California Resources Corp
For the period ended Mar 31, 2025. Filed May 7, 2025.
View on SEC.govAbout this filing
A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Mar 31, 2025 · Filed May 7, 2025
CRC$46.96+3.0%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2024-09-30; filed 2024-11-06.
0001609253-24-000119
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-03-31; filed 2025-05-07.
0001609253-25-000055
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
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Tables are not compared: 27 previous and 17 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (49)
Current report
In early 2025, OPEC+ began unwinding prior voluntary production cuts, which added approximately 400,000 barrels per day to the global oil market. This substantial supply boost contributed to a decline in global oil prices during the three months ended March 31, 2025. Concurrently, in March and April 2025, the United States expanded tariff rates on imported goods based on both country of origin and material type. These expanded tariff rates, if sustained, could increase both the cost of oilfield goods and delivery lead times. Collectively, these policy changes—OPEC+'s production increase and the U.S. tariffs—are introducing significant volatility to the oil and gas sector. For more information on the impact of tariffs on our business, see Regulatory Updates.
Current report
Regulation of Exploration and Production Activities
Current report
Well Permitting
Current report
During the three months ended March 31, 2025, we received well permits for 53 workovers and 21 sidetracks. This reflects a continuing improvement in the rate of issuance by CalGEM of permits for workovers and sidetracks.
Current report
During the three months ended March 31, 2025, we continued to experience delays from CalGEM with respect to obtaining new well and deepening permits for our operations and did not receive any permits for these activities. However, during this period, CalGEM issued one new well permit for an oil and gas exploration well in Santa Barbara County to another operator in the state. This permit was issued outside of Kern County and in reliance on an environmental impact analysis other than the Kern County Environmental Impact Report (EIR) to comply with CEQA.
Current report
We currently hold sufficient permits to maintain our existing capital program through 2025. We also have the requisite number of permits in hand to run one active drilling rig throughout 2026.
Current report
For further information regarding well permitting, see Part I, Items 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities, Well Permittingin our 2024 Annual Report.
Current report
Evolving Federal Energy and Climate Policies
Current report
Since January 2025, the current administration has issued numerous Executive Orders that aim to increase oil production and decrease commodity prices. For example, a “national energy emergency” was declared in early January 2025, which gave the executive branch more power to expedite approvals for energy resource infrastructure (including oil and gas). Additionally, the administration issued the “Unleashing American Energy” Executive Order which incorporated numerous provisions aimed at unburdening and removing impediments to the development of various domestic energy resources, such as oil and gas. More recently, in March 2025, an Executive Order was signed that, among other matters, directed the U.S. Attorney General to investigate certain state laws that may adversely impact the development of energy resources, including state laws relating to climate change, environmental, social and governance initiatives, and funds collecting carbon penalties and/or taxes. We cannot predict what impact these Executive Orders or others may ultimately have on commodity prices, our operations or California laws and regulations relating to oil and gas, CCUS and climate change. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Prices and Realizations below for information on our realized price.
Current report
In addition, in March and April 2025, the current administration implemented a substantial number of trade tariffs on all U.S. imports, including a new universal baseline reciprocal tariff of 10%, an additional country-specific reciprocal tariff for select trading partners and a tariff of 25% on imported steel and aluminum products. On April 10, 2025, the administration paused the additional country-specific tariffs for 90 days, until July 8, 2025, with the exception of the reciprocal tariff on China. While imports of oil, gas and refined products received exemptions from the tariffs, concerns that the measures could cause inflation, slow economic growth and intensify trade disputes have also placed downward pressure on oil prices. With negotiations and countermeasures still ongoing, the supply chain environment is fluid, and we expect price volatility to continue over the next few months. While we do not expect a significant and immediate impact on cost and availability of oilfield materials and supplies, these trade tariffs have the potential to significantly increase our operating and capital costs over the longer term.
Current report
Responsible Net Zero Goal
Current report
In May 2025, our Board of Directors adopted the following net zero emissions goal (Responsible Net Zero):
Current report
Our goal is to achieve at least an 80% reduction of absolute Scope 1 and 2 greenhouse gas emissions and neutralize the remaining Scope 1 and 2 emissions to achieve Net Zero by 2045. Our near-term ambition is to achieve a 20% reduction in the average carbon intensity of all CRC oil and gas production by 2035, thereby reducing our customers’ Scope 3 emissions. We are committed to responsibly producing energy in a manner consistent with the UN’s Sustainable Development Goals.
Current report
Our Responsible Net Zero goal is based on the following considerations:
Current report
•We use 2020 total Scope 1 and 2 GHG emissions (including those of Aera) as our baseline to measure progress towards our Responsible Net Zero goal. Our emissions are based on calculations reported to the California Air Resources Board (CARB).
