California Resources Corp 10-Q

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations General We are an independent energy and carbon management company committed to energy transition. We are committed to environmental stewardship while safely providing local, responsibly sourced energy. We are also focused on maximizing the value of our land, mineral ownership, and energy expertise for decarbonization by developing carbon capture and storage (CCS) and other emissions-reducing projects. Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its consolidated subsidiaries as of the date presented. Business Environment and Industry Outlook Commodity Prices Our operating results, and those of the oil and natural gas industry, are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it challenging 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 and natural gas prices may affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Results of Our Oil and Natural Gas Operations, Production, Prices and Realizations below for information on our realized prices. During 2025, Brent prices were negatively affected by a succession of announcements by OPEC+ of its intention to return offline production to market at a much quicker pace than previously anticipated and concern over the state of global trade following a series of tariff announcements. Prices slightly increased in June 2025 as tensions between Iran and Israel became overtly military in nature and a concern developed that petroleum flowing through the Persian Gulf — and through the Strait of Hormuz, in particular — could ultimately be impacted. Collectively, these factors introduced significant oil price volatility with Brent crude oil prices fluctuating between a low of approximately $60 per barrel in early May and a high of approximately $80 per barrel in mid-June. The following table presents the average daily benchmark prices for oil and natural gas during the periods presented: Three months ended Six months ended June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024 Brent oil ($/Bbl) $ 66.76 $ 74.92 $ 70.84 $ 83.42 WTI oil ($/Bbl) $ 63.74 $ 71.42 $ 67.58 $ 78.77 NYMEX Henry Hub ($/MMBtu) $ 3.44 $ 3.65 $ 3.55 $ 2.07 Supply Chain and Inflation We continued to experience relatively flat pricing from our suppliers in the first half of 2025 as compared to the prior year. Tariff policy changes by the U.S. government for both country of origin and material type remains uncertain. The United States recently expanded tariff rates on imported goods including a 50% tariff on the steel and aluminum value of imported products. These expanded tariff rates, if sustained, could increase our cost of oilfield goods and expand delivery lead times over the longer term. We have taken measures to limit the effects of price increases caused by the recent expansion of U.S. tariffs by entering into fixed price contracts with terms of one to three years for a significant majority of our materials and services based on our current expected development plans. We also pre-purchased inventory prior to the execution of the tariffs and continue to purchase from vendors who source domestic content to limit the impact of foreign tariffs on our business. Overall, we continue to expect minimal impact of tariffs in our supply chain in 2025. Assuming the current tariff regime remains in place or is expanded, our inventory, capital and operating costs could increase over the long-term. 35 Marketing Arrangements In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. Additionally, in April 2025, Valero notified the California Energy Commission of its intent to idle, restructure, or cease refining operations at its Benicia refinery in the San Francisco Bay Area by the end of April 2026. Historically, we have sold a portion of our crude oil to these refineries. Assuming both refineries were to cease operations, there will be six remaining major petroleum refineries in California, each of which have a refining capacity greater than 75,000 barrels per day. We expect this would leave California with approximately 1.3 million barrels per day of remaining major refining capacity, which is more than four times the amount of crude oil produced in California in 2024. As a result of this and given the considerable flexibility we have in marketing our production, we do not expect the cessation of operations at these refineries, should they occur, will affect our ability to market our crude oil production. While these announcements have had no impact on our price realizations thus far, fewer refineries in California have the potential to impact our future price realizations. Regulatory Updates Well Permitting During the three months ended June 30, 2025, we received well permits for 86 workovers and 84 sidetracks. The rate at which CalGEM issued permits for workovers and sidetracks during this period continued to increase relative to the three months ended March 31, 2025. During the first half of 2025, we have received total well permits for 139 workovers, 105 sidetracks and 4 deepenings. We have not received any permits for