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. Aera Merger On July 1, 2024, we closed on the transactions contemplated by the definitive agreement and plan of merger (Merger Agreement) to obtain all of the ownership interests in Aera Energy, LLC (Aera) with an effective date of January 1, 2024 (Aera Merger). In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the Aera owners and paid $990 million in connection with the extinguishment of Aera's outstanding indebtedness using the proceeds from the issuance of the 2029 Senior Notes and cash on hand. For more information on the 2029 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 3 Debt. As of July 1, 2024, immediately following closing of the Aera Merger, our existing stockholders prior to the Aera Merger owned approximately 76% of CRC and the previous owners of Aera owned approximately 24% of CRC. In the three and six months ended June 30, 2024, we recognized $13 million and $26 million, respectively, of transaction and integration costs related to the Aera Merger which are included in other operating expenses, net on our condensed consolidated statement of operations. In July 2024, we recognized additional transaction costs of $27 million which were conditioned upon closing. Recent Debt Transactions 2029 Senior Notes On June 5, 2024, we completed an offering of $600 million in aggregate principal amount of 8.25% senior notes due 2029 (2029 Senior Notes). The terms of the 2029 Senior Notes are governed by the Indenture, dated as of June 5, 2024, by and among us, the guarantors and Wilmington Trust, National Association, as trustee (2029 Senior Notes Indenture). The net proceeds of $590 million, after $10 million of debt discount and issuance costs, were used along with available cash to repay all of Aera's outstanding debt at closing of the Aera Merger. For more information on the 2029 Senior Notes, refer to Part I, Item 1 – Financial Statements, Note 3 Debt. Fourth Amendment to the Revolving Credit Facility On July 1, 2024, we entered into a fourth amendment to our Revolving Credit Facility. This amendment increased the aggregate revolving commitments available under the Revolving Credit Facility from $630 million to $1.1 billion. Our ability to borrow under our Revolving Credit Facility is limited to the amount of these commitments. This amendment also increased the borrowing base from $1.2 billion to $1.5 billion, among other matters. Business Environment and Industry Outlook Commodity Prices Our operating results, and those of the oil and natural gas industry as a whole, are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We may respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term. Refer to Prices and Realizations below for information on our realized prices. 27 The following table presents the average daily benchmark prices for oil and natural gas during the periods presented: Three months ended Six months ended June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023 Brent oil ($/Bbl) $ 85.00 $ 81.84 $ 83.42 $ 80.12 WTI oil ($/Bbl) $ 80.57 $ 76.96 $ 78.77 $ 74.95 NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price $ 1.89 $ 2.24 $ 2.07 $ 2.76 Regulatory Updates Setbacks and Senate Bill No. 1137 California Senate Bill No. 1137 establishes 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public and separately imposing a number of potential impact analysis and mitigation and reporting requirements. The implementation of Senate Bill No. 1137 was stayed pending the outcome of a voter referendum to repeal the bill on the November 2024 ballot. However, this referendum was withdrawn on June 27, 2024 and the requirements of Senate Bill No. 1137 are no longer stayed. The majority of our production is in rural areas in the San Joaquin basin and is not affected by Senate Bill No. 1137. In addition to the write-down of reserves previously recorded in 2023, we continue to evaluate the location of projects near setback zones and believe any further reductions to the net present value of our proved undeveloped reserves as a result of the withdrawal of the voter referendum and the implementation of Senate Bill No. 1137 would be less than $14 million based on 2023 SEC prices (with an insignificant impact on our overall proved reserves). Well Permitting Status 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 approvals for workovers has continued in the course of the first half of 2024. As of June 30, 2024, we have received 364 permits for workovers (including permits received by Aera) since the beginning of the year. In July 2024, following discussions with CalGEM and further internal review of our development portfolio, we relinquished eight permits for deepenings that we had received in April and May 2024. In May and June 2024, CalGEM issued a number of new well permits to other operators in the state. These permits were issued outside of Kern County or in reliance on an environmental impact analysis other than the Kern County EIR to comply with CEQA. We are pursuing a similar strategy of seeking conditional use permits with respect to our Elk Hills, Buena Vista and Kern Front fields that would allow us to comply with CEQA requirements separate from the Kern County EIR. However, our ability to obtain these conditional use permits is uncertain and we may not be successful in obtaining such permits in a timely manner or at all. Following the withdrawal of the voter referendum regarding Senate Bill 1137 discussed above, CalGEM returned to operators all pending permit applications to be resubmitted with the information required under that law. CRC and Aera resubmitted substantially all permit applications in accordance with the requirements of this law, excluding permit applications for approximately 150 workovers and approximately 40 deepenings and sidetracks located in setback zones. The resubmission of these permit applications may result in further delays with CalGEM, including with respect to permit applications for wells not located in setback zones. 