Current report
•The term “neutralize” as it relates to Scope 1 GHG emissions refers to the planned use of either carbon offsets generated and claimed internally or carbon offsets purchased and claimed through the third party carbon market (including California’s Cap-and-Trade Program). For Scope 2 GHG emissions, the term “neutralize” refers to the use of contractual instruments such as renewable energy certificates or carbon offsets.
Current report
•The term “carbon offsets” refers to greenhouse gas emission reductions arising from third-party certified projects that remove, reduce, or avoid GHG emissions from the atmosphere.
Current report
•References to UN Sustainable Development Goals (UN SDGs) refer primarily to goals regarding income inequality, biodiversity, corruption, Scope 1 and 2 GHG emissions carbon intensity, fair labor and gender treatment. Operating a business consistent with UN SDGs is inherently a subjective determination regarding which UN SDGs to prioritize, how to weigh such matters against commercial considerations and to what extent a business activity promotes or is consistent with a given UN SDG.
Current report
•Future acquisitions and divestitures, as well as changes to methodology in accounting for carbon emissions or adjustments to historical carbon calculations as well as the use of third-party data or validation processes, could cause us to change our Responsible Net Zero goal.
Current report
•Assumptions, estimates, goals and similar statements and concepts regarding our Responsible Net Zero goal contain or assume forward looking statements within the meaning of federal securities laws and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. For a discussion of these risks and uncertainties, please refer to the Risk Factors and Forward-Looking Statements described in our Annual Report on our most recent Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the United States Securities and Exchange Commission.
Current report
Our Responsible Net Zero goal replaces our previously adopted Full Scope Net Zero goal. This change was primarily driven by the impact of the Aera Merger, which nearly doubled the size of our asset base and impacted the overall carbon intensity of our operations. The continuing lack of regulatory clarity around the measurement of Scope 3 GHG emissions (including the impact of carbon capture and sequestration in such calculations) also contributed to this change.
Current report
Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $814 million for the three months ended March 31, 2025, which is a decrease of $12 million compared to $826 million for the three months ended December 31, 2024.
Current report
The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended March 31, 2025 compared to the three months ended December 31, 2024:
Current report
Electricity revenue — Electricity revenue decreased by $17 million to $22 million for the three months ended March 31, 2025 compared to $39 million for the three months ended December 31, 2024. This decrease was primarily a result of lower seasonal pricing.
Current report
Non-energy operating costs— Non-energy operating costs for the three months ended March 31, 2025 were $209 million, which was a decrease of $16 million from $225 million for the three months ended December 31, 2024. The decrease was predominately a result of $7 million related to lower downhole maintenance, surface maintenance, and workover activity in addition to more favorable vendor pricing for the three months ended March 31, 2025 compared to the three months ended December 31, 2024.
Current report
General and administrative expenses — General and administrative (G&A) expenses were $72 million for the three months ended March 31, 2025 compared to $95 million for the three months ended December 31, 2024, which was a decrease of $23 million. The decrease was primarily a result of lower compensation-related expenses including stock-based compensation, bonus and retention awards and workforce reductions following the Aera Merger. See Liquidity and Capital Resources, Aera Integration below for additional information.
Current report
Compensation expense related to our bonus program decreased by $8 million for the three months ended March 31, 2025 compared to the three months ended December 31, 2024. This decrease was due to $4 million related to one-time retention awards granted in connection with the Aera Merger and $4 million related to the timing of the annual bonus accruals.
Current report
The non-cash portion of general and administrative expenses, comprised of equity-settled stock-based compensation, was approximately $6 million for both the three months ended March 31, 2025 and December 31, 2024.
Current report
Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) for the three months ended March 31, 2025 was $131 million compared to $142 million during the three months ended December 31, 2024. The decrease of $11 million was primarily the result of adjustments to the DD&A rate based on reserve estimates and fair value adjustments to the Aera assets in the three months ended March 31, 2025. See Part I, Item 1 – Financial Statements, Note 2 Aera Mergerfor information on the Aera assets and the purchase price allocation.
Current report
Measurement period adjustments — Measurement period adjustments relate to the initial accounting for assets acquired and liabilities assumed in the Aera Merger. The adjustments during the three months ended March 31, 2025 included adjustments to depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation. The adjustments during the three months ended December 31, 2024 related to accretion expense related to asset retirement obligations and depreciation, depletion and amortization expense resulting from changes to the initial purchase price allocation.
Current report
Other operating expenses, net — Other operating expenses, net decreased $18 million to $33 million for the three months ended March 31, 2025 compared to $51 million for the three months ended December 31, 2024. For the three months ended March 31, 2025 and December 31, 2024, other operating expenses, net includes the following:
Current report
Results of Our Oil and Natural Gas Operations
Current report
The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended March 31, 2025 or December 31, 2024.
Current report
(a)Gain on asset divestitures for the three months ended December 31, 2024 related to the sale of our Ventura assets.
