EDGAR 10-K Filing

Company CIK: 1609253
Filing Year: 2025
Filename: 1609253_10-K_2025_0001609253-25-000027.json

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ITEM 1. BUSINESS
ITEMS 1 & 2 BUSINESS AND PROPERTIES
Business
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.
Our principal business consists of two segments: oil and natural gas and carbon management. The oil and natural gas segment explores for, develops and produces crude oil, oil condensate, natural gas liquids and natural gas. The carbon management segment, which we refer to as Carbon TerraVault, is expected to build, install, operate and maintain CO2 capture equipment, transportation assets and underground storage facilities. Our carbon management segment also owns an investment in the Carbon TerraVault JV. For more information on our segments, refer to Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Segment Results of Oil and Natural Gas Operations and Results of our Carbon Management Segment, and Part II, Item 8 - Financial Statements and Supplementary Data, Note 16 Segment Information.
On July 1, 2024, we obtained by way of merger all of the ownership interests in Aera. The Aera Merger added significant oil-weighted production and proved developed reserves to CRC, primarily in the San Joaquin and Ventura basins. In connection with the closing of the Aera Merger, we issued 21,315,707 shares of common stock to the former Aera owners (Sellers) and expect to issue additional shares during 2025 in connection with post-closing settlement. As of July 1, 2024, and immediately following the closing of the Aera Merger, our existing stockholders prior to the Aera Merger owned 76% of CRC and the Sellers owned 24% of CRC. We also paid approximately $990 million in connection with the extinguishment of all of Aera's outstanding indebtedness. For more information on the Aera Merger, refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Aera Merger.
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 Strategy
•Focus on integration and synergy capture of the Aera assets to enable future consolidation opportunities. We are focused on reducing costs and improving operating efficiencies as a result of the Aera Merger. In 2024, we implemented synergies that we expect will result in future annual cost savings of $170 million, and we expect to implement additional synergies in 2025 that will result in a further $65 million in such cost savings. As the largest producer in California, we believe that we will have the opportunity to acquire additional producing assets in California at attractive valuations and we expect to pursue other acquisitions within or outside of California.
•Maintain high standards of operational performance to drive profitability and create reliable cash flows. For the year ended December 31, 2024, we generated $376 million in net income including the results of Aera's operations for the second half of the year. We intend to maintain high standards for safe and environmentally responsible operations, while also seeking to drive further efficiencies in our business through innovation and lowering costs and enhance cash flows in different commodity price environments and industry cycles.
•Maintain a disciplined and flexible capital program. We expect to allocate capital among assets based on permit availability and manage field-level development. Over the short term, we intend to primarily invest in workovers and sidetracks to take advantage of permit availability. When permitting for new wells resumes, we plan to invest in developing wells with high returns and short payback metrics. We expect to fund our capital program primarily from operating cash flows and maintain a flexible approach to adapt to fluctuations in commodity prices and changes in the regulatory climate.
•Preserve balance sheet strength and shareholder returns. As of December 31, 2024, we had $1,337 million of liquidity, consisting of $983 million available for borrowing under the Revolving Credit Facility (after taking into account $167 million of outstanding letters of credit) and $354 million in cash on hand. We had $1,145 million of long term indebtedness as of the same date. By maintaining significant liquidity and low leverage, we believe we will be able to ensure a strong financial foundation that will allow us to focus on shareholder returns, including dividends and share repurchases.
•Advance our carbon management business to lead the energy transition. We are focused on maximizing the value of our land, mineral and technical resources for decarbonization by developing CCS and other emissions reducing projects. We expect to deliver industrial-scale projects to help California meet its decarbonization goals. We intend to leverage our Carbon TerraVault JV with Brookfield to reduce our capital investments to develop these projects. We are also focused on maximizing opportunities and optimizing long term value for our existing natural gas fired power generation assets, including our 550 MW power plant at Elk Hills.
•Proactively and collaboratively engage in matters related to regulation and HSE matters. We seek to work with regulators and legislators at the state and local levels in an effort to minimize potential adverse impacts that new legislation and regulations may have on our business and operations. Our commitment to health, safety and the environment (HSE) defines how we operate our business. We intend to always produce energy in a safe and responsible manner to help support and enhance the quality of life in the communities in which we operate.
•Maintain our commitment to environmental stewardship. We intend to continue efforts to reduce CO2 and methane emissions in our operations. We also intend to continue to proactively manage our idle wells and reduce our consumption of freshwater in our operations. We are committed to transparency in these efforts and intend to continue to disclose our progress regularly, including through our annual sustainability report. We expect to continue to seek third party certifications of our results and disclosure practices, such as MIQ’s certification of methane emissions.
Oil and Natural Gas Segment
The following table highlights key information about our oil and natural gas segment as of and for the year ended December 31, 2024:
San Joaquin Basin Los Angeles Basin Sacramento Basin Other Basins
Total Operations
Mineral Acreage
Net mineral acreage (thousands)
1,277 35 421 130 1,863
Average net mineral acreage held in fee (%) 89 % 55 % 47 % 88 % 79 %
Number of producing fields we operate(a)
38 4 21 2 65
Average drilling rigs 1 - - - 1
Net wells drilled and completed 8.0 - - - 8.0
Proved reserves
Oil (MMBbl) 344 77 - 22 443
NGLs (MMBbl) 33 - - 1 34
Natural gas (Bcf) 383 5 18 3 409
Total (MMBoe) 441 78 3 23 545
Oil percentage of proved reserves 78 % 99 % - % 96 % 81 %
Production
Total net production (MMBoe) 31 6 1 2 40
Average daily net production (MBoe/d)(b)
85 17 2 6 110
(a)We reduced the number of producing fields reported in 2023 by removing certain fields that were classified as abandoned, shut-in or non-producing. This change has no impact on our production volumes.
(b)2 MBoe/d of production in the Salinas Basin for the year ended December 31, 2024 is included in Other Basins. Salinas Basin production was included in the San Joaquin Basin in prior periods.
For a discussion of the regulatory issues affecting the development of our oil and natural gas properties, see Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities.
San Joaquin Basin
Commercial petroleum development in the San Joaquin basin began in the 1800s. The basin contains multiple stacked formations throughout its areal extent, and we believe that this basin provides appealing opportunities for re-development of existing wells, as well as new discoveries and unconventional play potential. The geology of the San Joaquin basin continues to yield stratigraphic and structural trap discoveries.
We have interests in oil and gas fields throughout the San Joaquin basin, including in Elk Hills, Buena Vista, Coles Levee, North Belridge and South Belridge, Kern Front, Lost Hills, Cymric, McKittrick, Midway Sunset and Coalinga.
We hold substantially all of the working and mineral interests in the Belridge field. We operate the Belridge field, which consists of the North Belridge and South Belridge fields. The Belridge field consists of waterflood and steamflood operations. In the steamfloods we utilize natural gas that is both purchased from third parties and produced from our other fields. Our operations at Belridge include a central control facility with remote automation control on over 95% of the producing wells.
We hold substantially all the working, surface and mineral interests in the Elk Hills field. We operate efficient natural gas processing facilities, including a cryogenic gas plant, with a combined gas processing capacity of 330 MMcf/d. Additionally, our Elk Hills power plant generates electricity to power our oil and gas operations at Elk Hills and other nearby producing fields. Our operations at Elk Hills also include an advanced central control facility and remote automation control on over 95% of the producing wells.
We believe our extensive 3D seismic library, which covers over 800,000 acres in the San Joaquin basin, or over 50% of our gross mineral acreage in this basin, gives us a competitive advantage in field development.
Los Angeles Basin
This basin is a northwest-trending plain about 50 miles long and 20 miles wide. Most of the significant discoveries in the Los Angeles basin date back to the 1920s. The Los Angeles basin has one of the highest concentrations per acre of crude oil in the world. We have significant operations in the Wilmington field, which is a large active oil field in this basin. Most of our Wilmington production is subject to a set of contracts similar to production-sharing contracts (PSCs) under which we first recover the capital and operating costs we incur on behalf of the state and the city of Long Beach and then receive our share of profits. See Production, Price and Cost History below for more information on our PSCs.
Sacramento Basin
The Sacramento basin is a deep, thick sequence of sedimentary deposits of natural gas within an elongated northwest-trending structural feature covering about 7.7 million acres. Exploration and development in the basin began in 1918.
Other Basins
We have oil and natural gas operations in other basins in California, including the Ventura and Salinas basins. We also have mineral interests in undeveloped acreage throughout California, including the Santa Maria basin which is located in San Luis Obispo County and Santa Barbara County.
Mineral Acreage
The following table summarizes our gross and net developed and undeveloped mineral acreage as of December 31, 2024.
San Joaquin Basin Los Angeles Basin Sacramento Basin Other
Basins
Total
(in thousands)
Developed(a)
Gross(b)
543 22 243 14 822
Net(c)
495 16 233 13 757
Undeveloped(d)
Gross(b)
918 21 222 143 1,304
Net(c)
782 19 188 117 1,106
Total
Gross(b)
1,461 43 465 157 2,126
Net(c)
1,277 35 421 130 1,863
(a)Mineral acres spaced or assigned to productive wells.
(b)Total number of mineral acres in which interests are owned.
(c)Net mineral acreage includes acreage reduced to our fractional ownership interest and interests under our PSCs.
(d)Mineral acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the mineral acreage contains proved reserves.
At December 31, 2024, 79% of our total net mineral interest position was held in fee and the remainder was leased. Of our leased acreage, approximately 85% is held by production and the remainder is subject to lease expiration if initial wells are not drilled within a specified period of time. The primary terms of our leases range from one to twenty years. The terms of these leases are typically extended upon achieving commercial production for so long as such production is maintained. Work programs are designed to ensure that the economic potential of any leased property is evaluated before expiration. In some instances, we may relinquish leased acreage in advance of the contractual expiration date if the evaluation process is complete and there is no longer a commercial reason for leasing that acreage. In cases where we determine we want to take the additional time required to fully evaluate undeveloped acreage, we have generally been successful in obtaining extensions.