28 CCS Project Permitting Status On June 4, 2024, Kern County released a Draft Recirculated Environmental Impact Report (DREIR) in connection with our application for conditional use permits for our CTV I CCS project. As expected, the public comment period closed on July 18, 2024 and the project is scheduled for consideration by the Kern County Planning Commission on August 22, 2024, at which time the Planning Commission will decide whether to recommend the adoption of changes to the zoning ordinance and certification of the DREIR to the Board of Supervisors. The Board of Supervisors is scheduled to meet to consider this matter later this year. Water Injection Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to oversight by the City of Long Beach and CalGEM. Following discussions with the City of Long Beach and CalGEM with respect to the level of injection well pressure gradient needed to comply with CalGEM’s requirements for the protection of underground aquifers, while at the same time mitigating subsidence risks, CalGEM provided a directive to reduce the injection well pressure in a gradual manner. In response to this directive, we were required to implement a five-year injection reduction work plan. The first phase of reduction commenced July 1, 2024, and focuses on reducing pressure gradients in the zones at higher starting pressure. We continue to evaluate the work plan with CalGEM, including any subsidence risk, and the work plan may be adjusted further in the future. Given this uncertainty, it is difficult to predict with certainty the impact to production and reserves. However, assuming no adjustments to the current work plan, we currently estimate on a preliminary basis that the net present value of our proved developed reserves would be negatively impacted by less than 1%. We also estimate on a preliminary basis, a negative impact on production of approximately 1 MBoe/d at the end of the 5-year work plan. These estimates are preliminary and could change materially pending the results of our year-end reserve process and technical audits. Activism Opposition toward oil and gas drilling and development activity has been growing over time. Companies in the oil and gas industry are often the target of efforts to delay or prevent oil and gas development by non-governmental organizations and individuals. This opposition also extends to our carbon management business as certain activists oppose carbon capture and sequestration efforts by the oil and gas industry. These activists use a variety of tactics that primarily rely on allegations regarding safety, environmental compliance and business practices. At both the state and federal level, these tactics include seeking changes to laws, pressuring governmental agencies to promulgate regulations or engage in rulemaking, or pursuing litigation. For example, we are currently a named real party in interest in Center for Biological Diversity v. City of Long Beach, Long Beach City Council, California State Lands Commission, et al. , a lawsuit brought by an environmental non-governmental organization that seeks the shut down of the Long Beach Unit on the basis of a purported CEQA violation by certain governmental entities. While we believe that the defendants will prevail in this matter and do not otherwise expect its disposition will result in a material adverse effect on our business or operations, we cannot predict the outcome of any litigation with certainty. 29 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 Six months ended June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023 Oil (MBbl/d) San Joaquin Basin 30 30 30 35 Los Angeles Basin 17 18 17 19 Total 47 48 47 54 NGLs (MBbl/d) San Joaquin Basin 10 11 11 11 Total 10 11 11 11 Natural gas (MMcf/d) San Joaquin Basin 99 90 94 119 Los Angeles Basin 1 1 1 1 Sacramento Basin 14 14 14 16 Total 114 105 109 136 Total Net Production (MBoe/d) 76 76 76 88 Total daily net production for the three months ended June 30, 2024 remained flat compared to the three months ended March 31, 2024. Total daily net production for the three months ended March 31, 2024 was negatively impacted by 3 Mboe/d due to scheduled maintenance at our Elk Hills power plant. Total daily net production for the three months ended June 30, 2024 was also negatively impacted by approximately 3 Mboe/d as a result of scheduled maintenance and unplanned downtime at our Elk Hills power plant. Our PSCs, which are described below, did not have a significant impact