Current report
Production, Prices, and Realizations
Current report
Oil — Brent prices were slightly higher for the three months ended March 31, 2025 compared to the three months ended December 31, 2024. The increase in Brent prices is due to a combination of early-quarter OPEC+ inaction in terms of returning barrels to the market and various geopolitical factors.
Current report
Natural Gas — Natural gas prices increased for the three months ended March 31, 2025 compared to the three months ended December 31, 2024 driven by colder-than-anticipated winter temperatures across most of the United States, resulting in strong demand and large storage withdrawals bringing storage inventories in line with historical norms.
Current report
Results of Our Carbon Management Segment
Current report
Our carbon management segment, which we refer to as Carbon TerraVault, primarily pursues the development of carbon capture and sequestration projects. We expect that our Carbon TerraVault CCS projects will inject CO 2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO 2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO 2 emissions. Our carbon management segment is in its early stages of development, and did not have any revenue for the three months ended March 31, 2025 or December 31, 2024. We define carbon management expense to be our direct operating costs to run our carbon management segment.
Current report
The following tables include results for our carbon management segment for the three months ended March 31, 2025 and December 31, 2024.
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Removed paragraphs (108)
Previous report
Aera Merger
Previous report
On July 1, 2024, we closed on transactions pursuant to the definitive agreement and plan of merger (Merger Agreement) to obtain all of the ownership interests in Aera Energy, LLC (Aera) (Aera Merger). In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the former Aera owners (Sellers). We also paid approximately $990 million in connection with the extinguishment of all of Aera's outstanding indebtedness using the proceeds from the issuance of our 2029 Senior Notes and cash on hand. For more information on the 2029 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 4 Debt.
Previous report
As of July 1, 2024, immediately following closing of the Aera Merger, our existing stockholders prior to the Aera Merger owned 76% of CRC and the Sellers owned 24% of CRC.
Previous report
In the three and nine months ended September 30, 2024, we recognized $30 million and $56 million, respectively, of transaction and integration costs related to the Aera Merger which are included in other operating expenses, net on our condensed consolidated statement of operations. See Part I, Item 1 – Financial Statements, Note 4 Debtfor information on financing costs related to the Aera Merger.
Previous report
Reorganization
Previous report
We expect to pay severance costs of approximately $25 million in the fourth quarter of 2024 and the remaining amounts throughout 2025 as the workforce reduction will be achieved in stages due to transition periods. See Part I, Item 1 – Financial Statements, Note 2 Aera Mergerfor information on the severance plan and Note 11 Pension and Postretirement Benefit Plansfor information on amendments to Aera's pension and postretirement benefit plans.
Previous report
Recent Debt Transactions
Previous report
2029 Senior Notes Follow-On Offering
Previous report
On August 22, 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 8.25% senior notes due 2029 (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 7.125% senior notes due 2026 (2026 Senior Notes) as described below. The 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.
Previous report
2026 Senior Note Repurchases
Previous report
Fifth Amendment to Revolving Credit Facility
Previous report
On November 1, 2024, we entered into a fifth amendment to our Revolving Credit Facility. For more information on recent amendments to our Revolving Credit Facility, see Part I, Item 1 – Financial Statements, Note 4 Debtand Note 15 Subsequent Events.
Previous report
Crude Oil
Previous report
We sell nearly all of our crude oil to California refiners. A majority of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.
Previous report
The prices paid by California refiners are typically based on local postings that are closely tied to Brent prices. International waterborne-based Brent prices are relevant because there is limited crude pipeline infrastructure available to transport crude over land from other parts of the United States into California. We believe that these limitations will continue to contribute to higher realized prices in California than most other U.S. oil markets for comparable grades.
Previous report
Natural Gas
Previous report
We sell all of our natural gas not used in our operations into the California market. A majority of these sales are made at index-based prices. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity between the market and producing areas. Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and from Canada. As a result, we typically obtain higher realizations relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas.
Previous report
In addition to selling natural gas, we also purchase natural gas for production of steam at our steamfloods and for power generation. As a result, the positive impact of higher natural gas prices is, absent impacts of gas cost hedging, largely offset by higher operating costs of our steamfloods and in our electricity generation expense, but higher prices have a net positive effect on our operating results when gas hedges are taken into account. See Part I, Item 1 – Financial Statements, Note 6 Derivativesfor more information on derivative contracts related to purchased natural gas.
Previous report
Following the Aera Merger, we have transportation contracts for up to (i) 101,750 MMBtu/d of long-haul (Rockies to California) gas transportation through September 2031 and (ii) approximately 220,000 MMBtu/d of localized system natural gas transportation through September 2026. These contracts to transport natural gas contain both fixed reservation fees and variable charges.
