California Resources Corp (CRC)

ITEM 7MANAGEMENT'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, 2023 (2023 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, 2023 compared to December 31, 2022.

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.

Certain prior period balances related to NGL marketing activities were reclassified to conform to our 2024 presentation. For the year ended December 31, 2023, we reclassified $6 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities and we reclassified $3 million related to NGL processing fees from other operating expenses, net to costs related to marketing of purchased commodities on our consolidated statement of operations.

Aera Merger

Following the closing of the Aera Merger, in August 2024 we initiated a workforce reduction to align the size and composition of our workforce with expected future operations and to capture synergies related to Aera Merger. As a result, we reduced our combined company's employee headcount by 12% and recognized a charge of $30 million in other operating expenses, net on the consolidated statement of operations for the year ended December 31, 2024, respectively, primarily related to severance benefits. We expect to pay the remaining severance costs through 2026 as the workforce reduction will be achieved in stages due to transition periods. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Aera Merger for information on the severance plan and Note 14 Pension and Postretirement Benefit Plans for information on amendments to Aera's pension and postretirement benefit plans.

Statement of Operations Analysis

Consolidated Results of Operations

Our consolidated results of operations include the results of Aera beginning July 1, 2024, the closing date of the Aera Merger. For more information on the Aera Merger, see Part I, Item 1 and 2 – Business and Properties, Business and Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Aera Merger. The Aera Merger and related transactions have significantly impacted the comparability of our financial results for 2024 and prior years.

For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the 2026 Senior Notes Indenture and 2029 Senior Notes Indenture, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 18 Condensed Consolidating Financial Information.

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Year Ended December 31, 2024 vs. 2023

The following table presents our total operating revenues:

Oil, natural gas and NGL sales – Oil, natural gas and NGL sales, excluding the impact of payments on settled commodity derivatives, were $2,537 million for the year ended December 31, 2024, which is an increase of $382 million from $2,155 million for the year ended December 31, 2023. This increase includes $915 million of oil, natural gas and NGL sales related to additional production from the Aera fields following the completion of the Aera Merger on July 1, 2024. Excluding the Aera fields, our oil, natural gas and NGL sales were lower in the year ended December 31, 2024 compared to the same prior year period primarily due to lower natural gas prices. The effect of cash settlements on our commodity derivative contracts are excluded from the table below.

Note: See Production, Prices and Realizations for volumes and realized prices by commodity type for each period.

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 $241 million for the year ended December 31, 2024 compared to a net loss of $12 million for the year ended December 31, 2023. 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:

Revenue from marketing of purchased commodities – Revenue from marketing of purchased commodities was $235 million during the year ended December 31, 2024, which is a decrease of $172 million from $407 million during the year ended December 31, 2023. The decrease was primarily a result of lower natural gas prices in 2024 compared to 2023, and was partially offset by higher sales of purchased crude oil in 2024 as compared to 2023. Our margin from marketing of purchased commodities was $42 million for the year ended December 31, 2024 compared to $183 million for the year ended December 31, 2023.

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Electricity sales – Electricity sales decreased by $52 million to $159 million during the year ended December 31, 2024 compared to $211 million for the year ended December 31, 2023. The decrease was predominantly due to lower electricity prices in 2024 as well as scheduled maintenance and unplanned downtime at our Elk Hills power plant.

The following table presents our consolidated operating expenses, non-operating expenses and income tax provision:

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, 2024 were $279 million, which was a decrease of $44 million from $323 million for the year ended December 31, 2023. Excluding $95 million related to the operation of the Aera fields, our energy operating costs for the year ended December 31, 2024 would have been $184 million. This decrease was primarily a result of lower natural gas prices in the year ended December 31, 2024 compared to the same prior year period. For more information on our natural gas market prices, see Segment Results of Oil and Natural Gas Operations, Production, Prices and Realizations below.

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Non-energy operating costs – Non-energy operating costs for the year ended December 31, 2024 were $671 million, which was an increase of $190 million from $481 million for the year ended December 31, 2023. The increase was predominately a result of costs related to the additional fields acquired in the Aera Merger. Non-energy operating costs for the year ended December 31, 2024 include $206 million related to Aera's operations. Excluding costs related to the Aera fields, non-energy operating costs for the year ended December 31, 2024 were lower than the prior year period as a result of lower costs for downhole and surface maintenance and more favorable vendor pricing for certain items in 2024 as a result of cost savings initiatives undertaken during 2023.

General and administrative expenses – General and administrative expenses were $321 million for the year ended December 31, 2024, which was an increase of $54 million from $267 million for the year ended December 31, 2023. The increase was primarily a result of an additional $73 million of expenses related to Aera for the period from July 1, 2024 through December 31, 2024. Excluding Aera, general and administrative expenses were lower in the year ended December 31, 2024 compared to the year ended December 31, 2023 as a result of reduced spending on information technology infrastructure and lower compensation-related expense, including stock-based compensation expense. Stock-based compensation awards are discussed further below.

Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.

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.

Stock-based compensation included in G&A expense is shown in the table below:

Depreciation, depletion and amortization – Depreciation, depletion and amortization increased $163 million to $388 million for the year ended December 31, 2024 from $225 million for the same prior year period. The increase was primarily the result of a higher net book value for our property, plant and equipment as a result of the Aera Merger.

Taxes other than on income – Taxes other than on income increased $77 million to $242 million for the year ended December 31, 2024 from $165 million for the year ended December 31, 2023. The increase was a result of higher greenhouse gas expense, production taxes and ad valorem taxes related to the Aera assets following the completion of the Aera Merger.

