California Resources Corp 10-Q

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations General We are an independent oil and natural gas exploration and production and carbon management company operating properties exclusively within California. We are committed to energy transition and have some of the lowest carbon intensity production in the United States. We are in the early stages of permitting several carbon capture and storage (CCS) projects in California. Our carbon management business, which we refer to as Carbon TerraVault, is expected to build, install, operate and maintain CO 2 capture equipment, transportation assets and storage facilities in California. In August 2022, we entered into a joint venture with BGTF Sierra Aggregator LLC (Brookfield) to pursue carbon management and storage activities (Carbon TerraVault JV) . For more information about the risks involved in our carbon capture projects, see Part I, Item 1A – Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2023 (2023 Annual Report) and for more information on the Carbon TerraVault JV, see Part I, Item 1 – Financial Statements, Note 3 Investment in Unconsolidated Subsidiary and Related Party Transactions. Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its consolidated subsidiaries. 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. Upon closing, Aera's $950 million outstanding long-term debt will become due as a result of a change in control provision within their legacy debt agreement. 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 (HSR Act), prior authorization by the Federal Energy Regulatory Commission under Section 203 of the Federal Power Act and other customary closing conditions. The required waiting period under the HSR Act expired on March 25, 2024. Upon completion of the transaction, we currently expect our existing stockholders to own approximately 77% of the combined company and the existing Aera owners to own approximately 23% of the combined company, on a fully diluted basis. The Aera Merger is expected to close around mid-year 2024. Post closing of the Aera Merger, and subject to Board approval, we expect to increase our quarterly dividend. In the three months ended March 31, 2024, we incurred $13 million of transaction and integration costs related to the Aera Merger included in other operating expenses, net on our condensed consolidated statement of operations. We also incurred $8 million in financing fees, which is included in other current assets, net on our condensed consolidated balance sheet as of March 31, 2024. 25 Business Environment and Industry Outlook Commodity Prices Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Prices and Realizations below for information on our realized prices. The following table presents the average daily benchmark prices for oil and natural gas during the periods presented: Three months ended March 31, 2024 December 31, 2023 Brent oil ($/Bbl) $ 81.84 $ 82.69 WTI oil ($/Bbl) $ 76.96 $ 78.32 NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price $ 2.24 $ 2.88 Regulatory Updates Well Permits CalGEM remains in the process of developing standard operating procedures for reviewing well permit applications that it commenced in the second half of 2023. Significant permitting delays continue pending CalGEM’s completion of this process. An increase in permits approvals for workovers has continued through the first quarter of 2024, and substantially increased in April 2024. As of May 6, 2024, we have received 73 permits for workovers since the beginning of the year. As of May 6, 2024, we have also received 8 permits for deepenings and 1 permit for a sidetrack for wells in our Wilmington field. With only a few exceptions, there continues to be no new drill permits issued in the state. Kern County EIR Litigation On March 7, 2024, the California Court of Appeals, Fifth Appellate District (Court of Appeals), issued its ruling on the six challenges to Kern County’s Supplemental Recirculated Environmental Impact Report (SREIR) for Kern County Zoning Ordinance G-8992 (Ordinance). In its disposition, the Court of Appeals ordered the Trial Court to enter a modified judgement and fourth preemptory writ directing Kern County (i) to set aside approval of the Ordinance, SREIR and related findings of facts and statements of overriding considerations; and (ii) not to present a revised Ordinance for approval until Kern County has (a) prepared a revised SREIR that corrects CEQA violations relating to the (1) rejection of agricultural conservation easements as a form of partial mitigation for the conversion of agricultural land, (2) assessment of cancer risks associated with the drilling of multiple wells near sensitive receptors and (3) analysis of water supply impacts; and (b) circulated the revised SREIR for public review and comment, prepared responses to comments, and certified the revised SREIR. On March 22, 2024, Kern County released a notice of preparation of the Second Supplemental Revised Environmental Impact Report (SSREIR). We expect that Kern County will prepare a draft SSREIR, circulate it for public comments and thereafter certify the SSREIR and approve the Ordinance. After that, the Trial Court would then consider whether to lift the stay. If that occurs, well permitting could resume assuming no further challenges to the SSREIR. As a result of the ruling of the Court of Appeals in the Kern County EIR litigation and current lack of permits with respect to our Kern County properties, we currently plan to operate one drilling rig within Kern County in 2024. We have sufficient permits in hand to keep that rig active through the end of 2025. 