new wells in 2025. We currently hold sufficient permits to maintain our existing two drilling rig capital program throughout 2025. We also have the requisite number of permits in hand to run one active drilling rig throughout 2026. For further information regarding well permitting, see Part I, Items 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities, Well Permitting in our 2024 Annual Report. Kern County EIR Litigation On June 26, 2025, the Kern County Board of Supervisors certified a revised Environmental Impact Report (EIR) and approved an ordinance that authorizes the development of oil and natural gas wells in the county consistent with the revised EIR. Kern County is seeking the Trial Court’s determination that the revised EIR complies with the judgment and order of the Trial Court and decision of the Court of Appeal. After that, the Trial Court could lift the stay, subject to further potential appeals. The timing of when or if the Trial Court will take such action is uncertain. If the stay is lifted and no further stay is issued by the Court of Appeal, new well permitting could resume. However, there is no certainty we will obtain permits on that timeline or at all, or that the Trial Court and Court of Appeal will collectively lift the stay before a final, non-appealable ruling upholding the adequacy of the revised EIR is issued. These developments could further adversely affect our business, results of operations and financial condition. Waste Emissions Charge In May 2025, following a joint resolution of disapproval under the Congressional Review Act, the EPA issued a final rule to remove the Waste Emission Charge (WEC) regulations, originally adopted under the Inflation Reduction Act, from the Code of Federal Regulations. As a result, the fees associated with methane emissions from certain oil and gas facilities that would have been due to the EPA in September 2025 will not be collected. Although the underlying statute still requires a methane charge, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14th and commonly referred to as the One Big Beautiful Bill Act, postponed implementation from 2024 to 2034. 36 Water Injection Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. CalGEM has issued a directive to reduce the injection well pressure in a gradual manner in accordance with a five-year injection reduction work plan. The first phase of reduction commenced July 1, 2024 and a second reduction began in January 2025. The next phase of reduction is currently on hold while we evaluate the impact of the previously implemented reductions together with CalGEM. The work plan may be adjusted and it is difficult to predict with accuracy the impact to production and reserves. However, we continue to estimate a negative impact on production of approximately 1 MBoe/d at the end of the current 5-year work plan. We also estimate that the net present value of our proved developed reserves would be negatively impacted by less than 1%. These estimates could change materially pending the results of future technical audits. Statements of Operations Analysis 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 – Financial Statements, Note 2 Aera Merger . The Aera Merger and related transactions have significantly impacted the comparability of our financial results for the six months ended 2024. Consolidated Results of Operations Three months ended June 30, 2025 compared to March 31, 2025 The following table presents our consolidated operating revenues for the periods indicated: Three months ended June 30, 2025 March 31, 2025 (in millions) Oil, natural gas and natural gas liquids sales $ 702 $ 814 Net gain from commodity derivatives 157 6 Revenue from marketing of purchased commodities 56 64 Electricity revenue 58 22 Other revenue 5 6 Total operating revenues $ 978 $ 912 Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $702 million for the three months ended June 30, 2025, which is a decrease of $112 million compared to $814 million for the three months ended March 31, 2025. The following table shows changes in oil, natural gas and natural gas liquids sales for the three months ended June 30, 2025 compared to the three months ended March 31, 2025: Oil NGLs Natural Gas Total Operations (in millions) Three months ended March 31, 2025 $ 736 $ 50 $ 28 $ 814 Changes in realized prices (85) (11) (14) (110) Changes in production and other (7) — (1) (8) Changes in intersegment revenues — — 6 6 Three months ended June 30, 2025 $ 644 $ 39 $ 19 $ 702 Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods. 37 Net gain from commodity derivatives — We report gains and losses on our derivative contracts related to sales of our oil and marketing activities in operating revenues. Net gain from commodity derivatives was $157 million for the three months ended June 30, 2025 compared to a net gain of $6 million for the three months ended March 31, 2025. The change primarily resulted from the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below: Three months ended June 30, 2025 March 31, 2025 (in millions) Non-cash commodity derivative gain $ 140 $ 22 Net proceeds (settlements) and amortized premiums 17 (16) Net gain from commodity derivatives $ 157 $ 6 Electricity revenue — Electricity revenue increased by $36 million to $58 million for the three months ended June 30, 2025 compared to $22 million for the three months ended March 31, 2025. This increase was primarily a result of higher resource adequacy sales driven by increased seasonal pricing for the three months ended June 30, 2025 compared to the three months ended March 31, 2025, as well as downtime for maintenance that primarily impacted the three months ended March 31, 2025. 