If we are not able to establish production or otherwise extend lease terms, approximately 9,000 net mineral acres will expire in 2025, 6,000 net mineral acres will expire in 2026 and 7,000 net mineral acres will expire in 2027. These leases represent 2% of our total net undeveloped acreage and 1% of our total net acreage as of December 31, 2024 and these expirations, should they occur, would not have a material adverse effect on us. Historically, we have not dedicated any significant portion of our capital program to prevent lease expirations and do not expect to do so in the future.
Production, Price and Cost History
The following table sets forth information regarding our production volumes, average realized and benchmark prices and operating costs per Boe (presented before and after hedges) for the periods presented. See Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations for more information on our production activity as well as the impact of price increases of certain commodities used in our operations and on our operating costs per Boe, among other factors.
Year Ended December 31,
2024 2023
Average daily net production
Oil (MBbl/d) 80 52 55
NGLs (MBbl/d) 10 11 11
Natural gas (MMcf/d) 117 135 147
Total daily net production (MBoe/d) 110 86 91
Total production (MMBoe) 40 31 33
Average realized prices
Oil with hedge ($/Bbl) $ 75.66 $ 65.97 $ 61.80
Oil without hedge ($/Bbl) $ 76.92 $ 80.41 $ 98.26
NGLs ($/Bbl) $ 48.93 $ 48.94 $ 64.33
Natural gas without hedge ($/Mcf) $ 2.99 $ 8.59 $ 7.68
Average benchmark prices
Brent oil ($/Bbl) $ 79.84 $ 82.22 $ 98.89
WTI oil ($/Bbl) $ 75.72 $ 77.62 $ 94.23
NYMEX gas ($/MMBtu) - Average Monthly Settled Price $ 2.27 $ 2.74 $ 6.64
Operating costs per Boe
Operating costs $ 24.51 $ 26.24 $ 23.75
Operating costs, after hedges
$ 25.31 $ 26.24 $ 23.75
Oil, natural gas and NGL production for our two largest fields for the year ended December 31, 2024 are presented in the table below:
Belridge
Elk Hills
2024 2024
Average daily net production
Oil (MBbl/d) 34 14
NGLs (MBbl/d) - 7
Natural gas (MMcf/d) - 59
Total daily net production (MBoe/d) 34 31
Oil, natural gas and NGL production for our two largest fields for the years ended December 31, 2023 and 2022 are presented in the table below:
Elk Hills
Wilmington
2023 2022 2023 2022
Average daily net production
Oil (MBbl/d) 16 17 16 15
NGLs (MBbl/d) 8 8 - -
Natural gas (MMcf/d) 68 75 - -
Total daily net production (MBoe/d) 35 38 16 15
Our operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field’s stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. We can quickly scale our operating costs in response to prevailing market conditions. We believe that a significant portion of our operating costs is variable over the lifecycle of our fields.
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to PSCs that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of production and reserves to recover a portion of such capital and operating costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of contractually defined base production, and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and operating costs. However, our net economic benefit is greater when product prices are higher. These PSCs represented 12% of our total production for the year ended December 31, 2024.
In line with industry practice for reporting PSCs, we report 100% of operating costs under such contracts in operating costs on our consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSCs. This difference in reporting full operating costs but only our net share of production equally inflates our revenue and operating costs per barrel and has no effect on our net results.
The following table presents our operating costs after adjustment for excess costs attributable to PSCs for the periods presented:
Year ended December 31,
2024 2023 2022
(in millions) ($ per Boe) (in millions) ($ per Boe) (in millions) ($ per Boe)
Operating costs(a)
$ 983 $ 24.51 $ 822 $ 26.24 $ 785 $ 23.75
Excess costs attributable to PSCs (67) (1.67) (71) (2.25) (74) $ (2.23)
Operating costs, excluding effects of PSCs(b)
$ 916 $ 22.84 $ 751 $ 23.99 $ 711 $ 21.52
(a)Operating costs related to our exploration and production activities and are presented before elimination entries beginning in 2024.
(b)Operating costs, excluding effects of PSCs is a non-GAAP measure. As described above, 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. These amounts represent our operating costs after adjusting for this difference.
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:
Year ended December 31,
2024 2023 2022
(MBoe/d)
Average Net Production
110 86 91
Partners' share under PSCs 6 7 8
Working interest and royalty holders' share 9 7 6
Other 4 1 1
Average Gross Production
129 101 106
Estimated Proved Reserves and Future Net Cash Flows
The following tables summarize our estimated proved oil (including condensate), NGLs and natural gas reserves and PV-10 as of December 31, 2024. Our estimated volumes and cash flows were calculated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year (SEC Prices), unless prices were defined by contractual arrangements. For oil volumes, the average Brent spot price of $80.42 per barrel was adjusted for gravity, quality and transportation costs. For natural gas volumes, the average NYMEX gas price of $2.13 per MMBtu was adjusted for energy content, transportation fees and market differentials. All prices are held constant throughout the lives of the properties. The average realized prices for estimating our proved reserves as of December 31, 2024 were $77.91 per barrel for oil, $46.73 per barrel for NGLs and $2.71 per Mcf for natural gas.
Estimated reserves include our economic interests under PSCs in our Long Beach operations in the Wilmington field. Refer to Part II, Item 8 - Financial Statements, Supplemental Oil and Gas Information for additional information on our proved reserves.
As of December 31, 2024
San Joaquin Basin Los Angeles Basin Sacramento Basin Other
Basins
Total
Proved developed reserves
Oil (MMBbl) 314 77 - 21 412
NGLs (MMBbl) 31 - - 1 32
Natural Gas (Bcf) 347 5 15 3 370
Total (MMBoe)(a)
403 78 3 22 506
Proved undeveloped reserves
Oil (MMBbl) 30 - - 1 31
NGLs (MMBbl) 2 - - - 2
Natural Gas (Bcf) 36 - 3 - 39
Total (MMBoe) 38 - - 1 39
Total proved reserves
Oil (MMBbl) 344 77 - 22 443
NGLs (MMBbl) 33 - - 1 34
Natural Gas (Bcf) 383 5 18 3 409
Total (MMBoe) 441 78 3 23 545
Reserves to production ratio (years)(b)
14 13 3 12 14
(a)As of December 31, 2024, approximately 8% of proved developed oil reserves, 7% of proved developed NGLs reserves, 9% of proved developed natural gas reserves and, overall, 8% of total proved developed reserves are non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full production response has not yet occurred due to the nature of such projects.
(b)Calculated as total proved reserves as of December 31, 2024 divided by total production for the year ended December 31, 2024.
Changes to Proved Reserves
The components of the changes to our proved reserves during the year ended December 31, 2024 were as follows:
San Joaquin Basin Los Angeles Basin(a)
Sacramento Basin Other Basins
Total
(MMBoe)
Balance at December 31, 2023 276 92 9 - 377
Revisions related to price (9) (2) (4) - (15)
Revisions related to performance (1) 4 (1) - 2
Revisions due to California regulatory challenges
(6) (10) - - (16)
Improved recovery 1 - - - 1
Acquisitions
211 - - 25 236
Production (31) (6) (1) (2) (40)
Balance at December 31, 2024 441 78 3 23 545
(a)Includes proved reserves related to PSCs of 62 MMBoe and 76 MMBoe at December 31, 2024 and 2023, respectively.
Revisions related to price - We had net negative price-related revisions of 15 MMBoe primarily resulting from lower average realized prices in 2024 as compared to 2023, including lower natural gas realizations in 2024. These revisions included negative price-related revisions of 18 MMBoe, which were partially offset by 3 MMBoe of positive revisions from operating cost efficiencies.
Revisions related to performance - We had 2 MMBoe of net positive performance-related revisions which included positive performance-related revisions of 12 MMBoe and negative performance-related revisions of 10 MMBoe. Our positive performance-related revisions primarily related to better-than-expected well performance. Our negative performance-related revisions primarily were due to lower overall expected recovery in the San Joaquin basin.
Revisions due to California regulatory challenges - We had 7 MMBoe of negative revisions due to lower maximum allowable surface injection pressure at the Wilmington field in the Los Angeles basin. We had 1 MMBoe of negative revisions due to the impact of AB 2716 at the Inglewood field in the Los Angeles basin. We had 2 MMBoe of negative revisions due to the retraction of the SB 1137 referendum and our analysis of sensitive receptor designations. The majority of these revisions were located in the Los Angeles Basin. We had 6 MMBoe of negative revisions associated with delays in obtaining new well drilling permits. The majority of the revisions related to permits was in the San Joaquin basin. See Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities.
Improved recovery - We added 1 MMBoe related to increased well performance in certain areas in the San Joaquin basin.
Acquisitions - We acquired 236 MMBoe in the Aera Merger. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Aera Merger for more information on this transaction.
Proved Undeveloped Reserves
The total changes to our proved undeveloped reserves during the year ended December 31, 2024 were as follows:
San Joaquin Basin Los Angeles Basin Sacramento Basin Other Basins
Total
(MMBoe)
Balance at December 31, 2023
41 4 1 - 46
Revisions related to price (3) - - - (3)
Revisions related to performance (4) - (1) - (5)
Revisions due to California regulatory challenges
(6) (4) - - (10)
Improved recovery 1 - - - 1
Acquisitions
11 - - 1 12
Transfers to proved developed reserves (2) - - - (2)
Balance at December 31, 2024 38 - - 1 39
Revisions related to price - We had 3 MMBoe of net negative price-related revisions primarily resulting from lower average realized prices in 2024 as compared to 2023, including lower natural gas realizations in 2024. Our negative price revisions of 3 MMBoe were partially offset by insignificant positive revisions from operating cost efficiencies.
Revisions related to performance - We had 5 MMBoe of net negative performance-related revisions due to low performance of recent drilling and subsequent type curve updates in the San Joaquin basin. Negative performance-revisions of 5 MMBoe were partially offset by insignificant positive revisions related to well performance in the San Joaquin basin.
Revisions due to California regulatory challenges - We removed 10 MMBoe from proved undeveloped reserves due to the regulatory changes discussed above. The majority of these revisions were located in the San Joaquin basin and the Los Angeles basin. See Regulation of the Industries in Which We Operate, Regulations of Exploration and Production Activities.