Previous report
NGLs
Previous report
NGL prices vary by liquid type and realizations are closely correlated to the different commodity prices to which they relate. Prices can also fluctuate due to the demand for certain chemical products (for which NGLs are used as feedstock) and due to infrastructure constraints and seasonality. Finally, our results are also affected by the performance of our natural gas-processing plants. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the remaining products as NGLs. The efficiency with which we extract liquids from the wet gas stream affects our production volumes and operating results. Our natural gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.
Previous report
We currently have a ship-or-pay pipeline transportation contract for approximately 6,100 barrels per day of NGLs through March 2026. Our contract to transport NGLs requires us to cash settle any shortfall between the contractual throughput minimums and volumes actually shipped. We have met all our throughput minimums under this contract for the periods presented.
Previous report
Delivery Commitments
Previous report
We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs, including additional delivery commitments obtained as part of the Aera Merger. As of September 30, 2024, we had the following delivery commitments as shown in the table below.
Previous report
We expect to fulfill our delivery commitments predominantly from our production and to a lesser extent from third party volumes acquired in connection with our marketing activities. We typically enter into index-based contracts with prices set at the time of delivery.
Previous report
Well Permitting Status
Previous report
CalGEM remains in the process of developing standard operating procedures for reviewing well permit applications and significant permitting delays may continue pending CalGEM’s completion of this process. An increase in approvals for workovers has continued through the third quarter of 2024. As of September 30, 2024, we have received 581 permits for workovers and 89 permits for sidetracks (including permits received by Aera) since the beginning of the year.
Previous report
During the second and third quarters of 2024, CalGEM issued 48 and 34 new well permits to other operators in the state, respectively. These permits were issued outside of Kern County or in reliance on an environmental impact analysis other than the Kern County Environmental Impact Report (EIR) to comply with CEQA. We are pursuing a similar strategy of seeking conditional use permits with respect to our Elk Hills, Buena Vista and Kern Front fields and Aera's Belridge field that would allow us to comply with CEQA requirements separate from the Kern County EIR. As discussed in the 2023 Annual Report, the Kern County EIR was legally challenged in 2020 and the use of the Kern County EIR is currently stayed and has been stayed through most of the litigation. For further information on the Kern County EIR, see Part I, Item IA – Risk Factors, 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 in our 2023 Annual Report. As a result, our ability to obtain these conditional use permits is uncertain and we may not be successful in obtaining such permits in a timely manner or at all.
Previous report
CCS Project Permitting Status
Previous report
On October 21, 2024, the Kern County Board of Supervisors approved the issuance of the conditional use permits and certified the Draft Recirculated Environmental Impact Report for our first carbon capture and storage project, Carbon TerraVault I. This approval follows a recommendation from the Kern County Planning Commission (Planning Commission) on September 12, 2024 that the Kern County Board of Supervisors take these actions.
Previous report
Setbacks and Senate Bill No. 1137
Previous report
California Senate Bill No. 1137 establishes 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public and separately imposes a number of potential impact analysis and mitigation and reporting requirements. The implementation of Senate Bill No. 1137 was stayed pending the outcome of a voter referendum to repeal the bill on the November 2024 ballot, but the referendum was withdrawn on June 27, 2024. However, on September 30, 2024, the Governor signed into law Assembly Bill No. 218, which extends the timeline for the implementation of certain initial and future monitoring and reporting requirements to July 1, 2026 and further delays compliance with certain other requirements of Senate Bill No. 1137 by up to three years. Assembly Bill. No. 218 does not modify the 3,200-foot setback requirements applicable to new drills, sidetracks or workovers.
Previous report
The majority of our production is in rural areas in the San Joaquin basin and is not affected by Senate Bill No. 1137. In addition to the writedown of reserves previously recorded in 2023, we continue to evaluate the location of projects near setback zones and believe any further reductions to the net present value of our proved undeveloped reserves as a result of the withdrawal of the voter referendum and the implementation of Senate Bill No. 1137 would be less than $14 million based on 2023 SEC prices (with an insignificant impact on our overall proved reserves).
Previous report
Recent Legislation
Previous report
On September 25, 2024, the following laws were enacted in the State of California:
Previous report
Assembly Bill 1866
Previous report
This law increases the annual fees operators must pay per idle well, depending on how long each well has been idle, and includes a new fee for those wells that have been idle for less than three years. In lieu of the annual fees, operators can instead file an eight year plan with the state to provide for the management and elimination of its idle wells. This law also increases the minimum percentages of idle wells that operators are required to eliminate each year. The rate at which idle wells must be eliminated varies depending on the number of an operator’s idle wells. Operators must prepare and submit a plan for the elimination of idle wells to CalGEM for approval. We have robust programs for managing and eliminating idle wells that in most cases meet or exceed the requirements of the new law. As a result, we do not expect this new law to have any meaningful impact on our current plans for eliminating idle wells or meaningfully increase fees associated with our idle wells.