on our net oil production in the three months ended June 30, 2024 compared to the three months ended March 31, 2024. Total daily net production decreased by 12 Mboe/d from 88 MBoe/d during the six months ended June 30, 2023 to 76 Mboe/d during the six months ended June 30, 2024 primarily due to natural production decline, downtime at our Elk Hills power plant as well as the divestiture of our share of a non-operated field in December 2023. Our PSCs, which are described below, negatively impacted our net oil production by 1 MBoe/d in the six months ended June 30, 2024 compared to the six months ended June 30, 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 Six months ended June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023 (MBoe/d) Total Net Production 76 76 76 88 Partners' share under PSCs 7 7 7 6 Working interest and royalty holders' share 7 7 6 8 Changes in NGL inventory and other 3 4 4 1 Total Gross Production 93 94 93 103 30 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 that are in effect through the economic life of the assets. The reporting of our PSCs creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. Operating costs, excluding effects of PSCs, is a non-GAAP measure which adjusts for excess costs attributable to PSCs for the periods presented in the tables below: Three months ended June 30, 2024 March 31, 2024 (in millions) ($ per Boe) (in millions) ($ per Boe) Operating costs (a) $ 159 $ 23.14 $ 179 $ 25.80 Excess costs attributable to PSCs (17) (2.48) (18) (2.54) Operating costs, excluding effects of PSCs $ 142 $ 20.66 $ 161 $ 23.26 (a) Operating costs related to our exploration and production activities and are presented before elimination entries. Six months ended June 30, 2024 June 30, 2023 (in millions) ($ per Boe) (in millions) ($ per Boe) Operating costs (a) $ 338 $ 24.48 $ 440 $ 27.71 Excess costs attributable to PSCs (35) (2.51) (35) (2.19) Operating costs, excluding effects of PSCs $ 303 $ 21.97 $ 405 $ 25.52 (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. 31 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 June 30, 2024 March 31, 2024 Price Realization Price Realization Oil ($ per Bbl) Brent $ 85.00 $ 81.84 Realized price without derivative settlements $ 83.14 98% $ 80.16 98% Derivative settlements (1.85) (2.99) Realized price with derivative settlements $ 81.29 96% $ 77.17 94% WTI $ 80.57 $ 76.96 Realized price without derivative settlements $ 83.14 103% $ 80.16 104% Realized price with derivative settlements $ 81.29 101% $ 77.17 100% NGLs ($ per Bbl) Realized price (% of Brent) $ 46.96 55% $ 50.50 62% Realized price (% of WTI) $ 46.96 58% $ 50.50 66% Natural gas NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 1.89 $ 2.24 Realized price ($/Mcf) $ 1.78 94% $ 3.90 174% 32 Six months ended June 30, 2024 June 30, 2023 Price Realization Price Realization Oil ($ per Bbl) Brent $ 83.42 $ 80.12 Realized price without derivative settlements $ 81.63 98% $ 77.25 96% Derivative settlements (2.43) (13.90) Realized price with derivative settlements $ 79.20 95% $ 63.35 79% WTI $ 78.77 $ 74.95 Realized price without derivative settlements $ 81.63 104% $ 77.25 103% Realized price with derivative settlements $ 79.20 101% $ 63.35 85% NGLs ($ per Bbl) Realized price (% of Brent) $ 48.76 58% $ 50.88 64% Realized price (% of WTI) $ 48.76 62% $ 50.88 68% Natural gas NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price $ 2.07 $ 2.76 Realized price ($/Mcf) $ 2.81 136% $ 12.44 451% Oil — Brent prices were higher for the three months ended June 30, 2024 compared to the three months ended March 31, 2024. The increase in Brent prices is attributable to heightened geopolitical tensions as well as the OPEC+ decision to continue with voluntary production cuts of 2.2 million barrels per day. Brent prices were higher for the six months ended June 30, 2024 compared to the six months ended June 30, 2023 due to global supply and demand factors signaling a continuing supply deficit in 2024 given OPEC+ resolve. NGLs — NGL prices for the three months ended June 30, 2024 decreased compared to the three months ended March 31, 2024 reflecting traditional seasonality between quarters for NGL pricing. NGL prices for the six months ended June 30, 2024 decreased compared to the six months ended June 30, 2023 primarily as a result of the ongoing supply and demand imbalance as a result of a generally mild North American winter in 2024. Natural Gas — Natural gas prices decreased for the three months ended June 30, 2024 compared to the three months ended March 31, 2024 driven by seasonality between quarters and an abundance of natural gas in storage exiting winter. Natural gas prices decreased for the six months ended June 30, 2024 compared to the six months ended June 30, 2023. In California, specifically, these results reflect record-setting prices for the period in 2023 versus near-record levels of gas in storage across the same period in 2024. 33 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 June 30, 2024 and March 31, 2024 and the six months ended June 30, 2024 and 2023. Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs. Three months ended Six months ended June 30, 2024 March 31, 2024 June 30, 2024 June 30, 2023 ($ per Boe, except as otherwise stated) Total net production (MBoe/d) 76 76 76 88 Total oil, natural gas and NGL sales (in millions) $ 416 $ 435 $ 851 $ 1,162 Energy operating costs $ 6.40 $ 8.07 $ 7.24 $ 11.52 Gas processing costs 0.44 0.58 0.51 0.63 Non-energy operating costs 16.30 17.15 16.73 15.56 Operating costs $ 23.14 $ 25.80 $ 24.48 $ 27.71 Field general and administrative expenses (a) $ 1.31 $ 1.30 $ 1.30 $ 1.45 Field depreciation, depletion and amortization (b) $ 6.84 $ 7.06 $ 6.95 $ 6.61 Field taxes other than on income $ 4.80 $ 4.61 $ 4.71 $ 3.72 (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 June 30, 2024 compared to the three months ended March 31, 2024 as well as during the six months ended June 30, 2024 compared to the six months ended June 30, 2023. The decreases between periods were predominantly a result of lower natural gas prices, partially offset by lower production volumes between periods. Non-energy operating costs were lower on a per Boe basis during the three months ended June 30, 2024 compared to the three months ended March 31, 2024 due to less downhole maintenance activity. Non-energy operating costs were lower during the six months ended June 30, 2024 compared to the six months ended June 30, 2023 due to reduced downhole maintenance and surface maintenance activity in 2024. Non-energy operating costs were higher on a per Boe basis during the six months ended June 30, 2024 compared to the six months ended June 30, 2023 as a result of lower production volumes. Consolidated Results of Operations 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 12 Condensed Consolidated Financial Information. We closed the Aera Merger on July 1, 2024 and the Results of Operations do not contain the results of Aera for the periods presented. For more information on the Aera Merger, see Part I, Item 1 – Financial Statements, Note 13 Subsequent Events. Certain prior period balances related to NGL marketing activities have been reclassified to conform to our 2024 presentation. For the six months ended June 30, 2023, we reclassified $3 million related to NGL storage activities from other revenue to revenue from marketing of purchased commodities on our condensed consolidated statement of operations. 34 Three months ended June 30, 2024 compared to March 31, 2024 The following table presents our consolidated operating revenues for the three months ended June 30, 2024 and March 31, 2024: Three months ended June 30, 2024 March 31, 2024 (in millions) Oil, natural gas and NGL sales $ 412 $ 429 Net gain (loss) from commodity derivatives 5 (71) Revenue from marketing of purchased commodities 51 74 Electricity sales 36 15 Other revenue 10 7 Total operating revenues $ 514 $ 454 Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $412 million for the three months ended June 30, 2024, which is a decrease of $17 million compared to $429 million for the three months ended March 31, 2024. The components of the decrease in the second quarter of 2024 are shown in the table below. The effect of cash settlements on our commodity derivative contracts and the elimination of intercompany sales related to natural gas sold to our power plant are not included in the table below. Oil NGLs Natural Gas Total Operations (in millions) Three months ended March 31, 2024 (a) $ 348 $ 49 $ 38 $ 435 Change in realized prices 14 (3) (21) (10) Change in production (9) (1) 1 (9) Three months ended June 30, 2024 (b) $ 353 $ 45 $ 18 $ 416 Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods. (a) Excludes a $6 million intercompany elimination related to natural gas sold to our Elk Hills power plant. (b) Excludes a $4 million intercompany elimination related to natural gas sold to our Elk Hills power plant. Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $5 million for the three months ended June 30, 2024 compared to net loss of $71 million for the three months ended March 31, 2024. The net gain (loss) from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period. Payments on commodity derivatives were $6 million for the three months ended June 30, 2024 compared to $12 million for the three months ended March 31, 2024. Including the effect of settlement payments for commodity derivatives, the realized prices received for our oil, natural gas and NGL sales decreased by $11 million compared to the three months ended March 31, 2024. Three months ended June 30, 2024 March 31, 2024 (in millions) Non-cash commodity derivative gain (loss) $ 11 $ (59) Settlements and premiums (6) (12) Net gain (loss) from commodity derivatives $ 5 $ (71) Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities decreased $23 million to $51 million in the three months ended June 30, 2024 from $74 million in the three months ended March 31, 2024. The decrease was predominantly due to lower natural gas prices in the second quarter compared to the first quarter of 2024. Revenue from marketing of purchased commodities net of costs related to marketing of purchased commodities was $8 million for the three months ended June 30, 2024 compared to $20 million for the three months ended March 31, 2024. 