Improved recovery - We added 1 MMBoe related to increased well performance in certain areas in the San Joaquin basin.
Acquisitions - We acquired 12 MMBoe in the Aera Merger. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Aera Merger for more information on this transaction.
Transfers to proved developed reserves - We converted 2 MMBoe of proved undeveloped reserves to proved developed reserves in the Los Angeles basin. This resulted in a conversion rate of 4% of our beginning-of-year proved undeveloped reserves, with an investment of $44 million in drilling and completion capital. We plan to continue drilling sidetracks in 2025 and, subject to the availability of permits, expect to increase our rig count in the second half of the year. We believe that we will be able to develop all year-end 2024 proved undeveloped reserves within five years of their original booking date. For more information on the 2025 Capital Program, see Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Uses of Cash and for more information on permitting, refer to Regulation of the Industries in Which We Operate, Regulations of Exploration and Production Activities.
PV-10 and Standardized Measure
PV-10 of cash flows is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC Prices. Calculation of PV-10 does not give effect to derivative transactions. Our PV-10 is computed on the same basis as our standardized measures of future net cash flows, the most comparable measure under GAAP, but does not include the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.
As of December 31, 2024
(in millions)
Standardized measure of discounted future net cash flows $ 6,702
Present value of future income taxes discounted at 10% 2,175
PV-10 of cash flows(a)
$ 8,877
(a)The average realized prices for estimating our PV-10 of cash flow as of December 31, 2024 were $77.91 per barrel for oil, $46.73 per barrel for NGLs and $2.71 per Mcf for natural gas.
Reserves Evaluation and Review Process
Our estimates of proved reserves and related discounted future net cash flows as of December 31, 2024 were made by our technical personnel, comprised of reservoir engineers and geoscientists, with the assistance of operational and financial personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and management's funding commitments to develop the reserves. Reserves volumes are estimated by forecasts of production rates, operating costs and capital investments. Price differentials between specified benchmark prices and realized prices and specifics of each operating agreement are then applied against the SEC Price to estimate the net reserves. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities related to the proved reserves. See Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates for further discussion of uncertainties inherent in the reserve estimates.
Proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods, for which the incremental cost of any additional required investment is relatively minor. Proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.
Our Director of Reserves is the technical person who is primarily responsible for overseeing the preparation of our reserves estimates in compliance with the SEC rules and regulations. He has over 15 years of experience in the upstream oil and gas industry, with projects ranging from appraisal of primary production reservoirs to enhanced oil recovery floods. He holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines.
We have an Oil and Gas Reserves Review Committee (Reserves Committee), consisting of senior corporate officers, to review and approve our oil and natural gas reserves for 2024. The Reserves Committee annually reports its findings to the Audit Committee.
Audits of Reserves Estimates
Netherland, Sewell & Associates, Inc. (NSAI) was engaged to provide independent audits of our reserves estimates for our fields. For the year ended December 31, 2024, NSAI audited 85% of our total proved reserves.
Our independent reserve engineers examined the assumptions underlying our reserves estimates, adequacy and quality of our work product and estimates of future production rates. They also examined the appropriateness of the methodologies employed to estimate our reserves as well as their categorization, using the definitions set forth by the SEC, and found them to be appropriate. As part of their process, they developed their own independent estimates of reserves for those fields that they audited. When compared on a field-by-field basis, some of our estimates were greater and some were less than the estimates of our independent reserve engineers. Given the inherent uncertainties and judgments in estimating proved reserves, differences between our estimates and those of our independent reserve engineers are to be expected. The aggregate difference between our estimates and those of the independent reserve engineers was less than 10%, which was within the Society of Petroleum Engineers (SPE) acceptable tolerance.
In the conduct of the reserves audits, our independent reserve engineers did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, crude oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if anything came to the attention of our independent auditors that brought into question the validity or sufficiency of any such information or data, they would not rely on such information or data until they had resolved their questions relating thereto or had independently verified such information or data. Our independent reserve engineers determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC as well as the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions. Our independent reserve engineers issued an unqualified audit opinion on the applicable portions of our proved reserves as of December 31, 2024, which is attached as Exhibit 99.1 to this Form 10-K and incorporated herein by reference.
NSAI qualifications - The primary technical engineer responsible for our audit is a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2006 and has over 5 years of prior industry experience. The primary geologist for our audit is a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience.
Drilling Statistics
The following table sets forth information on our net exploration and development wells drilled and completed during the periods indicated, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. We refer to gross wells as the total number of wells in which interests are owned, including outside operated wells. Net wells represent wells reduced to our fractional interest. For information on our 2025 capital program, see Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Uses of Cash and for information on the California regulatory environment and our ability to obtain permits, see Regulation of the Industries in Which We Operate.
San Joaquin Basin Los Angeles Basin Sacramento Basin Other Basins
Total Net Wells
Productive
Exploratory - - - - -
Development 8.0 - - - 8.0
Dry
Exploratory - - - - -
Development - - - - -
Productive
Exploratory - - - - -
Development 4.0 26.5 - - 30.5
Dry
Exploratory - - - - -
Development - - - - -
Productive
Exploratory - - - - -
Development 114.3 35.0 - - 149.3
Dry
Exploratory - - - - -
Development - - - - -
The following table sets forth information on our development wells where drilling was either in progress or pending completion as of December 31, 2024.
San Joaquin Basin Los Angeles Basin Sacramento Basin Other Basins
Total Net Wells
Gross 2.0 - - - 2.0
Net 2.0 - - - 2.0
Productive Wells
Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce at a reasonable rate of return. Our average working interest in our producing wells was 97% as of December 31, 2024. Wells are categorized based on the primary product they produce.
The following table sets forth our productive oil and natural gas wells (both producing and capable of production) as of December 31, 2024, excluding wells that have been idle for more than five years:
As of December 31, 2024
Productive Oil
Wells Productive Natural Gas Wells
Gross(a)
Net(b)
Gross(a)
Net(b)
San Joaquin Basin 15,056 14,712 110 108
Los Angeles Basin 1,709 1,617 - -
Sacramento Basin - - 253 237
Other Basins
629 629 597 558
Total 17,394 16,958 960 903
Multiple completion wells included in the total above 179 176 16 13
(a)The total number of wells in which interests are owned.
(b)Net wells include wells reduced to our fractional interest.
Exploration Inventory
We have had minimal investment in exploration activity in recent years, and our 2025 capital plan does not allocate any capital towards exploration drilling.
Marketing Arrangements
Our oil, natural gas and NGL sales for the years ended December 31, 2024, 2023 and 2022 are shown in the table below. For more information on our revenues, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 15 Revenue.
Year ended December 31,
2024 2023 2022
(in millions)
Oil $ 2,255 $ 1,534 $ 1,968
NGLs 186 198 264
Natural gas 96 423 411
Oil, natural gas and NGL sales $ 2,537 $ 2,155 $ 2,643
Crude Oil
We sell nearly all of our crude oil to California refiners. A majority of our crude oil production is connected to third-party pipelines and California refining markets via our gathering systems. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.
The prices paid by California refiners have been typically based on local postings that are closely tied to Brent prices. Beginning in 2025, the marketing arrangements for the majority of our production will no longer rely on local postings but will instead be based directly on Brent prices subject to applicable adjustments. International waterborne-based Brent prices are relevant because there is limited crude pipeline infrastructure available to transport crude overland from other parts of the United States into California. We believe that these limitations will continue to contribute to higher realizations in California than most other U.S. oil markets for comparable grades.
In October 2024, Phillips 66 announced that it plans to close its Wilmington refinery in Los Angeles in late 2025. For the six-month period following the Aera Merger, we sold approximately 8% of our production to this refinery. Following the closure of the Phillips 66 refinery, there will be seven remaining major petroleum refineries in California, each of which have a refining capacity greater than 75,000 barrels per day. Due to the significant excess of refining capacity in California versus the quantity of crude oil produced locally, we do not expect the closure of this refinery to affect our ability to market our crude oil production, or to negatively impact our price realizations.
Natural Gas
We sell all of our natural gas not used in our operations into the California market. A majority of these sales are made at index based prices. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity between the market and producing areas. Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and Canada.
In addition to selling natural gas, we also use natural gas in steam generation for our steamfloods and for power generation. We have entered into derivative contracts to provide price protection for the purchase of natural gas used in our operations. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 7 Derivatives for more information on our natural gas derivative contracts.
NGLs
NGL prices vary by liquid type and realizations are closely correlated to the different commodity prices to which they relate. Prices can also fluctuate due to the demand for certain chemical products (for which NGLs are used as feedstock) and due to infrastructure constraints and seasonality. Finally, our results are also affected by the performance of our natural gas-processing plants. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the remaining products as NGLs. The efficiency with which we extract liquids from the wet gas stream affects our production volumes and operating results. Our natural gas-processing plants also facilitate access to third-party delivery points near the Elk Hills field.
We currently have a ship-or-pay pipeline transportation contract for approximately 6,000 barrels per day of NGLs through March 2026. Our contract to transport NGLs requires us to cash settle any shortfall between the contractual throughput minimums and volumes actually shipped. We have met all our throughput minimums under this contract for the periods presented.
Delivery Commitments
We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs, including delivery commitments obtained as part of the Aera Merger. As of December 31, 2024, we had the following delivery commitments as shown in the table below.
2025 2026 2027 2028 2029
Oil (MMBbl) 35 27 20 3 -
NGL (MMBbl) 1 - - - -
Natural gas (Bcf) 23 - - - -
We expect to fulfill our delivery commitments predominantly from our production and to a lesser extent from third party volumes acquired in connection with our marketing activities. We typically enter into index-based contracts with prices set at the time of delivery.
Our Principal Customers
We sell crude oil, natural gas and NGLs to California refineries, marketers and other purchasers that have access to transportation and storage facilities. Our ability to sell our products can be affected by a variety of factors that are beyond our control. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 1 Nature of our Business, Summary of Significant Accounting Policies and Other for more information on our customers.