Costs related to marketing of purchased commodities – Costs related to marketing of purchased commodities was $193 million for the year ended December 31, 2024, which was a decrease of $31 million from $224 million for the year ended December 31, 2023 primarily due to lower natural gas prices. This decrease was partially offset by additional costs related to increased purchased crude oil used in certain of our marketing activities in 2024 as compared to 2023.

Electricity generation expense – Electricity generation expenses decreased to $40 million for the year ended December 31, 2024 from $103 million for the year ended December 31, 2023. The decrease of $63 million was predominantly a result of lower prices for natural gas used in electricity generation and scheduled maintenance and unplanned downtime at our Elk Hills power plant in the first half of 2024.

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Accretion expense – Accretion expense was $87 million for the year ended December 31, 2024, which was an increase of $41 million from $46 million for the year ended December 31, 2023. The increase was primarily due to asset retirement obligations assumed as of July 1, 2024 as part of the Aera Merger.

Net loss on natural gas purchase derivatives – Net loss on natural gas purchase derivatives was $30 million for the year ended December 31, 2024. For the same prior year period, we recognized a net loss of $8 million. 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. For more information on our derivatives, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives.

Other operating expenses, net – Other operating expenses, net were $183 million for the year ended December 31, 2024, which was an increase of $125 million from $58 million for the year ended December 31, 2023. The increase was primarily a result of transaction and integration costs for the Aera Merger of $57 million as well as additional expenses related to electricity purchased during the ongoing maintenance and downtime at our Elk Hills power plant of $50 million. We also incurred higher severance costs in the year ended December 31, 2024 as a result of the headcount reduction following the Aera Merger.

Gain on asset divestitures – Our gain on asset divestitures for the year ended December 31, 2024 was $11 million primarily related to the divestiture of non-core assets and the completion of our Ventura divestiture. Gain on asset divestitures for the year ended December 31, 2023 was $32 million primarily related to the divestiture of our non-operated portion of the Round Mountain Unit. 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 $87 million for the year ended December 31, 2024, which was an increase of $31 million from $56 million for the year ended December 31, 2023. The increase was predominately a result from higher interest expense from the issuance of our 2029 Senior Notes. In June 2024, we issued $600 million in aggregate principal amount of 8.25% senior notes due 2029 and in August 2024, we completed a follow-on offer of $300 million in aggregate principal amount for those notes. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt for information on financing costs related to the Aera Merger.

Income tax provision – The income tax provision for the year ended December 31, 2024 was $140 million (effective tax rate of 27%) compared to $184 million (effective tax rate of 25%) for the year ended December 31, 2023. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Income Taxes for more information for on our effective tax rate.

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Segment Results of Oil and Natural Gas Operations

The following tables include results for our oil and natural gas segment, excluding unallocated corporate expenses for the years ended December 31, 2024, 2023 and 2022. 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 Aera Merger.

(a)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)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. Net gain on asset divestitures for the year ended December 31, 2022 related to the sale of our 50% non-operated working interest in certain horizons within our Lost Hills field and the divestiture of certain Ventura basin assets. The table above excludes net gain on asset divestitures that were not related to the oil and natural gas segment.

(a)Excludes unallocated general and administrative expenses.

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

Energy costs in total and on a per Boe basis were lower in the year ended December 31, 2024 compared to the prior year period primarily as a result of lower natural gas prices. Energy operating costs were higher on a per Boe basis in for the year ended December 31, 2023 compared to the year ended December 31, 2022 as a result of lower production volumes in 2023.

We entered into commodity derivative contracts for purchased natural gas and acquired additional commodity derivative contracts in the Aera Merger. During the year ended December 31, 2024, we paid $32 million in settlement payments on natural gas derivatives, increasing our operating costs by $0.80 per Boe as shown in the table above. Our hedge contracts are part of our marketing function and hedge settlements are generally not allocated to our oil and gas segment. However, we believe it is useful to present our operating costs after hedge settlements.

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In 2025, our hedges for purchased natural gas approximate 62% of our expected fuel use in oil and natural gas operations. These 2025 hedges have a weighted average price of approximately $3.95 per MMBtu. Aera entered into natural gas hedges prior to our acquisition, and as of December 31, 2024, the weighted average price of those remaining hedges was $5.67 and we expect to pay $13 million to settle all of these contracts in the three months ended March 31, 2025.

Non-energy operating costs were higher in total and on a per Boe basis for the year ended December 31, 2024 compared to the year ended December 31, 2023 as a result of the Aera Merger on July 1, 2024. For the year ended December 31, 2024, non-energy operating costs related to the Aera fields predominately related to additional downhole maintenance and surface operations maintenance activity. Excluding the Aera fields, we had lower non-energy operating costs for the year ended December 31, 2024 compared to the same prior year period as a result of cost savings initiatives we implemented at the end of 2023. Non-energy operating costs were higher for the year ended December 31, 2023 compared to the year ended December 31, 2022 on a per Boe basis due to higher compensation-related costs for field personnel and additional downhole maintenance activity for the year ended December 31, 2023.

Operating costs, including the effects of natural gas hedges included settlement payments related to purchased natural gas used in our steamflood operations. We assumed natural gas hedges as part of the Aera Merger. We did not have settlements related to purchased natural gas hedges in the years ended December 31, 2023 and 2022.

Field depreciation, depletion and amortization increased for the year ended December 31, 2024 compared to the year ended December 31, 2023 as a result of the completion of the Aera Merger. Field depreciation, depletion and amortization increased for the year ended December 31, 2023 compared to the prior year primarily due to a change in our depreciation, depletion and amortization rates which are periodically adjusted to reflect an update of our SEC reserve estimates. Lower production volumes also contributed to the increase on a per Boe basis.