Previous report
Assembly Bill 2716
Previous report
This law requires operators to plug “low production wells” located within the boundary of the Baldwin Hills Conservancy in Los Angeles within a certain timeframe or otherwise subjects operators to administrative penalties. A “low-production well” is a well that produced fewer than 15 barrels of oil a day during the past 12 months. We have limited operations and assets within the affected area. As a result, we expect that this law will have an insignificant impact on both our total production and proved reserves.
Previous report
Assembly Bill 3233 (AB 3233)
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Previous wording
Our operating results, and those of the oil and natural gas industry as a whole, are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Prices and Realizations below for information on our realized prices.
Current wording
Our operating results, and those of the oil and natural gas industry as a whole, are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices.
Previous wording
In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. For the three months ended September 30, 2024, following the Aera Merger, we sold approximately 8% of our production to this refinery. Following the closure of this facility, there will be four remaining major (greater than 75,000 barrels per day) petroleum refineries in Southern California and three remaining major petroleum refineries in Northern California. Due to the significant excess of refining capacity in California versus the quantity of crude oil produced locally, we do not expect the closure of this refinery to affect our ability to market our crude oil production, or to negatively impact our price realizations.
Current wording
In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. Additionally, in April 2025, Valero notified the California Energy Commission of its intent to idle, restructure, or cease refining operations at its Benicia refinery in the San Francisco Bay Area by the end of April 2026. Historically, we have sold a portion of our crude oil to these refineries. Assuming the Phillips 66 and Valero refineries both close, there will be six remaining major petroleum refineries in California, each of which have a refining capacity greater than 75,000 barrels per day. We expect California to collectively have 1.34 million barrels per day of remaining refining capacity, which is over four times the amount of crude oil produced in California in 2024. As a result of this and the considerable flexibility we have in marketing our production, we do not expect the closure of these refineries, should they occur, to affect our ability to market our crude oil production or to negatively impact our price realizations.
Previous wording
The following table presents our consolidated operating revenues for the three months ended September 30, 2024 and June 30, 2024:
Current wording
The following table presents our consolidated operating revenues for the periods indicated:
Previous wording
Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $290 million for the nine months ended September 30, 2024 compared to a net loss of $131 million for the nine months ended September 30, 2023. As of July 1, 2024, we recorded a liability of $336 million for Aera's outstanding Brent-based derivative contracts. Due to a decline in forward oil prices between July 1, 2024 and September 30, 2024, we recognized a non-cash commodity derivative gain for these Aera hedges during the nine months ended September 30, 2024. The net gain (loss) from commodity derivatives 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.
Current wording
Net gain (loss) from commodity derivatives –We report gains and losses on our derivative contracts related to our oil production and marketing activities in operating revenue. Net gain from commodity derivatives was $6 million for the three months ended March 31, 2025 compared to a net loss of $49 million for the three months ended December 31, 2024. The change primarily resulted from payments to settle commodity derivative contracts and the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
Previous wording
The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses and intercompany eliminations, for the three months ended September 30, 2024 and June 30, 2024 and the nine months ended September 30, 2024 and 2023. 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.
Current wording
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. These internal costs include an allocation of the direct costs to produce electricity at our Elk Hills power plant based on electricity consumption by our Elk Hills and nearby fields. There is no internal allocation of the costs to produce steam from the power plant used in oil and natural gas 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
Previous wording
Energy operating costs — Energy operating costs for the three months ended September 30, 2024 were $92 million, which was an increase of $51 million from $41 million for the three months ended June 30, 2024. This increase was primarily due to additional energy costs and purchase injectant used in the operation of the Aera fields. Our energy operating costs for the three months ended September 30, 2024 include $45 million related to Aera's fields following the completion of the Aera Merger on July 1, 2024. Excluding Aera, energy operating costs for the three months ended September 30, 2024 were higher than the three months ended June 30, 2024 as the result of higher natural gas prices. For more information on natural gas market prices, see Prices and Realizations above.
Current wording
Energy operating costs — Energy operating costs for the three months ended March 31, 2025 were $103 million, which was an increase of $9 million from $94 million for the three months ended December 31, 2024. This increase was primarily due to higher natural gas prices. We reduced the volume of natural gas used in our steamflood operations, resulting in a savings of $3 million in each of the three months ended March 31, 2025 and December 31, 2024. For more information on natural gas market prices, see Prices and Realizations below.
Previous wording
Changes in our stock price introduce volatility in our results of operations because we pay half of our cash-settled awards based on our stock price performance and we adjust our obligation for unvested cash-settled awards at the end of each reporting period. Equity-settled awards are not similarly adjusted for changes in our stock price.