38 The following table presents our consolidated operating and non-operating expenses and income for the three months ended June 30, 2025 and March 31, 2025. Three months ended June 30, 2025 March 31, 2025 (in millions) Operating expenses Energy operating costs $ 78 $ 103 Gas processing costs 5 4 Non-energy operating costs 212 209 General and administrative expenses 79 72 Depreciation, depletion and amortization 128 131 Taxes other than on income 47 70 Costs related to marketing of purchased commodities 41 50 Electricity generation expenses 5 10 Transportation costs 20 20 Accretion expense 28 29 Net loss (gain) on natural gas purchase derivatives 3 (6) Measurement period adjustments, net — 1 Other operating expenses, net 65 33 Total operating expenses 711 726 Operating income 267 186 Non-operating (expenses) income Interest and debt expense, net (25) (27) Loss on early extinguishment of debt — (1) Loss from investment in unconsolidated subsidiaries — (1) Other non-operating income, net — 5 Income before income taxes 242 162 Income tax provision (70) (47) Net income $ 172 $ 115 Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations. These internal costs include an allocation of the direct costs to produce electricity at our Elk Hills power plant based on electricity consumption by our Elk Hills and nearby fields. There is no internal allocation of the costs to produce steam from the power plant used in oil and natural gas operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs Energy operating costs — Energy operating costs for the three months ended June 30, 2025 were $78 million, which was a decrease of $25 million from $103 million for the three months ended March 31, 2025. This decrease was primarily due to lower prices and lower volumes of natural gas used in our steamflood operations . For more information on natural gas market prices, see Prices and Realizations below. General and administrative expenses — General and administrative (G&A) expenses were $79 million for the three months ended June 30, 2025 compared to $72 million for the three months ended March 31, 2025, which was an increase of $7 million. The increase was primarily a result of higher legal expenses and compensation-related expenses during the three months ended June 30, 2025. 39 Taxes other than on income — Taxes other than on income for the three months ended June 30, 2025 were $47 million, which was a decrease of $23 million from $70 million for the three months ended March 31, 2025. The decrease was primarily due to an adjustment to the production tax rate. We also had lower greenhouse gas expense based on market prices. Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities for the three months ended June 30, 2025 were $41 million, which is a decrease of $9 million from $50 million for the three months ended March 31, 2025. This decrease was primarily due to lower natural gas prices, partially offset by increased volumes of purchased natural gas. Other operating expenses, net — Other operating expenses, net increased $32 million to $65 million for the three months ended June 30, 2025 compared to $33 million for the three months ended March 31, 2025. For the three months ended June 30, 2025 and March 31, 2025, other operating expenses, net includes the following: Three months ended June 30, 2025 March 31, 2025 (in millions) Carbon management business expense $ 14 $ 18 Aera transaction and integration costs 3 3 Severance 6 2 Front-end engineering design studies — 3 Litigation and settlement related expenses (a) 25 — All other 17 7 Total operating expenses, net $ 65 $ 33 (a) See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the three months ended June 30, 2025. Income taxes – The income tax provision for the three months ended June 30, 2025 was $70 million (representing an effective tax rate of 29%), compared to a provision of $47 million (representing an effective tax rate of 29%) for the three months ended March 31, 2025. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes . Six months ended June 30, 2025 compared to June 30, 2024 The following table presents our consolidated operating revenues for the periods indicated: Six months ended June 30, 2025 June 30, 2024 (in millions) Oil, natural gas and natural gas liquids sales $ 1,516 $ 841 Net gain (loss) from commodity derivatives 163 (66) Revenue from marketing of purchased commodities 120 125 Electricity revenue 80 51 Other revenue 11 17 Total operating revenues $ 1,890 $ 968 40 Oil, natural gas and natural gas liquids sales — Oil, natural gas and natural gas liquids sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,516 million for the six months ended June 30, 2025, which is an increase of $675 million compared to $841 million for the six months ended June 30, 2024. The following table shows changes in oil, natural gas and natural gas liquids sales for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. Oil NGLs Natural Gas Total Operations (in millions) Six months ended June 30, 2024 $ 701 $ 94 $ 46 $ 841 Changes in realized prices (106) — 13 (93) Changes in production and other (a) 785 (5) 2 782 Changes in intersegment revenues — — (14) (14) Six months ended June 30, 2025 $ 1,380 $ 89 $ 47 $ 1,516 Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods. (a) The increase in production primarily relates to the addition of the Aera fields on July 1, 2024. See Part I, Item 1 – Financial Statements, Note 2 Aera Merger for additional information. Net gain (loss) from commodity derivatives – We report gains and losses on our derivative contracts related to sales of our produced oil and marketing activities in operating revenue. Net gain from commodity derivatives was $163 million for the six months ended June 30, 2025 compared to a net loss of $66 million for the six months ended June 30, 2024. The change primarily resulted from payments to settle commodity derivative contracts and the non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period. Gains and losses from our commodity derivative contracts are shown in the table below: Six months ended June 30, 2025 June 30, 2024 (in millions) Non-cash commodity derivative gain (loss) $ 162 $ (48) Net settlements and amortized premiums 1 (18) Net gain (loss) from commodity derivatives $ 163 $ (66) Electricity revenue — Electricity revenue increased by $29 million to $80 million for the six months ended June 30, 2025 compared to $51 million for the six months ended June 30, 2024. This increase was primarily a result of higher pricing from resource adequacy contracts. 41 The following table presents our consolidated operating and non-operating expenses and income for the six months ended June 30, 2025 and June 30, 2024. Six months ended June 30, 2025 June 30, 2024 (in millions) Operating expenses Energy operating costs $ 181 $ 94 Gas processing costs 9 7 Non-energy operating costs 421 231 General and administrative expenses 151 120 Depreciation, depletion and amortization 259 106 Asset impairment — 13 Taxes other than on income 117 77 Costs related to marketing of purchased commodities 91 97 Electricity generation expenses 15 22 Transportation costs 40 37 Accretion expense 57 25 Net (gain) loss on natural gas purchase derivatives (3) 2 Measurement period adjustments, net 1 — Other operating expenses, net 98 110 Total operating expenses 1,437 941 Gain on asset divestitures — 7 Operating income 453 34 Non-operating (expenses) income Interest and debt expense, net (52) (30) Loss on early extinguishment of debt (1) — Loss from investment in unconsolidated subsidiaries (1) (7) Other non-operating income, net 5 (5) Income before income taxes 404 (8) Income tax (provision) benefit (117) 6 Net income (loss) $ 287 $ (2) Energy operating costs — Energy operating costs for the six months ended June 30, 2025 were $181 million , which was an increase of $87 million from $94 million for the six months ended June 30, 2024. This increase was predominantly due to additional energy costs and natural gas used in our steamflood operations related to the addition of the Aera fields on July 1, 2024. Excluding $94 million related to the operation of the Aera fields, our energy operating costs would have been $87 million for the six months ended June 30, 2025. The decrease was primarily a result of lower energy and natural gas costs in the six months ended June 30, 2025 compared to the same prior year period. Non-energy operating costs — Non-energy operating costs for the six months ended June 30, 2025 were $421 million , which was an increase of $190 million from $231 million for the six months ended June 30, 2024. The increase includes $191 million predominantly related to the addition of the Aera fields on July 1, 2024. Excluding the costs related to the Aera fields, our non-energy operating costs would have been $230 million for the six months ended June 30, 2025, which would be in line with the same prior year period. General and administrative expenses — General and administrative (G&A) expenses were $151 million for the six months ended June 30, 2025 compared to $120 million for the six months ended June 30, 2024, which was an increas e of $31 million . The increase was primarily due to additional compensation-related expense and other corporate expense resulting from the Aera Merger. 