Title to Properties
As is customary in the oil and natural gas industry for acquired properties, we initially conduct a high-level review of the title to our properties at the time of acquisition. Individual properties may be subject to ordinary course burdens that we believe do not materially interfere with the use or affect the value of such properties. Burdens on properties may include customary royalty or net profits interests, liens incident to operating agreements and tax obligations or duties under applicable laws, or development and abandonment obligations, among other items. Prior to the commencement of drilling operations on those properties, we typically conduct a more thorough title examination and may perform curative work with respect to significant defects. We generally will not commence drilling operations on a property until we have cured known title defects that are material to the project. For additional information on properties that secure our debt, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 5 Debt.
Competition
Our competitors are primarily other exploration and production companies that produce oil, natural gas and NGLs. We compete locally against independent producers and a major international oil company which operate in California. We also compete with foreign oil and gas companies since California imports approximately 75% of the oil it consumes and approximately 90% of its natural gas needs. We believe that our proximity to the California refineries gives us a competitive advantage over importers due to lower transportation costs. Further, California refineries are generally designed to process crude with the unique characteristics which are similar to our produced oil. The California natural gas market is serviced from a network of pipelines, including interstate and intrastate pipelines. We deliver our natural gas to customers using our firm capacity contracts.
We compete for third-party services to profitably develop our assets, to find or acquire additional reserves, to sell our production and to find and retain qualified personnel. The regulatory environment in California could negatively impact the number of oil field service providers, drilling and workover rigs, pipe and other oil field equipment in the state. However, we have not experienced shortages or delays in the delivery of materials or services from our vendors.
Carbon Management Segment
Our carbon management segment, which we refer to as Carbon TerraVault, pursues the development of carbon capture and sequestration projects. We expect that our Carbon TerraVault CCS projects will inject CO2 captured from industrial, power, agriculture and other emissions sources into subsurface reservoirs and permanently store CO2 deep underground. We also expect to invest in projects that rely on CCS technology in connection with reducing our own emissions. In addition, we may participate in the development of projects that are the source of these CO2 emissions.
EPA Class VI Permits
We are in the early stages of developing several CCS projects in California. In December 2024, the EPA issued Class VI permits, the first permits issued in California, for underground injection and storage of CO2 into the 26R reservoir which is located at our Elk Hills field. The permits became effective on February 6, 2025. The 26R reservoir is part of our joint venture with Brookfield as discussed further below.
We have submitted permit applications with the EPA for another permanent sequestration project at our Elk Hills field, four permanent sequestration projects in the Sacramento Basin and one permanent sequestration project in Central California that are under review by the EPA. We acquired one permit application with the EPA for sequestration projects in the Belridge field as part of the Aera Merger. Our permit applications are subject to additional review and approval by the EPA.
CCS Projects
In January 2025, we announced the approval of the installation of carbon capture equipment at our cryogenic gas processing facility at the Elk Hills field which will remove CO2 from inlet gas and which will be injected into the nearby 26R storage reservoir owned by the Carbon TerraVault JV. We expect this project will increase operational efficiency of the cryogenic gas processing plant, improving propane recovery, and reduce the carbon intensity of the electricity generated from our Elk Hills Power Plant. Our expected capital investment for this project is $14 million to $18 million with operations expected to commence in late 2025. We are also evaluating the feasibility of developing a carbon capture system for our 550-megawatt Elk Hills power plant (CalCapture). We continue to work with a consortium of industry participants to advance the development of a direct air capture hub to be located in Kern County and have been selected for a U.S. Department of Energy grant for this project as discussed further below.
We expect that the size and scope of our projects providing these and similar services and the related capital spent on such projects will continue to grow given our strategy of expansion into these services and the development of our carbon management segment. For more information about the risks involved in our carbon management segment, see Part I, Item 1A - Risk Factors.
Carbon TerraVault JV
In August 2022, we entered into a joint venture with Brookfield. We hold a 51% interest in the Carbon TerraVault JV and Brookfield holds a 49% interest. Our initial contribution included rights to inject CO2 into the 26R reservoir in our Elk Hills field for permanent CO2 storage. Brookfield has contributed $92 million to date. The remaining amount of Brookfield's initial investment will depend on the amount of storage capacity that is permitted subject to certain contractual adjustments. The parties have certain put and call rights with respect to the 26R reservoir if certain milestones are not met. As noted above, on December 30, 2024, the EPA issued Class VI permits to the Carbon TerraVault JV for the CTV I storage site.
Both Brookfield and CRC have granted the other party a right to participate in projects that involve the capture, transportation and storage of CO2 in California. These projects may be developed throughout the Carbon TerraVault JV or other joint ventures. This right expires upon the earlier of (1) August 2027, (2) when a final investment decision has been approved by the investment committee of the Carbon TerraVault JV for storage projects representing in excess of 5 million metric tons per annum (MMTPA) in the aggregate, or (3) when Brookfield has made contributions to the joint venture in excess of $500 million (unless Brookfield elects to increase its commitment). The non-presenting party has the option to accept, decline or defer its decision to participate. If the decision is deferred, then the presenting party may continue to pursue development; however during this time and prior to a final investment decision, the non-presenting party may elect to participate provided they pay their share of the project development costs incurred up to that point. The joint venture does not have a definitive term and terminates upon either party holding all of the ownership interests in the joint venture.
Refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 4 Investments and Related Party Transactions for more information on our Carbon TerraVault JV.
Competition
In our carbon management segment, we compete with other potential storage providers to acquire and develop storage reservoirs and enter into agreements with existing and future emission sources.
Infrastructure
Our infrastructure includes the plants and facilities shown in the table below, inclusive of our assets used in power generation and oil and natural gas operations.
Description Quantity Unit Capacity
San Joaquin Basin Other Basins Total
Gas Processing Plants
MMcf/d 335 10 345
Power Plants(a)
MW 791 - 791
Steam Generators/Plants
MBbl/d 380 - 380
Compressors 1,231 MHp 346 31 377
Water Management Systems
MBw/d 3,422 420 3,842
Water Softeners
MBw/d 250 - 250
Oil and NGL Storage
MBbls 689 46 735
Pipelines
Miles >11,000
(a)Includes 120 MW attributable to our 50% interest in the Midway Sunset Power Plant. Does not include the Long Beach Unit Power Plant described below or microturbines that generate limited power.
Power Plants
We own and/or operate the following power generation facilities:
Elk Hills Power Plant - We own a 550 MW combined-cycle cogeneration power plant, located adjacent to the Elk Hills natural gas processing facility. Approximately a third of the electricity generated from this plant is used in our oil and natural gas operations at Elk Hills. The balance of the power capacity is currently marketed into the resource adequacy market with excess energy produced being sold into the CAISO wholesale market.
Midway Sunset Power Plant - Following the Aera Merger, we own a 50% interest in a 240 MW cogeneration power plant located in the Midway Sunset field in Kern County, California and the remaining 50% is held by San Joaquin Energy Company, a subsidiary of NRG Energy, Inc. Our investment in this joint venture is accounted for using the equity method of accounting as discussed in Part II, Item 8 - Financial Statements and Supplementary Data, Note 4 Investments and Related Party Transactions. The electricity generated by this plant is sold to CAISO and the facility also participates in the resource adequacy capacity market.
Belridge Power Plant - Following the Aera Merger, we own a 62 MW cogeneration power plant located in the Belridge field in Kern County, California. The electricity generated by this plant is used in our operations.
Long Beach Unit Power Plant - We operate a 48 MW power generating facility that is owned by the Long Beach Unit in the Wilmington field. The electricity generated by this plant is used in our operations.
In addition, we own and/or operate a number of smaller gas-fired power plants that are primarily used to generate power for our oil and natural gas operations.
Other Infrastructure Assets Used in Oil and Natural Gas Segment
Gas processing infrastructure used in our oil and gas segment includes the Elk Hills cryogenic gas plant with a capacity of 200 MMcf/d of inlet gas and one low temperature separation plant used as a backup facility. Our natural gas processing facilities are interconnected via pipelines to nearby third-party rail and trucking facilities, with access to various North American NGL markets. In addition, we have truck rack facilities coupled with a battery of pressurized storage tanks at our natural gas processing facilities for NGL sales to third parties. We own, control and operate water management and steam-generation infrastructure. We soften and self-supply water to generate steam, reducing our operating costs. This is integral to our operations in the San Joaquin basin and supports our high-margin oil fields. Our tank storage capacity throughout California gives us flexibility for a period of time to store crude oil and NGLs, allowing us to continue production and avoid or delay any field shutdowns in the event of temporary power, pipeline or other shutdowns. Our pipelines are dedicated almost entirely to collecting our oil and natural gas production and are in close proximity to field-specific facilities such as tank farms or central processing sites. Our oil pipelines connect to multiple third-party transportation pipelines. In addition, virtually all of our natural gas facilities connect with major third-party natural gas pipeline systems.
Human Capital Management
We had approximately 1,550 employees as of December 31, 2024 as compared to approximately 970 as of December 31, 2023, all of whom were located in the United States. The significant growth in headcount was due to the employees who joined CRC following the Aera Merger. Approximately 240 of our employees are covered by a collective bargaining agreement. We also utilize the services of many third-party contractors throughout our operations.
Development
Employee development opportunities are provided to enhance leadership development and expand career opportunities. Our employees undergo mandatory annual training on our policies including health and safety, business ethics, harassment, IT security and others. In addition to training, our employees receive regular performance and career development discussions from their direct managers. All employees receive annual performance reviews.
Diversity
Our goal is to foster an open and diverse culture and we are committed to advancing a workplace culture inclusive of all backgrounds and perspectives. We believe this encourages workforce engagement and leads to more thoughtful and innovative business decisions.
Safety
Our unwavering commitment to health, safety and the environment defines how we operate our business. We prepare our workforce to work safely through comprehensive training, safe work practices, technology and rigorous maintenance and asset integrity programs. Each year, we set thresholds for TRIR and spill prevention as quantitative metrics that directly impact incentive compensation for all of our employees. We achieved a 99.999% oil spill prevention rate in 2024 and registered a workforce TRIR of 0.39 (including Aera's results following the Aera Merger). We have achieved exemplary safety performance over the last several years by promoting a culture of safety where all employees, contractors and vendors are empowered with Stop Work Authority to cease any activity - without repercussions - to prevent a safety or environmental accident.