Current wording
Cash-settled stock-based compensation expense decreased by $7 million primarily resulting from a lower expected payout on our incentive awards primarily due to a decline in our stock price at March 31, 2025 compared to December 31, 2024. Changes in our stock price introduce volatility in our results of operations because we pay cash-settled incentive awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period. Consequently, any future increases in our stock price will result in additional cash-settled stock-based compensation expense. Equity-settled stock-based compensation awards are not similarly adjusted for changes in our stock price.
Previous wording
Taxes other than on income — Taxes other than on income for the three months ended September 30, 2024 were $85 million, which is an increase of $46 million from $39 million for the three months ended June 30, 2024. This increase was due to higher production taxes, ad valorem taxes and greenhouse gas expense related to acquiring Aera's operations. Excluding Aera, taxes other than income for the three months ended September 30, 2024 increased from the three months ended June 30, 2024 primarily due to higher greenhouse gas expense, partially offset by lower ad valorem taxes.
Current wording
Taxes other than on income — Taxes other than on income for the three months ended March 31, 2025 were $70 million, which is a decrease of $10 million from $80 million for the three months ended December 31, 2024. This decrease was due to lower greenhouse gas expense.
Previous wording
Net gain from commodity derivatives — Net gain from commodity derivatives was $356 million for the three months ended September 30, 2024 compared to net gain of $5 million for the three months ended June 30, 2024 as shown in the table below. As of July 1, 2024, we recorded a liability of $336 million for Aera's outstanding Brent-based derivative contracts. Due to a decline in forward oil prices between July 1, 2024 and September 30, 2024, we recognized a non-cash commodity derivative gain for these Aera hedges during the three months ended September 30, 2024. The net gain from commodity derivatives 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.
Current wording
Net (gain) loss on natural gas purchased derivatives — Net gain from derivatives related to our purchase of natural gas was $6 million for the three months ended March 31, 2025 compared to a net loss of $19 million for the three months ended December 31, 2024. The change primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held, as well as the relationship between contract prices and the associated forward curves at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below:
Previous wording
Income taxes – The income tax benefit for the nine months ended September 30, 2024 was $132 million (representing an effective tax rate of 28%), compared to a provision of $105 million (representing an effective tax rate of 22%) for the nine months ended September 30, 2023. See Part I, Item 1 – Financial Statements, Note 7 Income Taxesfor more information on our effective tax rate.
Current wording
Income taxes – The income tax provision for the three months ended March 31, 2025 was $47 million (representing an effective tax rate of 29%), compared to a provision of $8 million (representing an effective tax rate of 20%) for the three months ended December 31, 2024. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our effective tax rate.
Previous wording
(a)Excludes unallocated general and administrative expenses.
Current wording
(b)Excludes unallocated general and administrative expenses.
Previous wording
(b)Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant.
Current wording
(c)Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant.
Previous wording
The following table sets forth our average net production volumes of oil, NGLs and natural gas produced per day in each of the California oil and natural gas basins in which we operated for the periods presented.
Current wording
The following table sets forth our average net production of oil, NGLs and natural gas sold per day in each of the California oil and natural gas 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.
Previous wording
Total daily net production sold increased by 69 Mboe/d from 76 Mboe/d for the three months ended June 30, 2024 to 145 Mboe/d during the three months ended September 30, 2024 primarily as a result of the Aera Merger. Our natural gas production also increased during the three months ended September 30, 2024 as compared to the three months ended June 30, 2024 by 2 MBoe/d as a result of fewer days of downtime at our Elk Hills power plant. Our PSCs, which are described below, positively impacted our net oil production by 1 MBoe/d in the three months ended September 30, 2024 compared to the three months ended June 30, 2024.
Current wording
Total average net production sold remained unchanged at 141 MBoe/d for the three months ended March 31, 2025 and December 31, 2024. Our PSCs, which are described below, positively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2025 compared to the three months ended December 31, 2024.
Previous wording
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. Operating costs, excluding effects of PSCs, is a non-GAAP measure which adjusts for excess costs attributable to PSCs for the periods presented in the tables below:
Current wording
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs.
Previous wording
The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX indexes for our oil and natural gas operations for the periods presented:
Current wording
The following table sets forth the average realized prices and price realizations on the commodities we sell as a percentage of average Brent, WTI and NYMEX indexes for our oil and natural gas operations for the periods presented:
Previous wording
NGLs — NGL prices for the three months ended September 30, 2024 decreased compared to the three months ended June 30, 2024 reflecting traditional seasonality and moved in tandem with crude oil prices. NGL prices for the nine months ended September 30, 2024 decreased compared to the nine months ended September 30, 2023 as growing North American crude and associated gas production continue to provide an ample supply of wet gas for processing.
Current wording
NGLs — Prices for natural gas liquids during the three months ended March 31, 2025 increased compared to the three months ended December 31, 2024, reflecting traditional seasonality and moving in tandem with crude oil prices.
Previous wording
Our primary sources of liquidity and capital resources are cash flows from operations, cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three months ended September 30, 2024 were for capital investments, repurchases of our common stock and dividends.