26 CCS Project Permitting In December 2023, Kern County released a draft EIR prepared in connection with our application for conditional use permits for our CTV I CCS project. The project was originally scheduled to be considered by the Kern County Planning Commission on March 28th; however, based on comments received the Planning Commission required further environmental review before it can consider the project and the draft EIR. The Planning Commission recommended that the consideration of applicable changes to the zoning ordinance and certification of the EIR be continued to the August 22, 2024 Planning Commission hearing, at which the Planning Commission will decide whether to recommend the adoption of the changes to the zoning ordinance and certification of the EIR to the Board of Supervisors. The Board of Supervisors meeting is expected to occur in or around September or October. Low Carbon Fuel Standard On February 14, 2024, the California Air Resources Board (CARB) announced that it was postponing the previously scheduled March 21, 2024, public hearing regarding the proposed amendments to the LCFS Regulation released on December 19, 2023. Due to continuous substantial public feedback on the proposed amendments, CARB intends to release revised proposed amendments for public review and comment, to be followed by a public hearing. The release of the revised proposed amendments is pending. These revisions may impact the eligibility of certain of our CCS projects for LCFS credits. Results of Oil and Gas Operations Production The following table sets forth our average net production of oil, NGLs and natural gas per day in each of the California oil and natural gas basins in which we operated for the periods presented. Three months ended March 31, 2024 December 31, 2023 Oil (MBbl/d) San Joaquin Basin 30 32 Los Angeles Basin 18 18 Total 48 50 NGLs (MBbl/d) San Joaquin Basin 11 11 Total 11 11 Natural gas (MMcf/d) San Joaquin Basin 90 114 Los Angeles Basin 1 1 Sacramento Basin 14 15 Total 105 130 Total Net Production (MBoe/d) 76 83 27 Total daily net production for the three months ended March 31, 2024 compared to the three months ended December 31, 2023 decreased by 7 MBoe/d predominately due to scheduled plant downtime during the first quarter of 2024. The decrease in production also reflects natural production decline as well as the divestiture of our share of a non-operated field in December 2023. Our production-sharing contracts (PSCs), which are described below, did not have a significant impact on our net oil production in the three months ended March 31, 2024 compared to the three months ended December 31, 2023. The following table reconciles our average net production to our average gross production (which includes production from the fields we operate and our share of production from fields operated by others) for the periods presented: Three months ended March 31, 2024 December 31, 2023 (MBoe/d) Total Net Production 76 83 Partners' share under PSC-type contracts 7 7 Working interest and royalty holders' share 7 7 Changes in NGL inventory and other 4 1 Total Gross Production 94 98 Production-Sharing Contracts (PSCs) Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure which adjusts for excess costs attributable to PSC-type contracts for the periods presented in the tables below: Three months ended March 31, 2024 December 31, 2023 (in millions) ($ per Boe) (in millions) ($ per Boe) Operating costs (a) $ 179 $ 25.80 $ 186 $ 24.49 Excess costs attributable to PSC-type contracts (18) (2.54) (17) (2.22) Operating costs, excluding effects of PSC-type contracts $ 161 $ 23.26 $ 169 $ 22.27 (a) Operating costs related to our exploration and production activities and are presented before elimination entries. For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2023 Annual Report. 