Engagement and Retention
We survey our employees annually to ensure employee sentiment is collected and heard each year allowing us to assess engagement levels and drivers to determine areas of improvement to enhance engagement and retention. The results of the engagement surveys are reviewed by senior management and our Board of Directors. Senior leadership also hosts regular townhalls so employees can engage with them through question-and-answer sessions.
Regulation of the Industries in Which We Operate
Our operations are subject to a wide range of federal, state and local laws and regulations. Those that specifically relate to oil and natural gas exploration and production and carbon sequestration, utilization and storage are described in this section. CalGEM is the primary regulator of the oil and natural gas production industry in California. The State Lands Commission provides additional administration of the state’s surface and mineral interests.
Regulation of Exploration and Production Activities
Well Permitting
During 2024, we continued to experience delays from CalGEM with respect to obtaining new well, sidetrack, deepening and workover permits for our operations. These delays are a result of various factors, including more stringent environmental reviews in connection with permitting, limited resources at CalGEM, and policy directives that are outside of our control.
During 2024, we (including our Aera subsidiary) received well permits for 799 workovers and 145 sidetracks.
New Production Permits
Since December 2022, CalGEM has issued a limited number of permits to other operators for new production wells in California. In 2024, CalGEM issued 77 new well permits to other operators, 40 of which were for oil and natural gas production wells and 37 of which were for injection and observation wells. These permits were issued for wells outside of Kern County or within Kern County but in reliance on authority other than the Kern County EIR discussed below.
We continue to pursue an alternative path for the permitting of wells in Kern County other than in reliance on the Kern County EIR. We have submitted applications for conditional use permits (CUPs) for projects at our Aera subsidiary's Belridge field and our Kern Front, Elk Hills and Buena Vista fields. Timing for completion of the CUP application processes is difficult to estimate and could extend into the first half of 2026. Our ability to obtain the CUPs is uncertain and we may not be successful in obtaining such permits in a timely manner or at all.
Sidetrack, Deepening and Workover Permits
CalGEM finalized its procedures for the review of permit applications for workovers in December 2023 and its lead agency review process for sidetrack permits in September 2024 and recently resumed evaluation of permits for deepenings. Following the adoption of these procedures, we experienced an increase in the issuance by CalGEM of permits for workovers and sidetracks during the course of 2024. However, the rate of issuance of permits for deepening wells has not increased.
We cannot guarantee that the issues described above or new ones that may arise in the future will not continue to delay or otherwise impair our ability to obtain drilling permits. Any continuing failure to obtain certain permits or the adoption of more stringent permitting requirements could have a material adverse effect on our business, results of operations and our financial condition. See Part 1, Item IA - Risk Factors, We may face material delays related to our ability to timely obtain permits necessary for our operations or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.
Kern County EIR Litigation
In 2015 the Kern County Board of Supervisors (i) approved the county’s adoption of an ordinance providing for a single proscribed project for the development of oil and natural gas wells in the county by the various operators within their individual fields; and (ii) certified the Environmental Impact Report (EIR) prepared by the county for the project. Following the adoption of the ordinance, the county relied on the certified EIR to satisfy CEQA requirements for the well permits issued under the ordinance.
Our operations in Kern County have been subject to significant uncertainty over the past several years as a result of ongoing challenges to Kern County’s ability to rely on the EIR and its subsequent iterations to satisfy CEQA requirements for well permits issued under the ordinance. In December 2015, several groups filed CEQA litigation against Kern County challenging the EIR. These proceedings have resulted in multiple rulings and appeals and the matter remains ongoing. The Trial Court imposed a stay on the issuance of new well permits under the ordinance in June 2022 which has remained in effect throughout most of the litigation and is currently in effect pending resolution of the matter by the Court of Appeals.
On March 7, 2024, the Court of Appeals issued its ruling on challenges made to a revised EIR. As a result, Kern County was directed to (a) prepare a further revised EIR that corrects deficiencies relating to (1) the rejection of agricultural conservation easements as a form of partial mitigation for the conversion of agricultural land, (2) assessment of cancer risks associated with the drilling of multiple wells near sensitive receptors and (3) analysis of water supply impacts; and (b) circulate the further revised EIR for public review and comment, and subsequently certify this revised EIR.
On March 22, 2024, Kern County released a notice of preparation of the further revised EIR. Kern County is expected to circulate a draft for public comment in the first quarter of 2025 and thereafter seek the Trial Court’s determination on this EIR’s compliance with the ruling of the Court of Appeals, certify this EIR and approve the revised ordinance. After that, the Trial Court would then be able to lift the stay, subject to further potential appeals. If the stay is lifted, 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 will approve the certification of the further revised EIR or lift the stay, which could further adversely affect our business, results of operations and financial condition.
As a result of these issues and current lack of permits with respect to our Kern County properties, we plan to operate one active drilling rig within Kern County in the first half of 2025 and have the requisite number of permits in hand to keep that rig active through the end of 2026. We operated one rig in 2024. We plan to begin drilling certain sidetracks under existing sidetrack permits in the first half of 2025 and plan to increase our active rig count in Kern County to two (2) rigs in the second half of 2025. In 2025, approximately $21 million of capital to develop proved reserves relates to drilling and completing sidetracks in Kern County for which we do not presently have a permit. If we are unable to obtain the necessary permits for the development of these wells, we will pursue alternatives for the deployment of this capital. For more information on our 2025 Capital Program, see Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Uses of Cash.
Regulatory Activity
The California Legislature and Governor have significantly increased the jurisdiction, duties and enforcement authority of CalGEM, the State Lands Commission and other state agencies with respect to oil and natural gas activities in recent years through legislation and policy pronouncements. CalGEM’s duties now include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs. CalGEM is also required to study and prioritize idle wells with emissions, evaluate costs of abandonment, decommissioning and restoration, and review and update associated indemnity bond amounts from operators if warranted, up to a specified cap which may be shared among operators. CalGEM and other state agencies have also significantly revised their regulations, regulatory interpretations and data collection and reporting requirements.
In addition, certain local governments have proposed or adopted ordinances that would restrict certain drilling activities in general, including limiting well stimulation, completion or injection activities, imposing setback distances from certain other land uses, or banning such activities outright. Other local governments have also sought to ban natural gas or the transportation of natural gas through their cities. For example, the cities of Brentwood and Antioch have refused to extend the necessary franchise agreements to preserve an existing pipeline that runs through their jurisdictions. In July 2023, one of our subsidiaries submitted an application with the CPUC to convert this pipeline to common carrier status. The application is still pending.
Setbacks and Senate Bill 1137 (SB 1137)
On September 16, 2022, the Governor of California signed Senate Bill No. 1137 which established 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 imposed a number of potential impact analysis and mitigation and reporting requirements. Senate Bill No. 1137 was stayed during a referendum process that was ultimately withdrawn and finally became effective on June 27, 2024. However, on September 30, 2024, the Governor signed into law Assembly Bill No. 218, which extends the timeline for the implementation of certain initial and future monitoring and reporting requirements until July 1, 2026 and further delays compliance with certain other requirements by up to three years. Assembly Bill. No. 218 does not modify the 3,200-foot setback requirements applicable to new wells, sidetracks, deepenings or workovers.
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 implementation of Senate Bill No. 1137 would be immaterial.
Idle Wells and Assembly Bill 1866 (AB 1866)
This law, effective January 1, 2025, increases the annual fees operators must pay per idle well, depending on how long each well has been idle, and includes a new fee for those wells that have been idle for less than three years. In lieu of the annual fees, operators can instead file an eight-year plan with the State to provide for the management and elimination of their idle wells. This law also increases the minimum percentages of idle wells that operators are required to eliminate each year. The rate at which idle wells must be eliminated varies depending on the number of an operator’s idle wells. Operators must prepare and submit a plan for the elimination of idle wells to CalGEM for approval. We implement robust programs for managing and eliminating idle wells that meet or exceed the requirements of the new law. As a result, we do not expect this new law to have any meaningful impact on our current plans for eliminating idle wells or meaningfully increase fees associated with our idle wells.
Baldwin Hills Conservancy and Assembly Bill 2716 (AB 2716)
This law requires operators to plug “low production wells” located within the boundary of the Baldwin Hills Conservancy in Los Angeles within a certain timeframe or otherwise subjects operators to administrative penalties. A “low-production well” is a well that produced fewer than an average of 15 barrels of oil a day during the past 12 months. We have limited operations and assets within the affected area. As a result, we expect that this law will not have a material adverse effect on either our total production or proved reserves.
Local Regulation and Assembly Bill 3233 (AB 3233)
This law provides local governments with the authority to limit methods for, or even prohibit oil and gas operations or development within their jurisdiction, including with respect to existing operations. Prior to the passage of this law, certain local governments in California, including the City and County of Los Angeles and Monterey County, had attempted to limit oil and gas operations within their jurisdictions and such actions had been challenged and struck down by California courts. However, following the adoption of AB 3233, certain legal challenges previously made to these local actions are no longer valid and it is possible that these or other local governments in California may attempt to pass new or similar restrictions. Future bans or restrictions on production or development by the City of Los Angeles or the counties of Los Angeles and Monterey could impact our production negatively or result in the write-down of our reserves.
For the fiscal year ended December 31, 2024, over 70% of our gross production is located in Kern County, and at this time we are not aware of any local governments within Kern County that are considering materially limiting or otherwise prohibiting oil and gas operations within their jurisdiction. However, it is difficult to predict how local governments in California may choose to exercise their new authority under AB 3233. There may be future legal challenges to AB 3233 and any local ordinances enacted thereunder and we cannot predict whether or not such challenges will be successful.
See Part 1, Item IA - Risk Factors - We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation.
Bonding and Assembly Bill 1167 (AB 1167)
On October 7, 2023, the California Governor signed into law Assembly Bill 1167 (AB 1167), which imposes more stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in California, requiring them to file either an individual indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities. Upon signing AB 1167, Governor Newsom called for further legislative changes to these new requirements to mitigate against the potential risk of the implementation of AB 1167 ultimately increasing the number of orphaned idle or low-producing wells in California, although no such changes have yet been announced. We cannot predict what form these changes may ultimately take or if the legislature will act on the Governor’s request. Implementation of this law may lead to the delay or additional costs with respect to certain acquisitions or dispositions, which could impact our ability to grow or explore new strategic areas - or exit others - within California.