35 Electricity sales — Electricity sales increased by $21 million to $36 million for the three months ended June 30, 2024 compared to $15 million for the three months ended March 31, 2024 due to fewer days of downtime at our Elk Hills power plant for maintenance in the second quarter of 2024 and higher revenue from capacity agreements coming into the summer months. The following table presents our consolidated operating and non-operating expenses and income for the three months ended June 30, 2024 and March 31, 2024: Three months ended June 30, 2024 March 31, 2024 (in millions) Operating expenses Energy operating costs $ 41 $ 53 Gas processing costs 3 4 Non-energy operating costs 112 119 General and administrative expenses 63 57 Depreciation, depletion and amortization 53 53 Asset impairment 13 — Taxes other than on income 39 38 Exploration expense — 1 Costs related to marketing of purchased commodities 43 54 Electricity generation expenses 14 8 Transportation costs 17 20 Accretion expense 13 12 Carbon management business expenses 15 8 Other operating expenses, net 51 37 Total operating expenses 477 464 Gain on asset divestitures 1 6 Operating income (loss) 38 (4) Non-operating (expenses) income Interest and debt expense (17) (13) Loss from investment in unconsolidated subsidiary (4) (3) Other non-operating (expenses) income (6) 1 Income (loss) before income taxes 11 (19) Income tax (provision) benefit (3) 9 Net income (loss) $ 8 $ (10) Energy operating costs — Energy operating costs for the three months ended June 30, 2024 were $41 million, which was a decrease of $12 million from $53 million for the three months ended March 31, 2024. This decrease was primarily the result of lower natural gas prices in the three months ended June 30, 2024. For more information on natural gas market prices, see Prices and Realizations above. Asset impairments — During the three 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 for the three months ended March 31, 2024. Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $43 million for the three months ended June 30, 2024 compared to $54 million for the three months ended March 31, 2024. The decrease of $11 million was primarily due to lower natural gas prices in the three months ended June 30, 2024 compared to the three months ended March 31, 2024. This decrease was partially offset by higher volumes of purchased third-party crude oil in the three months ended June 30, 2024. 36 Other operating expenses, net — Other operating expenses, net increased $14 million to $51 million for the three months ended June 30, 2024 compared to $37 million for the three months ended March 31, 2024. The increase was predominantly due to expenses related to transaction and integration costs related to the Aera Merger. Six months ended June 30, 2024 compared to June 30, 2023 The following table presents our operating revenues for the six months ended June 30, 2024 and June 30, 2023: Six months ended June 30, 2024 June 30, 2023 (in millions) Oil, natural gas and NGL sales $ 841 $ 1,162 Net (loss) gain from commodity derivatives (66) 73 Revenue from marketing of purchased commodities 125 259 Electricity sales 51 102 Other revenue 17 19 Total operating revenues $ 968 $ 1,615 Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $841 million for the six months ended June 30, 2024, which is a decrease of $321 million compared to $1,162 million for the six months ended June 30, 2023. This decrease was primarily due to changes in realized prices as shown in the table below, including lower realized prices for natural gas and NGLs, partially offset by higher realized prices for oil. Oil, natural gas and NGL sales were also impacted by lower production volumes across all commodities. The effect of cash settlements on our commodity derivative contracts and the elimination of intercompany sales related to natural gas sold to our power plant are not included in the table below. Oil NGLs Natural Gas Total Operations (in millions) Six months ended June 30, 2023 $ 752 $ 104 $ 306 $ 1,162 Change in realized prices 43 (4) (237) (198) Change in production (94) (6) (13) (113) Six months ended June 30, 2024 (a) $ 701 $ 94 $ 56 $ 851 Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods. (a) Excludes a $10 million intercompany elimination related to natural gas sold to our Elk Hills power plant. 37 Net (loss) gain from commodity derivatives — Net loss from commodity derivatives was $66 million for the six months ended June 30, 2024 compared to a net gain of $73 million for the six months ended June 30, 2023. The net (loss) gain from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period. Payments on commodity derivatives were $18 million for the six months ended June 30, 2024 compared to payments of $128 million for the six months ended June 30, 2023. Payments on commodity derivatives for the six months ended June 30, 2023 included settlements for hedges that were entered into at a lower commodity price due to the requirements of our Revolving Credit Facility at that time. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales decreased by $211 million compared to the six months ended June 30, 2023. Six months ended June 30, 2024 June 30, 2023 (in millions) Non-cash commodity derivative (loss) gain $ (48) $ 201 Net cash payments on settled commodity derivatives (18) (128) Net (loss) gain from commodity derivatives $ (66) $ 73 Revenue from marketing of purchased commodities — Revenue from marketing of purchased commodities was $125 million for the six months ended June 30, 2024, which was a decrease of $134 million from $259 million during the six months ended June 30, 2023. The decrease was primarily the result of lower natural gas prices in 2024 compared to 2023. This decrease was partially offset by higher sales of purchased crude oil in 2024. Revenue from marketing of purchased commodities net of costs related to marketing of purchased commodities was $28 million for the six months ended June 30, 2024 compared to $108 million for the six months ended June 30, 2023. Electricity sales — Electricity sales decreased by $51 million to $51 million for the six months ended June 30, 2024 compared to $102 million for the six months ended June 30, 2023 due to scheduled maintenance and unplanned downtime at our Elk Hills power plant in the six months ended June 30, 2024. This decrease was partially offset by higher revenues from capacity agreements due to higher prices in six months ended June 30, 2024 as compared to the prior comparative period. 38 The following table presents our operating and non-operating expenses and income for the six months ended June 30, 2024 and 2023: Six months ended June 30, 2024 June 30, 2023 (in millions) Operating expenses Energy operating costs $ 94 $ 183 Gas processing costs 7 10 Non-energy operating costs 231 247 General and administrative expenses 120 136 Depreciation, depletion and amortization 106 114 Asset impairment 13 3 Taxes other than on income 77 84 Exploration expense 1 2 Purchased natural gas marketing expense 97 151 Electricity generation expenses 22 62 Transportation costs 37 33 Accretion expense 25 23 Carbon management business expenses 23 13 Other operating expenses, net 88 21 Total operating expenses 941 1,082 Gain on asset divestitures 7 7 Operating income 34 540 Non-operating (expenses) income Interest and debt expense (30) (28) Loss from investment in unconsolidated subsidiary (7) (3) Other non-operating income (5) 2 (Loss) income before income taxes (8) 511 Income tax benefit (provision) 6 (113) Net (loss) income $ (2) $ 398 Energy operating costs — Energy operating costs for the six months ended June 30, 2024 were $94 million, which was a decrease of $89 million from $183 million for the six months ended June 30, 2023. This decrease was a result of lower natural gas prices in the six months of 2024 compared to the same prior year period. For more information on our natural gas market prices, see Prices and Realizations above. Non-energy operating costs — Non-energy operating costs were $231 million for the six months ended June 30, 2024, which was a decrease of $16 million from $247 million for the six months ended June 30, 2023. The decrease was primarily due to lower downhole and surface maintenance activities combined with more favorable vendor pricing for certain items in 2024 as a result of cost savings initiatives undertaken during 2023. General and administrative expenses — General and administrative (G&A) expenses were $120 million for the six months ended June 30, 2024, which was a decrease of $16 million from $136 million for the six months ended June 30, 2023. The decrease in G&A expenses was primarily attributable to lower compensation-related expenses. G&A expenses were also lower in the six months ended June 30, 2024 compared to the same prior year period as a result in reduced spending on information technology infrastructure. Stock-based compensation awards are discussed further below. 39 The table below shows G&A expenses for our exploration and production business (in addition to unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business do not include expenses borne by the Carbon TerraVault JV. Six months ended June 30, 2024 June 30, 2023 (in millions) Exploration and production, corporate and other $ 115 $ 130 Carbon management business 5 6 Total general and administrative expenses $ 120 $ 136 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. Stock-based compensation included in G&A expense is shown in the table below: Six months ended June 30, 2024 June 30, 2023 (in millions) Cash-settled awards $ 6 $ 8 Stock-settled awards 11 14 Total included in general and administrative expenses $ 17 $ 22 Asset impairments — Asset impairments increased $10 million to $13 million for the six months ended June 30, 2024 from $3 million for the six months ended June 30, 2023. In the six months ended June 30, 2024, our asset impairment related to the write-down of excess and obsolete materials and supplies inventory related to our oilfield operations. In the six months ended June 30, 2023, our asset impairment related to the write-down of a property to fair value when it was classified as held for sale. Taxes other than on income — Taxes other than on income were $77 million for the six months ended June 30, 2024, which was a decrease of $7 million from $84 million for the six months ended June 30, 2023. The decrease was primarily related to lower greenhouse gas expense in 2024. This decrease was partially offset by higher ad valorem taxes in the six months ended June 30, 2024 compared to the same prior year period. Costs related to marketing of purchased commodities — Costs related to marketing of purchased commodities were $97 million for the six months ended June 30, 2024, which was a decrease of $54 million from $151 million for the six months ended June 30, 2023. The decrease primarily related to lower natural gas prices in 2024 compared to 2023. Electricity generation expense — Electricity generation expenses for the six months ended June 30, 2024 were $22 million, which was a decrease of $40 million from $62 million for the same prior year period. This decrease was primarily due to lower prices for natural gas as well as downtime at our Elk Hills power plant for maintenance. 