28 Prices and Realizations The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX indexes for our oil and natural gas operations for the periods presented: Three months ended March 31, 2024 December 31, 2023 Price Realization Price Realization Oil ($ per Bbl) Brent $ 81.84 $ 82.69 Realized price without derivative settlements $ 80.16 98% $ 82.00 99% Derivative settlements (2.99) (10.66) Realized price with derivative settlements $ 77.17 94% $ 71.34 86% WTI $ 76.96 $ 78.32 Realized price without derivative settlements $ 80.16 104% $ 82.00 105% Realized price with derivative settlements $ 77.17 100% $ 71.34 91% NGLs ($ per Bbl) Realized price (% of Brent) $ 50.50 62% $ 49.08 59% Realized price (% of WTI) $ 50.50 66% $ 49.08 63% Natural gas NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 2.24 $ 2.88 Realized price ($/Mcf) $ 3.90 174% $ 4.66 162% Oil — Brent prices were relatively flat for the three months ended March 31, 2024 compared to the three months ended December 31, 2023. The slight decline in Brent prices is attributable to general market factors, including developing concern over the strength of China’s economy. NGLs — NGL prices for the three months ended March 31, 2024 increased compared to the three months ended December 31, 2023 due to slightly stronger butane demand and development of alternative markets for our natural gasoline. California remained a premium market compared to other North American locations. Natural Gas — Natural gas prices decreased for the three months ended March 31, 2024 compared to the three months ended December 31, 2023 driven by growing natural gas production nationally and a surplus of natural gas in storage both nationally as well as in California. 29 Statements of Operations Analysis The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses and intercompany eliminations, for the three months ended March 31, 2024 and December 31, 2023. All metrics are shown on a per Boe basis except as otherwise stated. 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. Three months ended March 31, 2024 December 31, 2023 Total net production (MBoe/d) 76 83 Total oil, natural gas and NGL sales (in millions) $ 435 $ 483 Energy operating costs $ 8.07 $ 8.65 Gas processing costs 0.58 0.60 Non-energy operating costs 17.15 15.24 Operating costs $ 25.80 $ 24.49 Field general and administrative expenses (a) $ 1.30 $ 1.18 Field depreciation, depletion and amortization (b) $ 7.06 $ 6.58 Field taxes other than on income $ 4.61 $ 2.63 (a) Excludes unallocated general and administrative expenses. (b) Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant. Energy operating costs were lower on a per Boe basis during the three months ended March 31, 2024 compared to the three months ended December 31, 2023 where the benefit of lower electricity and natural gas prices was predominately offset by lower production volumes between periods. Non-energy operating costs were higher on a per Boe basis between the three months ended March 31, 2024 compared to the three months ended December 31, 2023 due to lower production volumes between periods. Consolidated Results of Operations For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 13 Condensed Consolidated Financial Information. Certain prior period balances related to NGL marketing activities have been reclassified to conform to our 2024 presentation. For the three months ended December 31, 2023, we reclassified $4 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on our condensed consolidated statement of operations. We also reclassified $3 million of NGL processing fees from other operating expenses, net to costs related to marketing of purchased commodities. 30 Three months ended March 31, 2024 compared to December 31, 2023 The following table presents our consolidated operating revenues for the three months ended March 31, 2024 and December 31, 2023: Three months ended March 31, 2024 December 31, 2023 (in millions) Oil, natural gas and NGL sales $ 429 $ 483 Net (loss) gain from commodity derivatives (71) 119 Revenue from marketing of purchased commodities 74 71 Electricity sales 15 42 Other revenue 7 11 Total operating revenues $ 454 $ 726 Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $429 million for the three months ended March 31, 2024, which is a decrease of $54 million compared to $483 million for the three months ended December 31, 2023. This decrease was primarily due to lower production volumes and lower realized prices for the first quarter of 2024 as shown in the table below. The effect of cash settlements on our commodity derivative contracts is not included in the table below. Oil NGLs Natural Gas Total (in millions) Three months ended December 31, 2023 $ 380 $ 47 $ 56 $ 483 Change in realized prices (9) 1 (9) (17) Change in production (23) 1 (9) (31) Change in intercompany sales of natural gas — — (6) (6) Three months ended March 31, 2024 $ 348 $ 49 $ 32 $ 429 Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods. Net (loss) gain from commodity derivatives — Net loss from commodity derivatives was $71 million for the three months ended March 31, 2024 compared to net gain of $119 million for the three months ended December 31, 2023. The net loss from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period. Payments on commodity derivatives were $12 million for the three months ended March 31, 2024 compared to $49 million for the three months ended December 31, 2023. Including the effect of settlement payments for commodity derivatives, the realized prices received for our oil, natural gas and NGL sales decreased by $17 million compared to the three months ended December 31, 2023. Three months ended March 31, 2024 December 31, 2023 (in millions) Non-cash commodity derivative (loss) gain $ (59) $ 168 Settlements and premiums (12) (49) Net (loss) gain from commodity derivatives $ (71) $ 119 Electricity sales — Electricity sales decreased by $27 million to $15 million for the three months ended March 31, 2024 compared to $42 million for the three months ended December 31, 2023 due to downtime at our Elk Hills power plant for planned maintenance and lower electricity prices in the first quarter of 2024. 