Pipeline Transportation
Federal and state pipeline regulations have also been revised by both CalGEM and the Office of the State Fire Marshal over recent years, including requirements relating to integrity management, risk assessments, and spill prevention, amongst others. Additionally, PHMSA has, from time to time, issued new regulations expanding or otherwise revising pipeline integrity requirements. For example, in January 2025, PHMSA released a proposed draft of a final rule that would enhance requirements for detecting and repairing leaks on new and existing natural gas distribution, gas transmission and gas gathering pipelines. Prior to that, in September 2023, PHMSA published a proposed rule that would enhance the safety requirements for gas distribution pipelines and would require updates to distribution integrity management programs, emergency response plans, operations and maintenance manuals, and other safety practices. PHMSA finalized this proposed rule in January 2025.
Water Injection
Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. During 2024, we entered into discussions with the City of Long Beach and CalGEM regarding 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. In July 2024, CalGEM issued a directive to reduce the injection well pressure in a gradual manner and we implemented a five-year injection reduction work plan. The first phase of reduction commenced July 1, 2024 with a second reduction beginning in January 2025. 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 accuracy the impact to production and reserves. However, assuming no adjustments to the current work plan, we estimate a negative impact on production of approximately 1 MBoe/d at the end of the 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.
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 segment 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 were recently named a 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 seeking various remedies on the basis of a purported failure to conduct a CEQA review. In January 2025, the Superior Court of California, County of Los Angeles, denied the claimant’s petitions. Following this decision, we do not expect a material adverse effect on our business or operations as a result of this lawsuit, pending the outcome of any appeals.
Separately, for example, in November 2024, environmental groups collectively filed CEQA litigation against Kern County alleging CEQA violations in connection with the County’s approval of conditional use permits for our CTV I project at our Elk Hills Field. At this time, we cannot predict the outcome of this challenge with any certainty. Such lawsuits have the potential to delay timely construction of our CCS projects and commencement of operations and could otherwise have a material adverse effect on our business, results of operations and financial condition. Please see Regulation of Carbon Capture, Sequestration and Storage - CCS Project Permitting below for additional information.
Regulation of Health, Safety and Environmental Matters
Numerous federal, state, local and other laws and regulations that govern health and safety, the release or discharge of materials, land use or environmental protection may restrict the use of our properties and operations, increase our costs or lower demand for or restrict the use of our products and services. Applicable federal health, safety and environmental laws include the Occupational Safety and Health Act, Clean Air Act, Clean Water Act, Safe Drinking Water Act, Oil Pollution Act, Natural Gas Pipeline Safety Act, Pipeline Safety Improvement Act, Pipeline Safety, Regulatory Certainty, and Job Creation Act, Endangered Species Act, Migratory Bird Treaty Act, Comprehensive Environmental Response, Compensation, and Liability Act, Resource Conservation and Recovery Act and NEPA, among others. California imposes additional laws that are analogous to, and often more stringent than, such federal laws. These laws and regulations:
•establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, conduct regional, community or field monitoring of air, soil or water quality, and require attainment plans to meet those regional standards, which may include significant mitigation measures or restrictions on development, economic activity and transportation in such region;
•require various permits, approvals and mitigation measures before drilling, workover, production, underground fluid injection or waste disposal commences, or before facilities are constructed or put into operation;
•require the installation of sophisticated safety and pollution control equipment, such as leak detection, monitoring and shutdown systems, and implementation of inspection, monitoring and repair programs to prevent or reduce releases or discharges of regulated materials to air, land, surface water or ground water;
•restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require conservation and reclamation measures, impose energy efficiency or renewable energy standards on us or users of our products and services, and restrict the use of oil, natural gas or certain petroleum-based products such as fuels and plastics;
•restrict the types, quantities and concentrations of regulated materials, including oil, natural gas, produced water or wastes, that can be released or discharged into the environment, or any other uses of those materials resulting from drilling, production, processing, power generation, transportation or storage activities;
•limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater recharge, endangered species habitat and other protected areas, and require the dedication of surface acreage for habitat conservation;
•establish standards for the management of solid and hazardous wastes or the closure, abandonment, cleanup or restoration of former operations, such as plugging and abandonment of wells and decommissioning of facilities;
•impose substantial liabilities for unauthorized releases or discharges of regulated materials into the environment with respect to our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
•require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state and private lands or leases;
•impose taxes or fees with respect to the foregoing matters;
•may expose us to litigation with government authorities, counterparties, special interest groups or others; and
•may restrict our rate of oil, NGLs, natural gas and/or electricity production.
These requirements can result in restrictions on our operations. For example, in 2014, at the request of the EPA, CalGEM commenced a detailed review of the multi-decade practice of permitting underground injection wells and associated aquifer exemptions under the Safe Drinking Water Act. In 2015, the state set deadlines to obtain the EPA’s confirmation of aquifer exemptions under the Safe Drinking Water Act in certain formations in certain fields. During the review, the State has restricted injection in certain formations or wells in several fields, including some operated by us, requested that we change injection zones in certain fields, and held certain pending injection permits in abeyance. The State continues to work with EPA to resolve these issues. The aquifer exemption process has slowed in part due to the determination by CalGEM and the State Water Resources Control Board that certain of the remaining applications require additional “conduit analysis” to ensure that injected fluid will not escape from the intended area of subsurface confinement as well as EPA delays. Of the 30 original aquifer exemption proposals addressing permitted injection into a potential underground source of drinking water, 22 have been approved by EPA, with eight applications outstanding. In connection with legal challenges filed against the State by industry stakeholders, the Kern County Superior Court has issued an order generally barring the blanket enforcement of CalGEM’s aquifer exemption regulations mandating grant of an aquifer exemption as a precondition to continued injection activities.
At the federal level, recent modifications to regulations implementing NEPA may impose additional restrictions on oil and natural gas activities on federal lands. In October 2021, the Biden Administration announced three significant changes to a 2020 rule finalized under the Trump Administration. These changes included (i) authorizing agencies to consider the direct, indirect and cumulative effects of major federal actions including upstream and downstream impacts of fossil fuel projects; (ii) allowing agencies to determine the purpose and need of a project (thereby allowing consideration of less-harmful alternatives); and (iii) affording agencies greater flexibility in crafting their own NEPA procedures, consistent with Council of Environmental Quality (CEQ) regulations, so as to meet the agencies’ and public’s need. To that end, in April 2022, the CEQ issued a final rule in line with the proposed changes-“Phase I” of the Biden Administration’s two-phased approach to modifying NEPA. In May 2024-“Phase 2”-the CEQ issued a final rule revising the implementing regulations of the procedural provisions of NEPA and implementing amendments to NEPA included in the Fiscal Responsibility Act of 2023. The final rule was challenged by various states and the litigation remains ongoing. More recently, in November 2024, the U.S. Court of Appeals for the D.C. Circuit held that the CEQ lacks authority to issue NEPA regulations. Additionally, the current administration recently signed an energy-related Executive Order which included ordering the CEQ to propose rescinding its NEPA regulations. As a result, there is currently significant uncertainty with respect to the scope of environmental analysis required under NEPA.
There is also uncertainty surrounding the disbursement of federal funding. On January 20, 2025, an Executive Order was issued which paused distribution of federal funds appropriated through the Inflation Reduction Act (IRA) or the Infrastructure Investment and Jobs Act. The pause was aimed at providing time to review the processes, policies and issuance of various grants, loans, contracts or financial disbursements of appropriated funds but did not modify the IRA statutory language with respect to federal income tax credits. However, on January 29, 2025, the White House Office of Management and Budget rescinded the freezing of federal grants and loans, although not its efforts to review the processes with respect to federal spending. Although we are in receipt of small funding awards from the Department of Energy, many of our counterparts with which we are co-developing projects are dependent on much larger awards and loans. Any disruption, delay or withdrawal of federal funding could result in delays with respect to the development and timely completion of such projects or otherwise render them uneconomic, thereby adversely affecting our ability to pursue such projects.
In addition, due to the risk of future drought conditions in California, water districts and the State government have implemented regulations and policies that may restrict groundwater extraction and water usage and increase the cost of water. Water management, including our ability to recycle, reuse and dispose of produced water and our access to water supplies from third-party sources, in each case at a reasonable cost, in a timely manner and in compliance with applicable laws, regulations and permits, is an essential component of our operations to produce crude oil, natural gas and NGLs economically and in commercial quantities. As such, any limitations or restrictions on wastewater disposal or water availability could have an adverse impact on our operations. We treat and reuse water that is co-produced with oil and natural gas for a substantial portion of our needs in activities such as pressure management, waterflooding, steamflooding and well drilling, completion and stimulation. We also provide reclaimed produced water to certain agricultural water districts. We also use supplied water from various local and regional sources, particularly for power plants and steam generation. We are a net freshwater supplier to the state. While our production to date has not been impacted by restrictions on access to third-party water sources, we cannot guarantee that there may not be restrictions in the future.
Federal, state and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
Regulation of Carbon Capture, Sequestration and Storage
Unitization and Pipelines
On September 16, 2022, the Governor of California signed Senate Bill No. 905 into law, which contemplates the development of unitization, permitting and pipeline safety regulations over a multi-year period to facilitate the development of CCS projects in California, though the legislation does not provide for compulsory unitization. Senate Bill No. 905 also provides for a unified permitting process to simplify the permitting process for CCS projects, although this will be optional for project applicants. Additionally, the law contemplates the implementation of a new regulatory program incorporating standards that are not yet defined and that could affect the timing of future CCS projects in California. The California Air Resources Board has been tasked with developing this proposed framework and this work is still pending at this time. We believe that our Carbon TerraVault projects will continue to be developed on a timeline consistent with our initial expectations as these initial projects are not reliant on the unitization or permitting regulations being developed under Senate Bill No. 905.