Field taxes other than on income were higher for the year ended December 31, 2024 compared to the same prior year period predominately as a result of the Aera Merger. Field taxes other than on income were higher in the year ended December 31, 2023 on a per Boe basis, due to lower production volumes compared to the year ended December 31, 2022.

Production, Prices and Realizations

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 December 31, 2024 and volumes from CRC's operated and non-operated fields for each of the periods presented.

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 years ended December 31, 2024, 2023 and 2022:

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The following table summarizes the changes to our total daily net production per day for the periods presented:

(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 unplanned downtime at our Elk Hills power plant for the year ended December 31, 2024. In the first quarter of 2022, we conducted routine maintenance at one of our gas processing facilities.

(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 Aera Merger for more information.

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Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Global commodity prices decreased during the year ended December 31, 2024 compared to the year ended December 31, 2023 predominately as a result of growing inventories and decreased demand. 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:

(a) Calculated as a percentage of Brent.

(b) Calculated as a percentage of WTI.

Oil — Brent and realized prices excluding derivative settlements were lower for the year ended December 31, 2024 compared to the same prior year period. The decrease was largely a result of slowing global demand growth, increased production from non-OPEC+ countries, and an awareness that OPEC+ could remove voluntary production cuts at any time. Including derivative settlements, our realized price increased for the year ended December 31, 2024 compared to the prior year.

NGLs — Prices for NGLs were flat for the year ended December 31, 2024 compared to the same prior year period. NGL prices fluctuate with the seasons of the year but remained flat between years as a result of increased supply, solid demand and an absence of protracted abnormal weather. California markets continued to carry a premium to other markets in 2024.

Natural Gas — Realized natural gas prices for the year ended December 31, 2024 were lower than those for the year ended December 31, 2023 influenced primarily by higher storage inventories, abundant import availability and a general lack of unseasonable weather. The year ended December 31, 2023 included a historic spike in pricing during the first quarter of 2023, while the rest of the year declined in price.

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Results of Our Carbon Management Segment

Our carbon management segment, which we refer to as Carbon TerraVault, pursues the development of carbon capture and sequestration projects. We expect that our Carbon TerraVault CCS projects will inject CO2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO2 emissions. Our carbon management segment is in its early stages of development, and did not have any revenue for the years ended December 31, 2024, 2023 or 2022. 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, 2024, 2023 and 2022.

(a)Asset impairment for the years ended December 31, 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 losses for the years ended December 31, 2024, 2023 and 2022 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, 2024, 2023 and 2022 are included in the table below.

Carbon management expenses increased in 2024 compared to 2023 as a result of additional compensation-related costs as more development work was performed and employee headcount increased as we realigned our job functions during our August 2024 reorganization. During the year ended December 31, 2024, we also incurred additional costs related to easements and pre-construction activities.

Liquidity and Capital Resources

Liquidity

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 year ended December 31, 2024 were for capital investments, repurchases of our outstanding debt and common stock, and payment of dividends.

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The following table summarizes our liquidity:

(a)Excludes restricted cash of $18 million.

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 repurchases 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 also intend to pursue financing options to further develop our carbon management segment. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.

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, 2024.

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, 2024 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, 2026 Senior Notes and 2029 Senior Notes. For more information regarding our Revolving Credit Facility, 2026 Senior Notes and 2029 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, 2024, we were in compliance with all of the covenants of our Revolving Credit Facility.

Recent Amendments

In 2024, we entered into the following amendments to our Revolving Credit Facility:

•February 2024 – we entered into a second amendment that, among other things, permit the incurrence of indebtedness under a bridge loan facility in connection with the Aera Merger.

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•March 2024 – we entered into a third amendment that facilitated certain matters with respect to the Aera Merger, including the postponement of the regular spring borrowing base redetermination until the fall of 2024 and certain other amendments.

•July 1, 2024 – we entered into a fourth amendment that increased the aggregate revolving commitments available under the Revolving Credit Facility from $630 million to $1.1 billion. This amendment also increased the borrowing base from $1.2 billion to $1.5 billion, among other matters.

•November 1, 2024 – we entered into a fifth amendment that, among other things, extended the maturity date of the Revolving Credit Facility to March 16, 2029 and amended the springing maturity provisions, increased our capacity to issue letters of credit by $50 million to $300 million, and increased the aggregate amount of revolving commitment by $50 million to $1,150 million. Our borrowing base of $1.5 billion is redetermined semi-annually and was re-affirmed in November 2024 as part of our recent amendment.

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, the 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 7.125% senior notes due 2026 (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

On January 20, 2021, we completed an offering of $600 million in aggregate principal amount of our 7.125% senior unsecured notes due 2026. The net proceeds of $587 million, after $13 million of debt issuance costs, were used to repay our outstanding indebtedness.

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. In the year ended December 31, 2023, we repurchased $55 million in face value of our 2026 Senior Notes at par resulting in an extinguishment loss of $1 million for the write-off of unamortized debt issuance costs.

Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 19 Subsequent Events for information on a recent repurchase of our 2026 Senior Notes.

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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, 2024:

(a)A significant number of stock-based compensation awards were settled in the first quarter of 2024. These awards were primarily granted in January 2021 following our emergence from bankruptcy.

We expect to issue additional shares during 2025 to Sellers in connection with the acquisition of Aera related to the settlement of pre-acquisition income taxes. Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Aera Merger for additional information.

Common Stock Issued as Part of the Aera Merger

In connection with the Aera Merger, as described in Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Aera Merger, on July 1, 2024 we entered into a registration rights agreement (Registration Rights Agreement) with the Sellers. In accordance with the Registration Rights Agreement, a total of 21,315,707 shares of common stock were registered pursuant to a registration statement on Form S-3 filed on August 5, 2024.