42 Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) for the six months ended June 30, 2025 was $259 million compared to $106 million durin g the six months ended June 30, 2024. The increase of $153 million was primarily the result of the addition of the Aera assets included in the six months ended June 30, 2025. See Part I, Item 1 – Financial Statements, Note 2 Aera Merger for information on the Aera assets. Asset impairments — During the six months ended June 30, 2024, we recognized a $13 million impairment for excess and obsolete materials and supplies related to our oilfield operations. We did not recognize an asset impairment during the six months ended June 30, 2025. Taxes other than on income — Taxes other than on income for the six months ended June 30, 2025 were $117 million, which is an increase of $40 million from $77 million for the six months ended June 30, 2024. This 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. Accretion expense — Accretion expense for the six months ended June 30, 2025 was $57 million compared to $25 million for the six months ended June 30, 2024. The increase was primarily due to the addition of the Aera asset retirement liability assumed as of July 1, 2024 in connection with the Aera Merger. Other operating expenses, net — Other operating expenses, net decreased $12 million to $98 million for the six months ended June 30, 2025 compared to $110 million for the six months ended June 30, 2024. For the six months ended June 30, 2025 and June 30, 2024, other operating expenses, net includes the following: Six months ended June 30, 2025 June 30, 2024 (in millions) Carbon management business expense $ 32 $ 23 Aera transaction and integration costs 8 26 Energy costs due to downtime at Elk Hills power plant — 36 Severance 8 1 Litigation and settlement related expenses (a) 25 7 All other 25 17 Total operating expenses, net $ 98 $ 110 (a) See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for more information on a $25 million payment we made to CalGEM during the six months ended June 30, 2025. Interest and debt expense, net — Interest and debt expense, net was $52 million for the six months ended June 30, 2025 compared to $30 million for the six months ended June 30, 2024. The increase was predominantly due to higher interest expense resulting from the issuance of our 2029 Senior Notes. In June 2024, we issued $600 million in aggregate principal amount of 2029 Senior Notes and in August 2024, we completed a follow-on offering of $300 million in aggregate principal amount of 2029 Senior Notes. Income taxes – The income tax provision for the six months ended June 30, 2025 was $117 million (representing an effective tax rate of 29%), compared to a benefit of $6 million (representing an effective tax rate of 75%) for the six months ended June 30, 2024. See Part I, Item 1 – Financial Statements, Note 7 Income Taxes for additional information on our income taxes. For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the 2026 Senior Notes Indenture and 2029 Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 15 Condensed Consolidated Financial Information. 43 Results of Our Oil and Natural Gas Operations The following table includes financial results and key operating data for our oil and natural gas segment for the three months ended June 30, 2025 and March 31, 2025 and the six months ended June 30, 2025 and 2024. Three months ended Six months ended June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024 (in millions, except as otherwise stated) Production and segment financial data Net production sold (MBoe/d) 137 141 139 76 Segment total operating revenues $ 714 $ 830 $ 1,544 $ 854 Segment profit $ 194 $ 266 $ 460 $ 249 Items affecting comparability: Gain on asset divestitures (a) $ — $ — $ — $ 7 Key operating expenses per Boe Operating costs $ 24.19 $ 25.60 $ 24.90 $ 24.48 Operating costs, after hedges on purchased natural gas $ 24.75 $ 26.55 $ 25.65 $ 24.91 Segment general and administrative expenses (b) $ 0.72 $ 0.95 $ 0.84 $ 1.30 Segment depreciation, depletion and amortization (c) $ 9.69 $ 9.96 $ 9.82 $ 6.95 Segment taxes other than on income $ 3.28 $ 4.66 $ 3.98 $ 4.71 (a) Gain on asset divestitures for the six months ended June 30, 2024 related to the sale of oil and gas assets located in Ventura. (b) Excludes unallocated general and administrative expenses. (c) Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant. 44 Production, Prices, and Realizations Net Production Sold The following table sets forth our average net production of oil, NGLs and natural gas sold per day in each of the California oil and natural gas basins in which we operate for the periods presented. The amounts in the production table below include volumes produced from operated and non-operated fields for each of the periods presented. Three months ended Six months ended June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024 Oil (MBbl/d) San Joaquin Basin 83 84 84 30 Los Angeles Basin 17 18 17 17 Other Basins 9 9 9 — Total 109 111 110 47 NGLs (MBbl/d) San Joaquin Basin 10 10 10 11 Total 10 10 10 11 Natural gas (MMcf/d) San Joaquin Basin 96 101 99 94 Los Angeles Basin 1 1 1 1 Sacramento Basin 12 12 12 14 Other Basins 2 3 2 — Total 111 117 114 109 Total Net Production Sold (MBoe/d) 137 141 139 76 Total average net production sold decreased to 137 MBoe/d for the three months ended June 30, 2025 compared to 141 MBoe/d