31 The following table presents our consolidated operating and non-operating expenses and income for the three months ended March 31, 2024 and December 31, 2023: Three months ended March 31, 2024 December 31, 2023 (in millions) Operating expenses Energy operating costs $ 53 $ 65 Gas processing costs 4 4 Non-energy operating costs 119 117 General and administrative expenses 57 66 Depreciation, depletion and amortization 53 55 Taxes other than on income 38 33 Exploration expense 1 1 Costs related to marketing of purchased commodities 54 42 Electricity generation expenses 8 18 Transportation costs 20 18 Accretion expense 12 11 Carbon management business expenses 8 17 Other operating expenses, net 37 21 Total operating expenses 464 468 Gain on asset divestitures 6 25 Operating (loss) income (4) 283 Non-operating (expenses) income Interest and debt expense (13) (13) Loss on early extinguishment of debt — (1) Loss from investment in unconsolidated subsidiary (3) (3) Other non-operating income 1 1 (Loss) income before income taxes (19) 267 Income tax benefit (provision) 9 (79) Net (loss) income $ (10) $ 188 Energy operating costs — Energy operating costs for the three months ended March 31, 2024 were $53 million, which was a decrease of $12 million from $65 million for the three months ended December 31, 2023. This decrease was primarily the result of lower electricity and natural gas prices in the first quarter of 2024. For more information on natural gas market prices, see Prices and Realizations above. General and administrative expenses — General and administrative (G&A) expenses were $57 million for the three months ended March 31, 2024, which was a decrease of $9 million from $66 million for the three months ended December 31, 2023. The decrease in G&A expenses was primarily attributable to a reduction in compensation-related expenses. Stock-based compensation 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 at the end of a two- or three-year period 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. 32 Stock-based compensation included in G&A expense is shown in the table below: Three months ended March 31, 2024 December 31, 2023 (in millions) Cash-settled awards $ 3 $ 2 Stock-settled awards 5 6 Total included in general and administrative expenses $ 8 $ 8 Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $54 million for the three months ended March 31, 2024 compared to $42 million for the three months ended December 31, 2023. The increase of $12 million was primarily due to higher purchases of third-party crude oil. Electricity generation expenses — Electricity generation expenses for the three months ended March 31, 2024 were $8 million, which was a decrease of $10 million from $18 million for the three months ended December 31, 2023. This decrease was primarily due to lower variable operating costs due to downtime resulting from scheduled maintenance of our Elk Hills power plant in the first quarter of 2024. Other operating expenses, net — Other operating expenses, net increased $16 million to $37 million for the three months ended March 31, 2024 compared to $21 million for the three months ended December 31, 2023. The increase was predominately due to additional expenses related to electricity purchased during the scheduled maintenance at our Elk Hills power plant as well as transaction and integration costs related to the Aera Merger. Income taxes — The income tax benefit for the three months ended March 31, 2024 was $9 million (representing an effective tax rate of 47%), compared to a provision of $79 million (representing an effective tax rate of 30%) for the three months ended December 31, 2023. We recognized an excess tax benefit as a discrete adjustment in the first quarter of 2024 related to the settlement of certain equity-settled stock-based compensation awards. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our effective tax rate. 