Senate Bill No. 905 provides that pipelines may be used to transport carbon dioxide to or from a carbon dioxide capture, removal or sequestration project only upon conclusion of PHMSA’s rulemaking strengthening safety requirements for carbon dioxide pipelines. Although PHMSA released a notice of proposed rulemaking to this effect in early January 2025, it has not yet been published in the Federal Register and its disposition is uncertain at this time following the change in U.S. presidential administrations. Certain Carbon TerraVault projects are expected to be constructed on sites directly above underground storage facilities and would not be impacted by Senate Bill No. 905 or PHMSA’s rulemaking. For those Carbon TerraVault projects that do rely on transportation of CO2, however, the terms of these final pipeline safety regulations may impair or prohibit our ability to timely pursue future CCS projects that rely on the transportation of CO2.
CCS Project Permitting
On October 21, 2024, the Kern County Board of Supervisors approved the issuance of the conditional use permits and certified the EIR for our first CCS project, Carbon TerraVault I (CTV I). On November 22, 2024, a group of non-governmental organizations filed a lawsuit against the County of Kern and its Board of Supervisors in Kern County Superior Court, challenging the Board of Supervisors’ certification of the EIR for non-compliance with CEQA. In addition to challenging the EIR, the Petitioners have indicated that they intend to seek injunctive relief for a stay of the project but have not yet sought such relief. At this time, we cannot predict the outcome of this litigation with certainty. Such lawsuits have the potential to delay timely construction and commencement of operations at CTV I and could otherwise have a material adverse effect on our carbon management business and its prospects.
On December 31, 2024, the EPA issued four Class VI underground injection control (UIC) permits for the construction and operation of four CO2 injection wells at the site of the CTV I 26R underground CO2 storage reservoir at our Elk Hills Field. Per EPA rules, the EPA opened a 30-day period during which certain persons could make limited petitions regarding the permits. No person filed a petition for review or administrative review prior to the January 30, 2025 deadline. As a result, the EPA’s permit decision became effective February 3, 2025.
We currently have 7 Class VI permit applications relating to our carbon management segment pending with the EPA in different stages of the permitting process. We expect a final decision on Class VI UIC permits for our CTV I A1-A2 underground CO2 storage reservoir at our Elk Hills Field in the second half of 2025. We cannot guarantee the ultimate timing of EPA’s approval of the Class VI UIC permits for CTV I A1-A2 or any of our other projects, or that those permits will not be challenged, and cannot guarantee how these matters could ultimately delay or otherwise adversely impact our ability to timely execute our CCS projects.
Federal Tax Credits
The Inflation Reduction Act enhanced existing credits for the capture and sequestration of carbon oxide (45Q credit) by increasing the size of the maximum credit to $85 per metric ton of qualified carbon oxide when such carbon oxide is captured from industrial and power generation facilities and to $180 per metric ton of carbon oxide when a direct air capture facility is utilized to capture such carbon oxide, and, in each case, when such captured carbon oxide is disposed of by the taxpayer in secure geological storage. The Inflation Reduction Act also extended the date for when qualifying facilities must begin construction to before January 1, 2033. Further, a direct pay option for the 45Q credit (for a limited five-year period) was added, and the Inflation Reduction Act provides an option to monetize the 45Q credit through a sale of the 45Q credit to another taxpayer. These additional energy-related tax incentives are effective for new projects beginning on January 1, 2023, and enhance the economics for development of CCS projects in California. The accessibility of direct pay, tax equity financing, and the credit transfers market for 45Q credits provided under the Inflation Reduction Act is still developing, and therefore uncertainties and complexities with respect to our (or our partners) ability to efficiently monetize the 45Q credit exist.
The Inflation Reduction Act also incentivizes the development of clean hydrogen production projects through the clean hydrogen production tax credit under section 45V of the Code (45V credit). The credit amount is up to $3 per kilogram multiplied by an applicable percentage for clean hydrogen for a ten-year period beginning when a qualified facility is placed in service. On January 10, 2025, the IRS and Treasury released final regulations under section 45V. The final regulations provide rules for determining lifecycle greenhouse gas emissions rates resulting from hydrogen production processes; petitioning for provisional emissions rates; verifying production and sale or use of clean hydrogen; modifying or retrofitting existing qualified clean hydrogen production facilities; using electricity from certain renewable or zero-emissions sources to produce qualified clean hydrogen; and electing to treat part of a specified clean hydrogen production facility instead as property eligible for the energy credit.
The amount of the available 45V credit from which we may directly or indirectly benefit in connection with our Carbon TerraVault business will depend on our ability to satisfy certain requirements and obtain certain emissions rate results under the most recent 45V credit Greenhouse Gasses, Regulated Emissions, and Energy Use in Transportation (45VH2-GREET) model or a petition for a provisional emissions rate. The final regulations impose certain requirements, restrictions and limitations that may eliminate or reduce the amount of the credit available to us (or our partners), which may impact our ability to successfully develop clean hydrogen production projects. Moreover, the accessibility of direct pay, tax equity financing, and the credit transfers market for 45V credits provided under the Inflation Reduction Act is still developing, and therefore uncertainties and complexities with respect to our (or our partners) ability to efficiently monetize the 45V credit still exist.
The current administration recently signed several Executive Orders reversing, revoking or rescinding many climate-related actions and has expressed a desire to make modifications to the Inflation Reduction Act. The enactment of any legislation that reduces or eliminates 45Q credits or 45V credits could have an adverse effect on the development of our carbon management business and its prospects. For more information, see Part 1, Item IA - Risk Factors - Risks Related to Carbon TerraVault and Our Carbon Management Segment, Our Carbon TerraVault business and other CCS projects depend on financial and tax incentives to be economical, and these incentives may not currently be sufficient for our Carbon TerraVault business and other CCS projects to be economical, may not be fully realized, or could be changed or terminated.
Regulation of Climate Change and Greenhouse Gas (GHG) Emissions
A number of international, federal, state, regional and local efforts seek to prevent or mitigate the effects of climate change or to track, mitigate and reduce GHG emissions associated with energy use and industrial activity, including operations of the oil and natural gas production sector and those who use our products as a source of energy or feedstocks. While in office, President Biden issued several executive orders on climate change. The EPA finalized methane emissions standards for new, modified and existing oil and natural gas: required reporting of annual GHG emissions from oil and natural gas exploration and production, power plants and natural gas processing plants; gathering and boosting compression and pipeline facilities; and certain completions and workovers; incorporation of measures to reduce GHG emissions in permits for certain facilities; and restriction of GHG emissions from certain mobile sources. However, upon the first days in office, the current administration signed several Executive Orders reversing, revoking or rescinding many climate-related actions and it remains to be seen how such Executive Orders may impact our business and what may result from any litigation, administrative or legislative actions relating to such Executive Orders.
Separately, California has adopted stringent laws and regulations to reduce GHG emissions and may continue to adopt more. The current state laws and regulations:
•established a “cap-and-trade” program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030, the year that the cap-and-trade program currently expires;
•require allowances or qualifying offsets for GHGs emitted from California operations and for the volume of natural gas, propane and liquid transportation fuels sold for use in California;
•established a low carbon fuel standard (LCFS) and associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline gasoline and diesel fuels, and provide a mechanism to generate LCFS credits through innovative crude oil production methods such as those employing solar or wind energy or carbon capture and sequestration;
•mandated that California derive 60% of its electricity for retail customers from renewable resources by 2030;
•established a policy to derive all of California’s retail electricity from renewable or "zero-carbon" resources by 2045, subject to required evaluation of the feasibility by state agencies;
•imposed state goals to double the energy efficiency of buildings by 2030 and to reduce emissions of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013 levels by 2030; and
•mandated that all new single family and low-rise multifamily housing construction in California include rooftop solar systems or direct connection to a state-approved community solar system.
In November 2024, CARB finalized amendments to the LCFS Regulation which included increasing 2030 carbon intensity (CI) targets from 20% to 30% and extending CI reductions to 90% by 2045. Additional updates include additional funding of zero-emission vehicle charging and hydrogen fueling infrastructure, amongst other matters. The final rulemaking package was sent to the Office of Administrative Law in January 2025. However, in February 2025, the Office of Administrative Law issued a Notice of Disapproval to CARB, citing clarity and incorrect procedure as grounds for its disapproval. CARB may resubmit the finalized amendments after resolving the identified issues.
The amendments also excluded clean hydrogen produced using CCS from the definition of “Renewable Hydrogen”. Clean hydrogen produced using CCS comes primarily from natural gas using a steam reformation process, which brings together natural gas and heated water in the form of steam. The output is hydrogen. Carbon dioxide is produced as a by-product of this process. The produced hydrogen constitutes clean hydrogen using CCS if the produced carbon dioxide is captured and permanently sequestered. We are still assessing the impact of these revisions on the eligibility of certain of our hydrogen and CCS projects for LCFS credits; however, to the extent CARB disfavors clean hydrogen using CCS projects from generating credits under the LCFS, our low carbon projects may not be able to capture their full value as originally estimated. This could result in certain projects becoming less or non-economic, which in turn could limit our ability to successfully pursue hydrogen and CCS projects in the future.
California's cap-and-trade program is a market-based emissions reduction program to limit GHG emissions. The program applies to major GHG-emitting sources such as electricity generation and industrial facilities, with set carbon benchmarks that gradually decrease each year. Covered emitters must either reduce their emissions below this benchmark or purchase allowances at auction, incentivizing investment in lower-emissions technologies. However, unlike the LCFS, CARB’s CCS protocol has not yet been incorporated into the cap-and-trade program. The timing for the adoption of a protocol is unclear and it may not happen at all. Until CARB adopts a CCS protocol for cap-and-trade, the program considers GHG emissions sequestered using CCS to be no different than unabated emissions. If CARB fails to adopt a CCS protocol for cap-and-trade, this could result in certain projects becoming less or non-economical, which in turn could limit our ability to successfully pursue certain CCS projects in the future. We are exploring alternative approaches to account for carbon capture under the California cap-and-trade program, but we cannot guarantee that CARB will accept these alternative approaches or that we will be able to pursue them in a timely manner to support our carbon capture projects.