The Registration Rights Agreement contemplates that each Seller is subject to certain lock-up provisions whereby such Seller agreed not to transfer (1) any shares of common stock issued to such Seller to any non-affiliate until January 1, 2025; (2) more than one-third of the shares of common stock issued to such Seller to any non-affiliate until July 1, 2025; and (3) more than two-thirds of the shares of common stock issued to such Seller to any non-affiliate until January 1, 2026. The lock up provisions are subject to certain exceptions as more particularly described in the Registration Rights Agreement, included as an exhibit hereto.

Dividends

Dividends are payable to shareholders in quarterly increments, subject to the quarterly approval of our Board of Directors. 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 2, 2025, our Board of Directors declared a cash dividend of $0.3875 per share of common stock. The dividend is payable to shareholders of record at the close of business on March 10, 2025 and is expected to be paid on March 21, 2025.

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We paid the following cash dividends for each of the periods presented.

Share Repurchase Program

Our Board of Directors authorized a Share Repurchase Program to acquire up to $1.35 billion of our common stock through December 31, 2025. 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:

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, which was effective beginning in 2023. Commissions paid were not significant in all periods presented.

Uses of Cash

2025 Capital Program

We expect our total 2025 capital program to 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. 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 one rig program in the first half of 2025 and add an additional rig in the second half of 2025. We expect our capital program related to oil and natural gas development to be focused on projects for which we have permits in hand. 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.

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Carbon management segment – Our 2025 capital for carbon management projects includes approximately $16 million for the installation of carbon capture equipment at one of our gas processing facilities located at our Elk Hills field which we expect to be completed in 2025. 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 2025 capital program, our expected material uses of cash during 2025 include: (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 2026 Senior Notes and 2029 Senior Notes (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt)

•operating lease liabilities including our drilling rigs, 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 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, 2024.

(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.

(c)Purchase obligation relates to solar power purchase agreements.

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.

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Our operating cash flow for the year ended December 31, 2024 was $610 million, which was a decrease of $43 million, from $653 million for the year ended December 31, 2023. The decrease was primarily driven by lower average realized prices, including natural gas prices in California markets. In total, our production increased on 2024 compared to 2023 after the completion of the Aera Merger on July 1, 2024. For the year ended December 31, 2024 we produced 110 MBoe/d, which was an increase of 24 MBoe/d from 86 MBoe/d for the year ended December 31, 2023. However, our natural gas production volume decreased by 18 MMcf per day, from 135 MMcf/d during the year ended December 31, 2023 to 117 MMcf/d in the year ended December 31, 2024 predominantly as a result of scheduled maintenance and unplanned down time at our Elk Hills power plant as well as natural decline. Additionally, average realized price for natural gas decreased by $5.60 per Mcf from $8.59 Mcf for the year ended December 31, 2023 to $2.99 Mcf for the year ended December 31, 2024. Our average realized price for oil without the effects of derivative settlements decreased by $3.49 to $76.92 for the year ended December 31, 2024 compared to $80.41 for the same prior year period. We also earned a lower margin on our marketing activities in 2024 as compared to 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 payments from our oil derivative contracts decreased $208 million from $272 million for the year ended December 31, 2023 to $64 million for the year ended December 31, 2024. Shortly after emergence from bankruptcy in 2020, we entered into derivative positions through September 2023 to meet the requirements of our Revolving Credit Facility. At that time we entered into commodity derivative contracts during a low commodity price environment. In addition to these bankruptcy-related contracts being settled in the year ended December 31, 2023, the percentage of our production that we were required to hedge was lower in the year ended December 31, 2024 as compared to the same prior year period.

During 2024, primarily due to acquired natural gas derivative contracts in the Aera Merger, we paid higher settlements on related commodity price protection on purchased natural gas. For the year ended December 31, 2024, we made settlement payments of $32 million. We had no settlement payments on derivative contracts related to purchased natural gas derivatives during the year ended December 31, 2023. For more information on our existing hedges see, Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives.

Operating costs and general and administrative expenses increased in 2024 as compared to 2023 primarily due to the addition of Aera's operations on July 1, 2024. As a result, we had higher compensation-related costs and additional costs related to downhole maintenance activity, surface maintenance and purchase injectant. Excluding the Aera Merger, we realized cost savings related to strategic initiatives we implemented in the second half of 2023.

Cash flows from investing activities - The table below summarizes net cash used in investing activities:

(a)Includes capital investments of $234 million in our oil and natural gas segment and $12 million in our carbon management segment in 2024. Includes capital investments of $153 million in our oil and natural gas segment and $5 million in our carbon management segment in 2023.

The increase in cash used in investing activities primarily relates to the Aera Merger which closed on July 1, 2024. As a result of the Aera Merger, we also increased our capital program in 2024 compared to 2023. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Aera Merger for more information on the transaction.

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Proceeds from asset divestitures for the year ended December 31, 2024 primarily 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. Proceeds from asset divestitures for the year ended December 31, 2023 included the sale of our non-operated interest in the Round Mountain Unit. In each of the years ended December 31, 2024 and 2023, 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 from financing activities – The table below summarizes net cash used by financing activities:

(a)The total value of shares purchased reported on our statement of cash flows includes approximately $2 million and $1 million in the years ended December 31, 2024 and 2023, respectively, 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.

As noted above in Long-Term Debt, we completed an initial offering and a follow-on offering for our 2029 Senior Notes. In conjunction, we also repurchased $300 million face value of our 2026 Senior Notes. In the year ended December 31, 2023, we repurchased $55 million in face value of our 2026 Senior Notes. 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 2024 as compared to 2023. Additionally, our Board of Directors increased the quarterly dividend rate on our common stock during 2024. 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.