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 three months ended March 31, 2024 were for capital investments, repurchases of our common stock and dividends. The following table summarizes our liquidity: March 31, 2024 (in millions) Cash and cash equivalents $ 403 Revolving Credit Facility: Borrowing capacity 630 Outstanding letters of credit (153) Availability $ 477 Liquidity $ 880 33 We amended our Revolving Credit Facility during the first quarter of 2024 as described in Part I, Item 1 – Financial Statements, Note 4 Debt and continue to evaluate refinancing options for our Senior Notes. In March 2024, we obtained commitments from our existing lenders and certain new lenders to amend our Revolving Credit Facility upon closing of the Aera Merger. These commitments include increasing our borrowing base from $1.2 billion to $1.5 billion, increasing the aggregate commitment amount from $630 million to $1.1 billion and other matters. These commitments are subject to certain conditions prior to becoming effective, including the closing of the Aera Merger. We intend to undertake certain financing transactions in connection with the Aera Merger. See Part I, Item 1 – Financial Statements, Note 2 Pending Aera Merger. We also intend to pursue financing options for our carbon management business that are separate from the rest of our business. 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 (v) maintain cash and cash equivalents on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months. Cash Flow Analysis Cash flows from operating activities — For the three months ended March 31, 2024, our operating cash flow decreased $223 million to $87 million from $310 million in the same period in 2023. This decrease in operating cash flow was primarily driven by lower natural gas prices in California markets during the first quarter of 2024 compared to 2023. Our average natural gas prices decreased $17.66 per Mcf from $21.56 per MMcf in the three months ended March 31, 2024 to $3.90 per Mcf during the three months ended March 31, 2024. Further, our natural gas production decreased by 31 MMcf/d from 136 MMcf/d in the three months ended March 31, 2023 to 105 MMcf/d in the three months ended March 31, 2024, also contributing to the decrease. While our realized oil price with derivative settlements increased by $14.13 per barrel to $77.17 in the three months ended March 31, 2024 from $63.04 in the same prior year period, our net oil production volumes decreased 7 MBbl/d from 55 MBbl/d in the three months ended March 31, 2023 to 48 MBbl/d in the three months ended March 31, 2024. Our total net production volumes decreased by 13 MBoe/d from 89 MBoe/d in the three months ended March 31, 2023 to 76 MBoe/d for the three months ended March 31, 2024 primarily due to scheduled plant downtime during the first quarter of 2024, natural production decline and the divestiture of our share of a non-operated field in December 2023. Our PSCs also negatively impacted our net oil production by 1 MBoe/d in the three months ended March 31, 2024 compared to the same prior year period. Cash flows used in investing activities — The following table provides a comparative summary of net cash used in investing activities: Three months ended March 31, 2024 2023 (in millions) Capital investments $ (54) $ (47) Changes in accrued capital investments (4) (13) Proceeds from divestitures, net 10 — Other, net (1) (1) Net cash used in investing activities $ (49) $ (61) In March 2024, we sold our 0.9-acre Fort Apache real estate property in Huntington Beach, California. For more information on our divestiture in the three months ended March 31, 2024, see Part I, Item 1 – Financial Statements, Note 8 Divestitures and Acquisitions. 34 Cash flows used in financing activities — The following table provides a comparative summary of net cash used in financing activities: Three months ended March 31, 2024 2023 (in millions) Repurchases of common stock (a) $ (58) $ (59) Common stock dividends (21) (20) Payments on equity-settled awards (4) — Issuance of common stock 1 1 Bridge loan commitment and debt amendment costs (8) — Shares cancelled for taxes (41) (1) Net cash used in financing activities $ (131) $ (79) (a) The total value of shares purchased includes approximately $1 million in both the three months ended March 31, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented. 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 $21 million of dividends paid in the first quarter of 2024, we paid $4 million of dividend equivalents accrued on these stock-based compensation awards. 2024 Capital Program Our capital program is dynamic in response to commodity price volatility while focusing on oil production and maximizing our free cash flow. Following the Court of Appeals decision in the Kern County EIR matter, we expect our 2024 capital program to range between $200 million and $240 million under current permitting conditions. Of this amount, $165 million to $185 million is related to oil and natural gas development (including $20 million to $25 million for maintenance at one of our gas processing facilities at our Elk Hills field), $20 million to $25 million is for carbon management projects and $15 million to $30 million is for corporate and other (including $10 million to $15 million related to scheduled maintenance at our Elk Hills power plant). We expect to run a one rig program for 2024 executing projects using existing permits. Refer to Regulatory Updates above for more information. The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals: Three months ended March 31, 