40 Carbon management business expenses — Carbon management business expenses increased by $10 million to $23 million for the six months ended June 30, 2024 from $13 million for the six months ended June 30, 2023. The increase in carbon management business expenses was predominantly due to higher easement expense and compensation-related expenses. Other operating expenses, net — Other operating expenses, net increased $67 million to $88 million for the six months ended June 30, 2024 compared to $21 million for the six months ended June 30, 2023. The increase was primarily related to transaction and integration costs for the Aera Merger as well as additional expenses related to electricity purchased during the ongoing maintenance at our Elk Hills power plant. Income taxes – The income tax benefit for the six months ended June 30, 2024 was $6 million (representing an effective tax rate of 75%), compared to a provision of $113 million (representing an effective tax rate of 22%) for the six months ended June 30, 2023. We recognized an excess tax benefit as a discrete adjustment in the six months ended June 30, 2024 related to the settlement of certain equity-settled stock-based compensation awards. See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more 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 June 30, 2024 were for capital investments, repurchases of our common stock and dividends. The following table summarizes our liquidity: June 30, 2024 (in millions) Available cash and cash equivalents (a) $ 1,030 Revolving Credit Facility: Borrowing capacity 630 Revolver balance drawn (30) Outstanding letters of credit (130) Availability $ 470 Liquidity $ 1,500 (a) Excludes an insignificant amount of restricted cash. At the time of the closing of the Aera Merger, we had available cash of $1.1 billion, which included $100 million of available cash at Aera. We used this cash to pay $990 million in connection with the extinguishment of Aera's outstanding indebtedness, and transaction costs and financing fees for the combined entity of $75 million, of which $9 million was accrued as of June 30, 2024. We amended our Revolving Credit Facility during the first quarter of 2024 which increased the aggregate commitment amount and our borrowing base as described in Part I, Item 1 – Financial Statements, Note 3 Debt and continue to evaluate refinancing options for our 2026 Senior Notes. 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 the indentures for our 2026 Senior Notes and our 2029 Senior Notes, (iii) reduce outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months. 41 Cash Flow Analysis Cash flows from operating activities — For the six months ended June 30, 2024, our operating cash flow decreased $234 million to $184 million from $418 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 six months ended June 30, 2024 compared to the same prior year period. Our average natural gas prices decreased $9.63 per Mcf from $12.44 per MMcf in the six months ended June 30, 2023 to $2.81 per Mcf during the six months ended June 30, 2024. Further, our natural gas production decreased by 27 MMcf/d from 136 MMcf/d in the six months ended June 30, 2023 to 109 MMcf/d in the six months ended June 30, 2024, also contributing to the decrease. While our realized oil price with derivative settlements increased by $15.85 per barrel to $79.20 in the six months ended June 30, 2024 from $63.35 in the same prior year period, our net oil production volumes decreased 7 MBbl/d from 54 MBbl/d in the six months ended June 30, 2023 to 47 MBbl/d in the six months ended June 30, 2024. Our total net production volumes decreased by 12 MBoe/d from 88 MBoe/d in the six months ended June 30, 2023 to 76 MBoe/d for the six months ended June 30, 2024 primarily due to 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 six months ended June 30, 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: Six months ended June 30, 2024 2023 (in millions) Capital investments $ (88) $ (86) Changes in accrued capital investments 2 (15) Proceeds from divestitures, net 12 — Acquisitions (6) (1) Other, net (2) (3) Net cash used in investing activities $ (82) $ (105) In March 2024, we sold our 0.9-acre Fort Apache real estate property in Huntington Beach, California for $10 million. For more information on our divestiture in the three months ended March 31, 2024, see Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions. 42 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, 2024 2023 (in millions) Proceeds from Revolving Credit Facility $ 30 $ — Proceeds from 2029 Senior Notes, net 590 — Repurchases of common stock (a) (93) (123) Common stock dividends (43) (40) Payments on equity-settled awards (4) — Issuance of common stock 3 1 Bridge loan commitment costs (5) — Debt amendment costs (3) (8) Shares cancelled for taxes (42) (2) Net cash provided by (used in) financing activities $ 433 $ (172) (a) The total value of shares purchased includes approximately $1 million in both the six months ended June 30, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented. 