A significant number of stock-based compensation awards were settled in the first quarter of 2024. These awards were primarily granted in January 2021 following our emergence from bankruptcy. We withheld shares of common stock to satisfy the tax withholding obligations (shares cancelled for taxes). In addition to the $113 million of dividends paid in the year ended December 31, 2024, we paid $4 million of dividend equivalents accrued on our stock-based compensation awards. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 10 Stock-Based Compensation for more information on equity awards.

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 and Note 19 Subsequent Events for more information on our transactions.

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Seasonality

Certain of our operating costs and the prices for our products fluctuate throughout the year. For example, prices for natural gas (that we both market to third parties and purchase for use in our operations) tend to be higher in the winter and summer months. However, seasonality overall does not have a material effect on our earnings during the year.

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, punitive damages, 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, 2024 and 2023 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. We estimate our ongoing share of maintenance costs for the platforms could be approximately $5 million per year. Due to the preliminary stage of the process, no cost estimates to abandon the offshore platforms have been determined.

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:

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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, Lebanon, Ukraine and the Middle East;

•the ability to successfully execute integration efforts in connection with the Aera 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;

•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 on future expenses and changes generally in the prices of goods and services;

•changes in business strategy and our capital plan;

•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

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

•our ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;

•our ability to maximize the value of our carbon management segment and operate it on a stand alone basis;

•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; 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.

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ITEM 7MANAGEMENT'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 2022 Form 10-K for our analysis of the changes in our consolidated statements of operations and statements of cash flows for the year ended December 31, 2022 compared to December 31, 2021.

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 significant 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.

Pending Aera Merger

On February 7, 2024, we entered into a definitive agreement and plan of merger (Merger Agreement) to combine with Aera Energy, LLC (Aera) in an all-stock transaction (Aera Merger) with an effective date of January 1, 2024. Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production.

Pursuant to the Merger Agreement, we have agreed to issue 21,170,357 shares of common stock (subject to customary adjustments in the event of stock splits, dividend paid in stock and similar items) plus an additional number of shares determined by reference to the dividends declared by us having a record date between the effective date and closing as more fully described in the Merger Agreement. Under the terms of the Merger Agreement, we have also agreed to assume Aera’s outstanding long-term indebtedness of $950 million at closing. We expect to repay a significant portion of this indebtedness with cash on hand and borrowings under our Revolving Credit Facility. We intend to refinance the balance through one or more debt capital markets transactions and, only to the extent necessary, borrowings under a bridge loan facility provided by Citigroup Global Markets, Inc. (the Bank). Under the terms of our debt commitment letter with the Bank, it has committed, subject to satisfaction of customary conditions, to provide us with an unsecured 364-day bridge loan facility in an aggregate principal amount of $500 million (Bridge Loan Facility).

Closing of the Aera Merger is subject to certain conditions, including, among others, approval of the stock issuance by our stockholders, expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, prior authorization by the Federal Energy Regulatory Commission under Section 203 of the Federal Power Act and other customary closing conditions.

Upon completion of the transaction, we currently expect our existing stockholders to own approximately 77.1% of the combined company and the existing Aera owners to own approximately 22.9% of the combined company, on a fully diluted basis. The Aera Merger is expected to close in the second half of 2024. Post closing of the Aera Merger, and subject to Board approval, we expect to increase our quarterly dividend.

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Production, Prices and Realizations

The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the years ended December 31, 2023, 2022 and 2021:

The following table summarizes the changes to our total daily net production per day for the years ended December 31, 2023, 2022 and 2021:

(a)See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions for more information. Note that in 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)In the first quarter of 2022, we conducted routine maintenance at one of our gas processing facilities.

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Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Global commodity prices decreased during 2023 compared to 2022 predominately as a result of growing inventories and decreased demand. 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:

(a) Calculated as a percentage of Brent.

(b) Calculated as a percentage of WTI.

Oil — Brent and realized prices excluding derivative settlements were lower for the year ended December 31, 2023 compared to 2022. The decrease was largely a result of reduced risk premiums associated with the conflict in Ukraine, Russian crude and refined products demonstrating that they could make it to market regardless of sanctions, and increasing production from OPEC producers, such as Iran and Venezuela, and non-OPEC producers including Brazil and the United States.

NGLs — Prices for NGLs decreased in the year ended December 31, 2023 compared to 2022 as prices for competing and complementary products (natural gas, crude oil) declined and as NGL production and inventories grew to near-record levels. For the year ended December 31, 2023, California continue to benefit from premium pricing for NGLs compared to other North American locations.

Natural Gas — California natural gas realized prices for the year ended December 31, 2023 averaged slightly above those for 2022 driven largely by price spikes during the first quarter of 2023 which exceeded the price spike experienced in the fourth quarter of 2022. For the balance of 2023, prices in California and nationally were generally weaker as storage inventories were restored and as North American natural gas production grew.

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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 8 Divestitures and Acquisitions and Note 17 Subsequent Events for more information on our transactions.

Carbon TerraVault Joint Venture

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on our Carbon TerraVault JV.

Supply Chain and Inflation

We continued to experience relatively flat pricing from our suppliers in 2023 as compared to 2022. We have long term vendor relationships and have taken measures to limit the effects of inflation by entering into contracts for a significant majority of our materials and services with terms of one to three years. We have not experienced any meaningful inflation in connection with recent contract renewals. Overall, we continue to expect minimal inflation in our supply chain.

Seasonality

Certain of our operating costs and the prices for our products fluctuate throughout the year. For example, prices for natural gas (that we both sell and purchase for use in our operations) tend to be higher in the winter and summer months. However, seasonality overall does not have a material effect on our earnings during the year.