2024 (in millions) Oil and natural gas operations (a) $ 36 Carbon management business 4 Corporate and other (b) 14 Total Capital $ 54 (a) During the three months ended March 31, 2024, we incurred an insignificant amount of costs related to planned maintenance at one of our gas processing facilities at our Elk Hills field. (b) During the three months ended March 31, 2024, we incurred approximately $13 million related to planned maintenance at our Elk Hills power plant. Derivatives Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions. 35 Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2024. See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of March 31, 2024 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2023 Annual Report for information on the hedging requirements included in our Revolving Credit Facility. Dividends Our Board of Directors declared the following cash dividends in each of the periods presented. Total Dividend Rate Per Share (in millions) ($ per share) Three months ended March 31, 2024 $ 21 $ 0.31 Three months ended March 31, 2023 $ 20 $ 0.2825 In addition to dividends declared, we paid $4 million of dividend equivalents related to stock-based compensation awards which were settled in the three months ended March 31, 2024. The declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Since the adoption of our dividend policy in 2021, we have returned $175 million to shareholders through dividends. For information regarding past dividends paid, see Cash Flow Analysis, Cash Flow Used in Financing Activities above. 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. The aggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $691 million, excluding commissions and excise taxes on repurchases, as of March 31, 2024. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The following is a summary of our share repurchases, which are held as treasury stock, for the periods presented: Total Number of Shares Purchased Total Value of Shares Purchased Average Price Paid per Share (number of shares) (in millions) ($ per share) Three months ended March 31, 2023 1,423,764 $ 59 $ 41.25 Three months ended March 31, 2024 1,065,764 $ 58 $ 53.26 Inception of Program (May 2021) through March 31, 2024 15,929,679 $ 662 $ 41.39 Note: The total value of shares purchased includes approximately $1 million in both the three months ended March 31, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented. Divestitures and Acquisitions See Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions for information on our transactions during the three months ended March 31, 2024 and 2023. 36 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 March 31, 2024 and December 31, 2023 were not material to our condensed consolidated balance sheets as of such dates. 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 I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for further information. Critical Accounting Estimates and Significant Accounting and Disclosure Changes There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates of our 2023 Annual Report. 37 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,” “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 pending 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; • 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, Ukraine and Yemen and the Red Sea; • the ability to successfully integrate the business of Aera once the Aera merger is completed; • the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the Aera merger that could reduce anticipated benefits or cause the parties to abandon the Aera merger; • the occurrence of any event, change or other circumstances that could give rise to the termination of the Merger Agreement; • the possibility that the stockholders of CRC may not approve the issuance of new shares of common stock in the Aera merger; • the ability to obtain the required debt financing pursuant to our commitment letters and, if obtained, the potential impact of additional debt on our business and the financial impacts and restrictions due to the additional debt; • 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, permits and approvals necessary for drilling or development activities or our carbon management business, (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment or (4) the transportation, marketing and sale of our products; • 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; 38 • our ability to claim and utilize tax credits or other incentives in connection with our CCS projects and clean energy projects; • our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS projects and other renewable energy efforts; • our ability to successfully identify, develop and finance carbon capture and storage projects 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 business 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 business; • 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 in our 2023 Annual Report . 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. 39