Current wording
Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three months ended March 31, 2025 were for debt reduction, repurchases of our common stock, payment of fixed dividends and capital investments.
Previous wording
(a)Excludes restricted cash of $28 million.
Current wording
(a)Excludes restricted cash of $15 million.
Previous wording
At current commodity prices and based upon our planned 2024 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and the indentures for our 2026 Senior Notes and our 2029 Senior Notes, (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
Current wording
At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and the indentures for our 7.125% senior notes due 2026 (2026 Senior Notes) and our 8.25% senior notes due 2029 (2029 Senior Notes), (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
Previous wording
The borrowing base under our Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.5 billion on November 1, 2024. The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitments from our lenders.
Current wording
The borrowing base under our Revolving Credit Facility is redetermined semi-annually and was reaffirmed at $1.5 billion on April 4, 2025. The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitments from our lenders, which is currently $1.15 billion. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debtin our 2024 Annual Report for additional information on the Revolving Credit Facility and related amendments.
Previous wording
In the three and nine months ended September 30, 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. In the three and nine months ended September 30, 2023, we repurchased $5 million in face value of our 2026 Senior Notes at par resulting in an insignificant extinguishment loss for the write-off of unamortized debt issuance costs.
Current wording
In February 2025, we redeemed $123 million of our 2026 Senior Notes at 100% of the principal amount of such notes, resulting in a loss on early extinguishment of debt in the amount of $1 million for the write-off of unamortized debt issuance costs.
Previous wording
Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.35 billion of our common stock through December 31, 2025. The aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $614 million, excluding commissions and excise taxes on repurchases, as of September 30, 2024. 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 and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The following is a summary of our share repurchases, which are held as treasury stock, for the periods presented:
Current wording
Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.35 billion of our common stock through December 31, 2025. As of March 31, 2025, the aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $457 million, excluding commissions and excise taxes on repurchases. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or contracts otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The following is a summary of our share repurchases, which are held as treasury stock, for the periods presented:
Previous wording
Note: The total value of shares purchased includes approximately $1 million in both the nine months ended September 30, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented.
Current wording
Note: The total value of shares purchased includes approximately $1 million in both the three months ended March 31, 2025 and 2024 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented. Total commissions and excise taxes paid since the inception of the program total $4 million.
Previous wording
Our Board of Directors declared the following cash dividends in each of the periods presented.
Current wording
We paid the following fixed cash dividends in each of the periods presented.
Previous wording
In addition to dividends declared, we paid$4 million of dividend equivalents related to stock-based compensation awards which were settled in thenine months ended September 30, 2024. The declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Since the adoption of our dividend policy in 2021, we have returned $231 million to shareholders through dividends (excluding dividend equivalents). For information regarding past dividends paid, see Cash Flow Analysis, Cash Flow Used in Financing Activities above.
Current wording
In addition to dividends declared, we paid$1 million and $4 million of dividend equivalents related to stock-based compensation awards which were settled in thethree months ended March 31, 2025 and 2024, respectively. The declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Since the adoption of our dividend policy in 2021, we have returned $302 million to shareholders through dividends (excluding dividend equivalents).
Previous wording
Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow. Our capital investment for the nine months ended September 30, 2024 was $167 million inclusive of $25 million for capital investment related to Aera's operations since the July 1, 2024 acquisition date. We expect our capital program for the remainder of 2024 to range between $85 million and $105 million under current permitting conditions. Of this amount, $77 million to $90 million is related to oil and natural gas development, $5 million to $10 million is for carbon management projects and $3 million to $5 million is for corporate and other. We expect to run a one rig program for the remainder of 2024 executing projects using existing permits. Refer to Regulatory Updates above for more information on permitting.
Current wording
Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow. Our capital investment for the three months ended March 31, 2025 was $55 million. We expect our 2025 capital program to remain at a range between $285 million and $335 million. Of this amount, $250 million to $280 million is related to our oil and natural gas segment, $20 million to $30 million is for our carbon management segment and $15 million to $25 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir. With respect to oil and natural gas development, we expect to run a two rig program in the second half of 2025 using existing permits in hand. Refer to Regulatory Updates above for more information on permitting. Refer to Part I, Item 1 – Financial Statements, Note 9 Segment Informationfor information on capital spend by segment.
Previous wording
Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the nine months ended September 30, 2024. See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of September 30, 2024 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debtin our 2023 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.
Current wording
Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2025. See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of March 31, 2025 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debtin our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.