for the three months ended March 31, 2025. The decrease was primarily a result of natural production decline partially offset by development results. In addition, our production-sharing contracts (PSCs), which are described below, negatively impacted our net oil production by 1 MBoe/d in the three months ended June 30, 2025 compared to the three months ended March 31, 2025. Total average net production sold increased to 139 MBoe/d for the six months ended June 30, 2025 compared to 76 MBoe/d for the six months ended June 30, 2024. The increase was primarily a result of the Aera Merger. Our PSCs, which are described below, positively impacted our net oil production by 1 MBoe/d in the six months ended June 30, 2025 compared to the six months ended June 30, 2024. Production-Sharing Contracts Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts that are in effect through the economic life of the assets. The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2024 Annual Report. 45 Prices and Realizations The following tables set forth the average realized prices and price realizations on the commodities we sell as a percentage of average Brent, WTI and NYMEX Henry Hub indexes for our oil and natural gas operations for the periods presented: Three months ended June 30, 2025 March 31, 2025 Price Realization Price Realization Oil ($ per Bbl) Brent $ 66.76 $ 74.92 Realized price without derivative settlements $ 65.07 97% $ 73.57 98% Derivative settlements 1.66 (1.56) Realized price with derivative settlements $ 66.73 100% $ 72.01 96% WTI $ 63.74 $ 71.42 Realized price without derivative settlements $ 65.07 102% $ 73.57 103% Realized price with derivative settlements $ 66.73 105% $ 72.01 101% Natural Gas Liquids ($ per Bbl) Realized price (% of Brent) $ 42.41 64% $ 54.64 73% Realized price (% of WTI) $ 42.41 67% $ 54.64 77% Natural gas NYMEX Henry Hub ($/MMBtu) $ 3.44 $ 3.65 Realized price ($/Mcf) $ 2.79 81% $ 4.12 113% 46 Six months ended June 30, 2025 June 30, 2024 Price Realization Price Realization Oil ($ per Bbl) Brent $ 70.84 83.42 Realized price without derivative settlements $ 69.34 98% $ 81.63 98% Derivative settlements 0.05 (2.43) Realized price with derivative settlements $ 69.39 98% $ 79.20 95% WTI $ 67.58 $ 78.77 Realized price without derivative settlements $ 69.34 103% $ 81.63 104% Realized price with derivative settlements $ 69.39 103% $ 79.20 101% Natural Gas Liquids ($ per Bbl) Realized price (% of Brent) $ 48.60 69% $ 48.76 58% Realized price (% of WTI) $ 48.60 72% $ 48.76 62% Natural gas NYMEX Henry Hub ($/MMBtu) $ 3.55 $ 2.07 Realized price ($/Mcf) $ 3.46 97% $ 2.81 136% Oil — Brent prices were lower for the three months ended June 30, 2025 compared to the three months ended March 31, 2025 as well as for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. See Business Environment and Industry Outlook above for more information on factors influencing Brent commodity prices for the periods presented. NGLs — Prices for natural gas liquids during the three months ended June 30, 2025 decreased compared to the three months ended March 31, 2025, reflecting traditional seasonality. Prices for natural gas liquids during the six months ended June 30, 2025 were consistent with the same prior year period. Natural Gas — Natural gas prices decreased for the three months ended June 30, 2025 compared to the three months ended March 31, 2025 driven by seasonal demand changes and the effects of significant storage volumes. Natural gas prices increased for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 driven by colder, late winter temperatures in early 2025. 47 Results of Our Carbon Management Segment Our carbon management segment, which we refer to as Carbon TerraVault, primarily pursues the development of CCS projects. We expect that our Carbon TerraVault CCS projects will inject CO 2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO 2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO 2 emissions. Our carbon management segment is in its early stages of development. We expect construction of our first carbon capture project at our cryogenic gas processing facility to be completed at or around year end at which time we will be ready to inject subject to receipt of final regulatory approvals early in 2026. The following tables include results for our carbon management segment for the three months ended June 30, 2025 and March 31, 2025 and the six months ended June 30, 2025 and June 30 2024. Three months ended Six months ended June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024 (in millions) (in millions) Segment loss $ (20) $ (25) $ (45) $ (38) Three months ended Six months ended June 30, 2025 March 31, 2025 June 30, 2025 June 30, 2024 (in millions) (in millions) Carbon management expenses $ 14 $ 18 $ 32 $ 23 Segment general and administrative expenses $ 3 $ 3 $ 6 $ 5 Loss from investment in the Carbon TerraVault JV $ 1 $ 1 $ 2 $ 7 Carbon management expenses decreased for the three months ended June 30, 2025 compared to the t hree months ended March 31, 2025 as a result of lower lease costs related to easements. Carbon management expenses increased for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 as a result of increased expenditure related to the evaluation of CCS projects and increased lease cost for the six months ended June 30, 2025. Liquidity and Capital Resources Liquidity Our primary sources of liquidity and capital resources are cash flows from operations, available cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three and six months ended June 30, 2025 were for repurchases of our common stock, payment of dividends, and capital investments. 