Income Taxes

All of our income is earned from domestic operations and is subject to tax in the United States. The following table sets forth our effective tax rate on income from continuing operations:

During the year ended December 31, 2023, we released a valuation allowance of $35 million for a portion of the tax loss on the sale of our Lost Hills assets after we jointly agreed to amend the original tax treatment with the buyer. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions for more information on the Lost Hills transaction. This valuation allowance was initially recorded during the year ended December 31, 2022 for the realizability of a capital loss on the sale of Lost Hills, the deductibility of which was limited. During the year ended December 31, 2021, we released all of our valuation allowance recorded against our net deferred tax assets given our anticipated future earnings trend at that time.

During the years ended December 31, 2022 and 2021, we recognized a tax benefit for tax credits related to our oil and gas operations. The tax benefit of these credits is presented as changes in tax attributes in our effective tax rate reconciliations.

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Management expects to realize the recorded deferred tax assets primarily through future operating income and reversal of taxable temporary differences. The amount of deferred tax assets considered realizable is not assured and could be adjusted if estimates change or three-years of cumulative income is no longer present. For additional information on tax-related items see Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Income Taxes.

Statement of Operations Analysis

Results of Oil and Natural Gas Operations

The following table includes key operating data for our oil and natural gas operations, excluding unallocated corporate expenses, on a per Boe basis for the years ended December 31, 2023, 2022 and 2021. 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.

(a)Excludes unallocated general and administrative expenses.

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

Energy operating costs were higher on a per Boe basis in 2023 compared to 2022 as a result of lower production volumes in 2023. Non-energy operating costs were higher in 2023 compared to 2022 on a per Boe basis due to higher compensation-related costs for field personnel and additional downhole maintenance activity in 2023.

Field depreciation, depletion and amortization increased in 2023 compared to the prior year primarily due to a change in our depreciation, depletion and amortization rates which are periodically adjusted to reflect an update of our SEC reserve estimates. Lower production volumes also contributed to the increase on a per Boe basis.

Field taxes other than on income were higher in 2023 on a per Boe basis due to lower production volumes in 2023.

Results of Operations

Reorganization

In 2023, we undertook initiatives to streamline our operations and implemented organizational changes. These actions were taken to better align our resources to our strategic priorities and improve operational efficiency. As a result, we recognized a severance charge of $10 million, included in other operating expenses, net on our consolidated statement of operations. In 2024, we expect to realize annualized savings of approximately $65 million, of which $50 million relates to operating costs, $10 million relates to general and administrative expenses, with the remainder reducing exploration expense and capital. Our results of operations for 2023 reflect partial savings achieved as actions were taken beginning in August 2023 and continuing into the fourth quarter.

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Year Ended December 31, 2023 vs. 2022

The following table presents our total operating revenues:

Oil, natural gas and NGL sales – Oil, natural gas and NGL sales, excluding the impact of payments on settled commodity derivatives, were $2,155 million for the year ended December 31, 2023, which is a decrease of $488 million, compared to $2,643 million for the year ended December 31, 2022. The decrease was primarily due to lower realized prices and lower production volumes for oil, as shown in the following table:

Note: See Production, Prices and Realizations for volumes and realized prices by commodity type for each period.

The effect of cash settlements on our commodity derivative contracts is not included in oil, natural gas and NGL sales. Including the effect of net payments on settled commodity derivatives described below, our oil, natural gas and NGL sales decreased by $22 million in 2023 compared to the same prior year period.

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Net loss from commodity derivatives – Net loss from commodity derivatives was $12 million for the year ended December 31, 2023 compared to a net loss of $551 million for the year ended December 31, 2022. The change primarily resulted from payments on settled commodity derivatives 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:

Marketing of purchased natural gas – Marketing of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Marketing of purchased natural gas was $401 million during the year ended December 31, 2023, which is an increase of $87 million from $314 million during the same prior year period. The increase was primarily a result of higher prices for natural gas acquired for resale during 2023, which included unusually high prices in January 2023. As part of our marketing activities, we may purchase gas in producing areas and transport for sales to areas with higher pricing. Revenues from marketing purchased natural gas net of related purchased natural gas marketing expense increased $139 million from $180 million in 2023 compared to $41 million in 2022.

Electricity sales – Electricity sales decreased by $50 million to $211 million during the year ended December 31, 2023 compared to $261 million for the year ended December 31, 2022. The decrease was predominantly due to lower electricity prices in 2023.

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The following table presents our consolidated operating expenses, non-operating expenses and income tax provision:

Non-energy operating costs – Non-energy operating costs for the year ended December 31, 2023 were $481 million, which was an increase of $36 million from $445 million for the year ended December 31, 2022. The increase was primarily a result of higher compensation-related costs for field personnel as well as additional downhole and surface maintenance activity in 2023 as compared to 2022. These increases were partially offset by savings due to actions taken in August 2023 to align our workforce with our current activity level.

General and administrative expenses – General and administrative expenses were $267 million for the year ended December 31, 2023, which was an increase of $45 million from $222 million for the year ended December 31, 2022. The increase in G&A expenses was primarily attributable to compensation-related expenses (including stock-based compensation awards discussed further below) and higher spending to streamline our information technology infrastructure.

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The table below shows the portion of total G&A expenses which are directly attributable to our carbon management business:

Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest or vest ratably over a two- or three-year period. Grants of equity-settled awards in 2021 contemplated that no corresponding grants would be made in 2022. We resumed granting equity-settled awards in 2023. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.

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.