Previous wording
In August 2024, management committed to a reduction in force as part of the integration process following the Aera Merger, which, when complete, will result in a 12% reduction in our combined company's employee headcount. We initiated this workforce reduction to align the size and composition of our workforce with expected future operating and capital plans and to capture synergies related to the Aera Merger. As a result, we recognized a charge of $27 million and $28 million in other operating expenses, net on the consolidated statement of operations for the three and nine months ended September 30, 2024, respectively, primarily related to severance benefits. See Part I, Item 1 – Financial Statements, Note 11 Pension and Postretirement Benefit Plansfor information on amendments to Aera’s pension and postretirement benefit plans in August 2024.
Current wording
In August 2024 and March 2025, management undertook a reduction in force as part of the integration process following the Aera Merger. After employee transition periods, the reduction in the combined employee headcount will be approximately 12%. We initiated this workforce reduction to align the size and composition of our workforce with expected future operating and capital plans. Employee severance and related costs are included in other operating expenses, net on our condensed consolidated statement of operations. We also amended Aera's pension and postretirement benefit plans in August 2024 resulting in a reduction of service cost, which is reported as a component of general and administrative expenses.
Previous wording
Cash flows from operating activities — For the nine months ended September 30, 2024, our operating cash flow decreased by $118 million to $404 million from $522 million in the same period in 2023. This decrease in operating cash flow was primarily driven by lower natural gas prices in California markets during the nine months ended September 30, 2024 compared to the same prior year period. Our average natural gas prices decreased $7.09 per Mcf from $9.85 per MMcf in the nine months ended September 30, 2023 to $2.76 per Mcf during the nine months ended September 30, 2024. Further, our natural gas production decreased by 22 MMcf/d from 136 MMcf/d in the nine months ended September 30, 2023 to 114 MMcf/d in the nine months ended September 30, 2024, also contributing to the decrease.
Current wording
Cash flows from operating activities — For the three months ended March 31, 2025, our operating cash flow increased by $99 million to $186 million from $87 million in the same period in 2024. This increase in operating cash flow was primarily driven by the Aera Merger on July 1, 2024.
Previous wording
(a)The total value of shares purchased reported on our statement of cash flows includes approximately $1 million in both the nine months ended September 30, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented.
Current wording
(a)The total value of shares purchased reported on our statement of cash flows includes approximately $1 million in both the three months ended March 31, 2025 and 2024 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented.
Previous wording
Divestitures, Acquisitions and Assets Held for Sale
Current wording
Divestitures and Assets Held for Sale
Previous wording
See Part I, Item 1 – Financial Statements, Note 7 Divestitures, Acquisitions and Assets Held for Sale for information on our divestitures and acquisitions during the three and nine months ended September 30, 2024 and 2023.
Current wording
See Part I, Item 1 – Financial Statements, Note 8 Divestitures and Assets Held for Sale for information on our divestitures and acquisitions during the three months ended March 31, 2025 and 2024.
Previous wording
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,” “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.
Current wording
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.
Previous wording
•government policy, war and political conditions and events, including the military conflicts in Israel, Lebanon, Ukraine and Yemen and the Red Sea;
Current wording
•government policy, war and political conditions and events, including the military conflicts in Israel, Lebanon, Ukraine and the Middle East;
Previous wording
•the ability to successfully execute integration efforts in connection with our merger with Aera Energy LLC, and achieve projected synergies and ensure that such synergies are sustainable;
Current wording
•the ability to successfully execute integration efforts in connection with the Aera Merger, and achieve projected synergies and ensure that such synergies are sustainable;
Previous wording
•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 business; (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;
Current wording
•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;
Previous wording
•the efforts of activists to delay prevent oil and gas activities or the development of our carbon management business through a variety of tactics, including litigation;
Current wording
•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;
Previous wording
•the impact of inflation on future expenses and changes generally in the prices of goods and services;
Current wording
•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;
Previous wording
•Our ability to maximize the value of our carbon management business and operate it on a stand alone basis;
Current wording
•our ability to maximize the value of our carbon management segment and operate it on a stand alone basis;
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Previous report — wording carried elsewhere
The amounts in the production tables below include volumes produced from Aera's operated and non-operated fields during the period from July 1, 2024 through September 30, 2024 and volumes from CRC's operated and non-operated fields for each of the periods presented.
Previous report — wording carried elsewhere
The following table sets forth our average net production of oil, NGLs and natural gas sold per day in each of the California oil and natural gas basins in which we operate for the periods presented.
Previous report — wording carried elsewhere
Income taxes – The income tax provision for the three months ended September 30, 2024 was $138 million (representing an effective tax rate of 29%), compared to a provision of $3 million (representing an effective tax rate of 27%) for the three months ended June 30, 2024.
Previous report — wording carried elsewhere
Note: See Productionfor volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.
Previous report — wording carried elsewhere
The following table presents our operating and non-operating expenses and income for the nine months ended September 30, 2024 and 2023:
Previous report — wording carried elsewhere
On August 2, 2024, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of$1.55, payable to shareholders in quarterly increments of$0.3875 per share of common stock. 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 and position.