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. For more information on the terms of our stock-based compensation awards, refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 9 Stock-Based Compensation in our 2023 Annual Report. 2024 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, 2024 was $88 million. For the combined business after completion of the Aera Merger, we expect our capital program for the second half of 2024 to range between $170 million and $210 million under current permitting conditions. Of this amount, $155 million to $185 million is related to oil and natural gas development, $10 million to $15 million is for carbon management projects and $5 million to $10 million is for corporate and other. We expect to run a one rig program for the remainder of 2024 executing projects using existing permits. Refer to Regulatory Updates above for more information on permitting. 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. 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, 2024. See Part I, Item 1 – Financial Statements, Note 5 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of June 30, 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. 43 Dividends On August 2, 2024, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.55 , payable to shareholders in quarterly increments of $0.3875 per share of common stock. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. On August 5, 2024 , our Board of Directors declared a quarterly cash dividend of $0.3875 per share of common stock. The dividend is payable to shareholders of record at the close of business on August 30, 2024 and is expected to be paid on September 16, 2024 . Our Board of Directors declared the following cash dividends in each of the periods presented. Total Dividend Rate Per Share (in millions) ($ per share) 2024 Three months ended March 31, 2024 $ 21 $ 0.31 Three months ended June 30, 2024 22 $ 0.31 Six months ended June 30, 2024 $ 43 2023 Three months ended March 31, 2023 $ 20 $ 0.2825 Three months ended June 30, 2023 20 $ 0.2825 Six months ended June 30, 2023 $ 40 In addition to dividends declared, we paid $4 million of dividend equivalents related to stock-based compensation awards which were settled in the six months ended June 30, 2024. The declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. Since the adoption of our dividend policy in 2021, we have returned $197 million to shareholders through dividends. For information regarding past dividends paid, see Cash Flow Analysis, Cash Flow Used in Financing Activities above. 44 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 $656 million, excluding commissions and excise taxes on repurchases, as of June 30, 2024. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend or discontinue authorization of the program at any time. The following is a summary of our share repurchases, which are held as treasury stock, for the periods presented: Total Number of Shares Purchased Total Value of Shares Purchased Average Price Paid per Share (number of shares) (in millions) ($ per share) Three months ended June 30, 2023 1,618,746 $ 64 $ 39.12 Three months ended June 30, 2024 703,839 $ 35 $ 49.71 Six months ended June 30, 2023 3,042,510 $ 123 $ 40.12 Six months ended June 30, 2024 1,769,603 $ 93 $ 51.85 Inception of Program (May 2021) through June 30, 2024 16,633,518 $ 697 $ 41.74 Note: The total value of shares purchased includes approximately $1 million in both the six months ended June 30, 2024 and 2023 related to excise taxes on share repurchases, which was effective beginning on January 1, 2023. Commissions paid on share repurchases were not significant in all periods presented. Divestitures, Acquisitions and Assets Held for Sale See Part I, Item 1 – Financial Statements, Note 7 Divestitures, Acquisitions and Assets Held for Sale for information on our divestitures and acquisitions during the three months ended June 30, 2024 and 2023. 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 June 30, 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 4 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. 45 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. 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, Ukraine and Yemen and the Red Sea; • the ability to successfully integrate Aera's business; • 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; • Our ability to claim and utilize tax credits or other incentives in connection with our CCS projects; • Our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS projects and other renewable energy efforts; • Our ability to successfully identify, develop and finance carbon capture and storage projects 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; 46 • 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. 47