Stock-based compensation included in G&A expense is shown in the table below:

Depreciation, depletion and amortization – Depreciation, depletion and amortization increased $27 million to $225 million for the year ended December 31, 2023 from $198 million for the same prior year period. The increase was primarily the result of a change in our DD&A rates which are periodically adjusted to reflect an update of our SEC reserve estimates.

Purchased natural gas marketing expense – Purchased natural gas marketing expense was $221 million for the year ended December 31, 2023, which was a decrease of $52 million from $273 million for the year ended December 31, 2022 primarily due to lower natural gas prices partially offset by higher volumes.

Electricity generation expense – Electricity generation expenses decreased to $103 million for the year ended December 31, 2023 from $167 million for the year ended December 31, 2022. The decrease of $64 million was predominantly a result of lower prices for natural gas used in electricity generation.

Transportation costs – Transportation costs were $67 million for the year ended December 31, 2023 which was an increase of $17 million from $50 million for the prior year. The increase in transportation costs was predominately a result of higher rates for natural gas transportation capacity in 2023.

Carbon management business expenses – Carbon management business (CMB) expenses were $37 million for the year ended December 31, 2023 compared to $14 million for the year ended December 31, 2022. CMB expenses include lease cost for sequestration easements, advocacy, and other related costs. The increase in 2023 was predominately a result of higher costs for CO2 injection easements and additional costs to evaluate certain projects.

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Other operating expenses, net – Other operating expenses, net was $66 million for the year ended December 31, 2023, which was an increase of $32 million from $34 million for the year ended December 31, 2022. The increase was primarily a result of one-time costs, such as severance, that we incurred in connection with our reorganization in 2023.

Net gain on asset divestitures – Our net gain on asset divestitures for the year ended December 31, 2023 was $32 million primarily related the divestiture of our non-operated portion of the Round Mountain Unit. Net gain on asset divestitures for the year ended December 31, 2022 was $59 million primarily related to the sale of our 50% non-operated working interest in certain horizons within our Lost Hills field and certain Ventura basin assets. For more information on our asset divestitures, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions.

Income tax provision – The income tax provision for the year ended December 31, 2023 was $184 million (effective tax rate of 25%) compared to $237 million (effective tax rate of 31%) for the year ended December 31, 2022. The income tax provision for 2022 included a provision for a valuation allowance recorded in the first quarter of 2022 at the time of our Lost Hills divestiture. This valuation allowance was released in the first quarter of 2023 after the Purchase and Sale Agreement was amended. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Income Taxes for more information on a valuation allowance related to our Lost Hills divestiture.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity and capital resources are cash flows from our oil and gas operations, cash and cash equivalents on hand and available borrowing capacity under our Revolving Credit Facility which matures July 31, 2027. We generated additional cash flow of $32 million from divestitures of non-core assets during 2023. Our primary uses of operating cash flow for 2023 were for capital investments, repurchases of our outstanding debt and common stock and payment of dividends.

The following table summarizes our liquidity:

As of December 31, 2023, we were in compliance with all of the covenants of our Revolving Credit Facility. For a description of the terms and conditions of our long-term debt, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt.

Under the terms of the Merger Agreement, we are obligated to assume the Aera indebtedness at Closing. We have entered into a debt commitment letter with the Bank pursuant to which the Bank has committed, subject to satisfaction of customary conditions, to provide us with the Bridge Loan Facility. We currently intend to refinance the Aera indebtedness with cash on hand, borrowings under our revolving credit facility, through one or more debt capital markets transactions and, only to the extent necessary, borrowings under the Bridge Loan Facility. See Part I, Item 1 and 2 – Business and Properties, Recent Developments – Pending Aera Merger for more information on the Aera Merger and Bridge Loan Facility.

In connection with the Merger Agreement, on February 9, 2024, we entered into a second amendment to our Revolving Credit Facility to, among other things, permit us to incur indebtedness under the Bridge Loan Facility.

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We are also currently in the process of seeking additional commitments from existing and new lenders to expand our borrowing capacity under the Revolving Credit Facility, as well as seeking an increase to our existing borrowing base of $1.2 billion. These changes would only become effective upon closing of the Aera Merger and there can be no assurances that we will be successful in these efforts.

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 Senior Notes indenture, (iii) repurchase outstanding indebtedness, (iv) advance carbon management activities, or (iv) 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.

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, 2023.

Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 6 Derivatives for more information on our open derivative contracts as of December 31, 2023 and Note 4 Debt for more information on the hedging requirements included in our Revolving Credit Facility.

Dividend Policy

Dividends are payable to shareholders in quarterly increments, subject to the quarterly approval of our Board of Directors. 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. Post closing of the Aera Merger, and subject to Board approval, we expect to increase our fixed quarterly dividend.

On February 27, 2024, our Board of Directors declared a cash dividend of $0.31 per share of common stock. The dividend is payable to shareholders of record at the close of business on March 6, 2024 and is expected to be paid on March 18, 2024.

We paid the following cash dividends for each of the periods presented.

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Share Repurchase Program

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. This includes a recent increase of $250 million and extension approved by our Board of Directors on February 6, 2024. The repurchases may be affected 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. Shares repurchased are held as treasury stock.

Note: The total value of shares purchased includes approximately $1 million related to excise taxes on share repurchases, which was effective beginning in 2023. Commissions paid were not significant in all periods presented.

Uses of Cash

2024 Capital Program

We expect our total 2024 capital program to range between $300 million and $340 million assuming normal operating conditions and excluding any additional capital which could result from the Aera Merger. Of this amount, $250 million to $260 million is related to oil and natural gas development, $30 million to $40 million is related to maintenance of one of our gas processing facilities and a power plant, both of which are located in our Elk Hills field, $15 million to $25 million is for carbon management projects and $5 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 3 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on our joint venture with Brookfield.