48 The following table summarizes our liquidity: June 30, 2025 (in millions) Available cash and cash equivalents (a) $ 56 Revolving Credit Facility: Borrowing capacity 1,150 Outstanding letters of credit (167) Availability $ 983 Liquidity $ 1,039 (a) Excludes restricted cash of $16 million. At current commodity prices and based upon our planned 2025 capital program described below, we expect to generate operating cash flow to return cash to shareholders through dividends and repurchases of our common stock. In line with this strategy, our Board of Directors has extended the term of our Share Repurchase Program from December 31, 2025 to June 30, 2026. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or share repurchases to the extent permitted under our Revolving Credit Facility and the indentures for our 7.125% senior notes due 2026 (2026 Senior Notes) and our 8.25% senior notes due 2029 (2029 Senior Notes), (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We continue to monitor the current macroeconomic environment and will adjust our planned uses of cash as necessary. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months. We have taken steps to reduce headcount as part of the integration process following the Aera Merger. We initiated these workforce reductions to align the size and composition of our workforce with expected future operating and capital plans. Employee severance and related costs are included in other operating expenses, net on our condensed consolidated statement of operations. On July 4, 2025, An Act to Provide for Reconciliation Pursuant to Title II of H. Con. Res. 14th and commonly referred to as the One Big Beautiful Bill Act was signed into law. This law contains several legislative changes including the reinstatement of full expensing for qualified assets placed in service after January 19, 2025. This law also reinstated the expensing all domestic research and development costs, including favorable transition rules, and increases the limitation on the amount of annual business interest expense which can be deducted each year. We expect these legislative changes will reduce our U.S. federal cash tax obligation by approximately $35 million in 2025 and the amount of U.S. federal taxes we would have otherwise owed in future years. Revolving Credit Facility See Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the Revolving Credit Facility and related amendments. 2026 Senior Notes Redemption See Part I, Item 1 – Financial Statements, Note 4 Debt for information on a partial redemption of our 2026 Senior Notes. Share Repurchase Program See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equity and Part II, Item 2 – Other Information, Unregistered Sales of Equity Securities and Use of Proceeds for more information on our Share Repurchase Program including a repurchase of shares during the second quarter of 2025 from IKAV. 49 Dividends See Part I, Item 1 – Financial Statements, Note 10 Stockholders' Equity for more information on our dividends. See Part I, Item 1 – Financial Statements, Note 16 Subsequent Events for information on a dividend declared in August 2025. 2025 Capital Program Our capital program is dynamic in response to commodity price volatility and permit availability while focusing on oil production and maximizing our free cash flow. Our capital investment for the six months ended June 30, 2025 was $111 million. We expect our full year 2025 capital program to range between $280 million and $330 million. Of this amount, $245 million to $275 million is related to our oil and natural gas segment, $20 million to $30 million is for our carbon management segment and $15 million to $25 million is for corporate and other activities. The above amounts related to carbon management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV, such as drilling injection and monitoring wells at our 26R reservoir. With respect to oil and natural gas development, we added a second drilling rig in June 2025 and currently expect to run our two rig program through the remainder of the year using existing permits in hand. Refer to Regulatory Updates above for more information on permitting. Refer to Part I, Item 1 – Financial Statements, Note 9 Segment Information for information on capital investment by segment. Derivatives Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining oil prices negatively affect our operating cash flow, and the inverse applies during periods of rising oil prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions. Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the six months ended June 30, 2025. See Part I, Item 1 – Financial Statements, Note 6 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 2025 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Debt in our 2024 Annual Report for information on the hedging requirements included in our Revolving Credit Facility. Cash Flow Analysis Cash flows from operating activities — For the six months ended June 30, 2025, our operating cash flow increased by $167 million to $351 million from $184 million in the same period in 2024. This increase in operating cash flow was primarily driven by the Aera Merger on July 1, 2024. With the addition of Aera's assets, oil production during the six months ended June 30, 2025 as compared to the same period in 2024 increased 63 MBbl/d from 47 MBbl/d to 110 MBbl/d. Higher revenue from this increase in production was partially offset by lower average realized oil prices (after derivative settlements). Average realized prices for oil decreased by $9.81 per barrel to $69.39 in the six months ended June 30, 2025 from $79.20 in the same prior year period. Further, as a result of the Aera Merger, we experienced higher operating costs, production taxes and greenhouse gas taxes during the six months ended June 30, 2025 as compared to the same prior year period in addition to one-time transaction and integration costs were incurred in 2025. During the six months ended June 30, 2024, scheduled plant downtime at the Elk Hills power plant negatively impacted our production and we purchased electricity at higher prices. 50 Cash flows used in investing activities — The following table provides a comparative summary of net cash used in investing activities: Six months ended June 30, 2025 2024 (in millions) Capital investments $ (111) $ (88) Changes in accrued capital investments (15) 2 Proceeds from asset divestitures 1 12 Acquisitions — (6) Other, net (5) (2) Net cash used in investing activities $ (130) $ (82) Cash flows used in financing activities — The following table provides a comparative summary of net cash used in financing activities: Six months ended June 30, 2025 2024 (in millions) Proceeds from Revolving Credit Facility $ — $ 30 Proceeds from 2029 Senior Notes, net — 590 Repurchases of common stock (a) (318) (93) Common stock dividends (70) (43) Dividend equivalents on equity-settled awards (1) (4) Issuance of common stock 2 3 Bridge loan commitment costs — (5) Debt redemption (123) — Debt amendment costs — (3) Shares cancelled for taxes (11) (42) Net cash provided by (used in) financing activities $ (521) $ 433 (a) Note: The total value of shares purchased includes excise taxes, which are generally paid in the year following the share repurchase. Commissions paid on share repurchases were not significant in all periods presented. For the six months ended June 30, 2025, our cash flow used in financing activities was $521 million compared to cash flow provided by financing activities of $433 million in the same period in 2024. This decrease in cash flow from financing activities was primarily driven by the $590 million of proceeds from 2029 Senior Notes issued in the six months ended June 30, 2024. Additionally, the decrease is caused by the $123 million cash outflow used to redeem a portion of the 2026 Senior Notes in February 2025 and the $318 million cash outflow used to repurchase stock in the six months ended June 30, 2025. Divestitures and Assets Held for Sale See Part I, Item 1 – Financial Statements, Note 8 Divestitures and Assets Held for Sale for information on our divestitures and acquisitions during the three months ended June 30, 2025 and 2024. Lawsuits, Claims, Commitments and Contingencies See Part I, Item 1 – Financial Statements, Note 5 Lawsuits, Claims, Commitments and Contingencies for further information. 51 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 2024 Annual Report. 52 Forward-Looking Statements This document contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements. Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include: • fluctuations in commodity prices, including supply and demand considerations for our products and services, and the impact of such fluctuations on revenues and operating expenses; • decisions as to production levels and/or pricing by OPEC+ or U.S. producers in future periods; • government policy, war and political conditions and events, including the military conflicts in Israel, 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, tariffs and changes in domestic or global trade policies on future expenses and changes generally in the prices of goods and services; • changes in business strategy and 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 strategies and initiatives, including CCS projects and other renewable energy efforts; 53 • our ability to successfully identify, develop and finance carbon capture and storage projects, power projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our 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 of our 2024 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.