With respect to oil and natural gas development, we expect to run a one rig program executing projects using existing permits through 2024. Subject to the availability of well permits, we expect to increase to a four rig program in the second half of 2024. The actual amount of spending related to oil and gas development under our 2024 capital program will depend on a variety of factors. In particular, the rate and amount of this spending depends on our ability to obtain new well permits in the second half of the year. If we are not able to obtain these permits, we could reduce our capital program by up to $100 million. For more information on permitting, refer to Part I, Item 1 and 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulations of Exploration and Production Activities.

Our 2024 capital for carbon management projects includes approximately $5 million for the installation of carbon capture equipment at one of our gas processing facilities located at our Elk Hills field. We expect the total capital investment for this project will range between $15 million to $20 million and work will be completed in 2025. 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 Business.

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Other Uses of Cash

Other than our 2024 capital program, our expected material uses of cash during 2024 include: (1) dividends, share repurchases and payroll taxes on equity-settled compensation awards; (2) settlements on commodity derivative contracts; (3) income taxes; (4) settlement of asset retirement obligations; (5) operating expenses; (6) costs related to advancing our carbon management activities not included in our capital program, such as employee costs and engineering studies; (7) transaction costs related to the Aera merger, including advisory, legal and other third-party fees and (8) to the extent necessary, repayment of Aera indebtedness.

Our long-term material uses of cash include the following:

•repayment of principal and interest on our Senior Notes (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt)

•operating lease liabilities including our drilling rigs, commercial office space, fleet vehicles, easements and certain facilities (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 12 Leases)

•obligations associated with our defined benefit and post-employment benefit plans (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 13 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)

•a contingent liability for put and call features related to Brookfield's initial investment in the Carbon TerraVault JV (see Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Investment in Unconsolidated Subsidiary and Related Party Transactions)

We also 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 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, 2023.

(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.

Our operating cash flow for the year ended December 31, 2023 was $653 million, which was a decrease of $37 million, or 5%, from $690 million for the year ended December 31, 2022. The decrease was largely driven by lower revenue from sales of the commodities we produce. Our production volume decreased by 5 MBoe per day, or 5%, from 91 MMBoe/d in 2022 to 86 MMBoe/d in 2023 predominantly as a result of natural decline. Additionally, average realized Brent prices decreased by $17.85 per barrel from $98.26 per barrel in 2022 to $80.41 per barrel in 2023. We earned a higher margin on our marketing activities in 2023 as compared to the same prior year period. For more information on our production and price changes, see Production and Price above.

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Settlement payments from derivative contracts decreased $466 million from $738 million in 2022 to $272 million in 2023. Shortly after emergence from bankruptcy in 2020, we entered into derivative positions through September 2023 to meet the requirements of our Revolving Credit Facility at that time during a low commodity price environment. The percentage of our production that we were required to hedge was lower in 2023 as compared to 2022. The tenor of these derivative positions ended in the third quarter of 2023 which, along with lower Brent prices between comparative periods, resulted in a decrease in settlement payments in 2023 as compared to 2022. For more information on our existing hedges see, Part II, Item 8 – Financial Statements and Supplementary Data, Note 6 Derivatives.

Cash paid for income taxes in 2023 was $121 million compared to $20 million in 2022. Our U.S. federal taxable income increased in 2023 primarily due to the use of remaining net operating loss and tax credit carryforwards available to us along with realizing tax losses on asset divestitures in 2022. Additionally, our capital program was lower in 2023 as compared to 2022 which, along with the phase out of bonus depreciation, also contributed to the increase. We continue to pay minimum taxes in California.

Operating costs and general and administrative expenses increased in 2023 as compared to 2022 primarily due to higher compensation related costs and additional downhole maintenance activity. In August 2023, we took actions to better align our resources to strategic priorities and improve operational efficiency. We realized approximately $15 million of savings in 2023 and expect these actions to result in approximately $65 million of savings in operating and overhead costs on an annualized basis.

Cash flows from investing activities - The table below summarizes net cash used in investing activities:

The decrease in cash used in investing activities primarily relates to a lower capital program in 2023 as compared to 2022. In the first quarter of 2023, we reduced our capital program to one rig to align with available permits. In comparison, we averaged 4 drilling rigs in 2022. Proceeds from asset divestitures for the year ended December 31, 2023 included the sale of our non-operated interest in the Round Mountain Unit. Proceeds from divestitures for the year ended December 31, 2022 included the sale of our 50% non-operated working interest in certain horizons within our Lost Hills field, certain of our Ventura basin assets and our commercial office building in Bakersfield, California. In each of the years ended December 31, 2023 and 2022, the acquisitions shown in the table above related to purchasing storage reservoirs for our carbon management business. Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions for more information on our divestitures and acquisitions.

Cash flows from financing activities – The table below summarizes net cash used by financing activities:

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Cash used for repurchases of our common stock under our Share Repurchase Program decreased in 2023 as compared to 2022 in part due to adding optionality to repurchase long-term debt. Additionally, our Board of Directors increased the quarterly dividend rate on our common stock during 2023. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 10 Stockholders' Equity for more information on our Share Repurchase Program and cash dividends and Note 4 Debt for more information on repurchases of our Senior Notes.

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, punitive damages, 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, 2023 and 2022 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 now appealing the order from BSEE. We expect to enter into a cost sharing agreement with former lessees in the first half of 2024, and expect to pay $12 million to $15 million for our share of the maintenance costs at that time. We will share in on-going maintenance costs during the pendency of the challenge to the BSEE order.

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 5 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:

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