In addition, the current and former Governors of California and certain municipalities in California have announced their commitment to adhere to GHG reductions called for in the Paris Agreement through executive orders, pledges, resolutions and memoranda of understanding or other agreements with various other countries, U.S. states, Canadian provinces and municipalities. In furtherance of this commitment, in September 2022, the Governor of California signed Assembly Bill No. 1279 into law, which codifies a previously issued executive order by the Governor's Office requiring the state to achieve carbon neutrality by 2045. In addition, the Governor of California previously issued an executive order directing several agencies to take further actions with respect to reducing emissions of GHGs. The Governor has also directed state agencies to implement other measures to mitigate climate change and strengthen biodiversity, such as via the conservation of 30% of state lands and waters by 2030. For more information, see Part I, Item 1A - Risk Factors, Risks Related to Regulation and Government Action, Recent and future actions by the State of California could reduce both the demand for and supply of oil and natural gas within the state and consequently have a material adverse effect on our business, and financial condition and results of operations.
The EPA and the CARB have also expanded direct regulation of methane as a contributor to GHG emissions. In response to President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, in December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources, known as OOOOc. Under the final rules, states have two years to prepare and submit their plans to impose methane emissions controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. The rules have been subject to legal challenge, and may also be repealed or modified by the current administration, though we cannot predict the substance or timing of such changes, if any.
Relatedly, beginning in 2025, certain oil and gas facilities, including those we own and operate, must pay a fee to EPA pursuant to the Inflation Reduction Act, starting at $900 per metric ton of methane emitted in 2024 and annually thereafter, with the fee rising to $1,200 in 2025 and $1,500 in 2026 and thereafter. However, compliance with the EPA’s methane rules, discussed above, would exempt an otherwise covered facility from the requirement to pay the fee. At this time, it remains uncertain whether the current administration will take any action to revise or repeal the methane charge rule or if Congress may take action to repeal or revise the IRA, including with respect to the methane charge rule.
Regulation of Transportation, Marketing and Sale of Our Products
Our sales prices of oil, NGLs and natural gas in the U.S. are set by the market and are not presently regulated. In 2015, the U.S. federal government lifted restrictions on the export of domestically produced oil that allows for the sale of U.S. oil production, including ours, in additional markets.
Federal and state laws regulate transportation rates for, and marketing and sale of, petroleum products and electricity with respect to certain of our operations and those of certain of our customers, suppliers and counterparties. Such regulations also govern:
•interstate and intrastate pipeline transportation rates for oil, natural gas and NGLs in regulated pipeline systems;
•prevention of market manipulation in the oil, natural gas, NGL and power markets;
•market transparency rules with respect to natural gas and power markets;
•the physical and futures energy commodities market, including financial derivative and hedging activity; and
•prevention of discrimination in natural gas gathering operations in favor of producers or sources of supply.
The federal and state agencies overseeing these regulations have substantial rate-setting and enforcement authority, and violation of the foregoing regulations could expose us to litigation with government authorities, counterparties, special interest groups and others.
International treaties and regulations also affect the marketing or sale of our products. For example, on January 1, 2020, the International Maritime Organization reduced the maximum sulfur content in marine fuels from 3.5% to 0.5% by weight under the International Convention for the Prevention of Pollution from Ships. Under this IMO 2020 rule, ships must either switch to low-sulfur fuels or install scrubbing facilities for emission controls, which may affect the price of and demand for varying grades of crude oil, both internationally and in California.
In addition, mandates or subsidies have been adopted or proposed by the state and certain local governments to require or promote renewable energy or electrification of transportation, appliances and equipment, or prohibit or restrict the use of petroleum products, by our customers or the public. For example, in January 2020, the California Public Utilities Commission (CPUC) commenced a rulemaking to develop a long-term natural gas planning strategy to ensure safe and reliable gas systems at just and reasonable rates during what it describes as a 25-year transition from natural gas-fueled technologies to meet the state's GHG goals. In addition, several municipalities in California enacted ordinances in 2019 that restrict the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect the retail natural gas market of our utility customers and the demand and prices we receive for the natural gas we produce. Several of these ordinances face legal challenges.
Available Information
We make available, free of charge on our website www.crc.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Definitive Proxy Statements and amendments to those reports filed or furnished, if any, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Unless otherwise provided herein, information contained on our website is not part of this report. The SEC maintains an internet site, http://www.sec.gov, that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

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ITEM 1A. RISK FACTORS
ITEM 1A RISK FACTORS
Described below are certain risks and uncertainties that could adversely affect our business, financial condition, results of operations or cash flow. These risks are not the only risks we face. Our business could also be affected materially and adversely by other risks and uncertainties that are not currently known to us or that we currently deem to be insignificant.
Summary:
Risks Related to Our Oil and Gas Business
•Prices for our products are volatile and a substantial decline in prices over an extended period could have a material adverse effect on our financial condition, results of operations, cash flow and ability to invest in our assets.
•Our producing properties are located exclusively in California, making us vulnerable to risks associated with having operations concentrated in this geographic area, including drought, earthquake and wildfire risks.
•Drilling for and producing oil and natural gas carries significant operational risks and uncertainty. We may not drill wells at the times we schedule, or at all. Wells we do drill may not yield production in economic quantities or generate the expected payback.
•Our business involves substantial capital investments, and we may be unable to fund these investments which could lead to a decline in our oil and natural gas reserves or production.
•We may be negatively impacted by inflation.
•We are subject to economic downturns and the effects of public health events which may materially and adversely affect the demand and the market price for our products.
•The military conflicts in Ukraine, Israel and other countries in the Middle East have caused price volatility and geopolitical instability which impact our business.
•Some of our competitors have greater resources than us and we may not be able to successfully compete in acquiring and developing new properties.
•Our hedging activities limit our ability to realize the full benefits of increases in commodity prices.
•Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be higher or lower than estimated.
•From time to time we may engage in step-out drilling, or drilling in new or emerging plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is unsuccessful.
Risks Related to Carbon TerraVault and Our Carbon Management Segment
•We may not be able to grow our Carbon TerraVault business and develop large scale CCS projects.
•Our ability to achieve our emissions goals and other goals related to carbon management activities is subject to risks and uncertainties.
•Our Carbon TerraVault business and other CCS projects depend on financial and tax incentives to be economical, and these incentives may not currently be sufficient for our Carbon TerraVault business and other CCS projects to be economical, may not be fully realized, or could be changed or terminated.
•Our Carbon TerraVault JV with Brookfield is subject to inherent uncertainties which could adversely affect our ability to implement our carbon management strategy.
Risk Factors Related to Our Business Generally
•Increasing activism against the industries in which we operate, including the oil and gas industry and our involvement in carbon capture, storage, utilization and sequestration, presents risks to our business.
•Increased attention to ESG matters may adversely impact our business.
•Acquisition and disposition activities, including continued integration of the Aera Merger, involve substantial risks.
•We may incur substantial losses and be subject to substantial liability claims as a result of pollution, environmental conditions or catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
•Cybersecurity attacks, systems failures and other disruptions could adversely affect us.
Risks Related to Regulation and Government Action
•We may face material delays related to our ability to timely obtain permits necessary for our operations, or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.
•We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation.
•Recent and future actions by the State of California could reduce both the demand for and supply of oil and natural gas within the state and consequently have a material and adverse effect on our business, results of operations and financial condition.
•Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans.
•Our Carbon TerraVault business and our CCS projects are subject to extensive government regulation much of which is still being developed. Failure to comply with these regulations and obtain the necessary permits, or the development of government regulations that are unfavorable to our CCS projects, could have an adverse effect on our business, results of operations and financial condition.
•New and developing regulations related to CO2 unitization, permitting and pipeline safety could negatively impact our business, financial condition and results of operations.
•Our operations and financial performance may be negatively affected directly or indirectly by changes in trade policies and tariffs.
•Concerns about climate change and other environmental issues may prompt governmental action that could have a material adverse effect on our operations or results.
•The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs on our operations.
•Tax law changes could have an adverse effect on our financial condition, results of operations and cash flows.
•Financial assurance requirements related to plugging and abandonment costs, decommissioning, and site restoration on those who acquire the right to operate wells and production facilities could impact our ability to sell or acquire assets in California or increase our costs in connection with the same.
Risks Related to our Indebtedness
•We may not be able to amend or refinance our existing debt to create more operating and financial flexibility and to enhance shareholder returns.
•Our existing and future indebtedness may adversely affect our business and limit our financial flexibility.
•We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy the obligations under our indebtedness, which may not be successful.
•The lenders under our Revolving Credit Facility could limit our ability to borrow and restrict our ability to use or access capital.
•Restrictive covenants in our Revolving Credit Facility and the indentures governing our Senior Notes may limit our financial and operating flexibility.
•Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Risks Related to Our Common Stock
•Our ability to pay dividends and repurchase shares of our common stock is subject to certain risks.
•The trading price of our common stock may decline, and you may not be able to resell shares of our common stock at prices equal to or greater than the price you paid or at all.
•Future issuances of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
•The ownership position of certain of our stockholders limits other stockholders’ ability to influence corporate matters and could affect the price of our common stock.
•Sales of shares of our common stock by our executive officers could negatively impact the market price for our common stock.
Risks Related to Our Oil and Gas Business
Prices for our products are volatile and a substantial decline in prices over an extended period could have a material adverse effect on our financial condition, results of operations, cash flow and ability to invest in our assets.
Our financial condition, results of operations, cash flow and ability to invest in our assets are highly dependent on oil, natural gas and NGL prices. A substantial decline in prices for these products would reduce our cash flows from operations and could reduce our borrowing capacity or cause a default under our financing agreements.
Prices for oil, natural gas and NGL may fluctuate widely in response to relatively minor changes in domestic and global supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:
•domestic and global inventory levels;
•political and economic conditions, including international disputes such as the conflicts in Ukraine, Israel and other countries in the Middle East;
•pandemics, epidemics, outbreaks or other public health events, such as the COVID-19 pandemic;
•the actions of OPEC and other significant producers and governments;
•changes or disruptions in actual or anticipated production, refining and processing;
•worldwide drilling and exploration activities;
•government energy policies and regulation, including with respect to climate change;
•the effects of conservation;
•natural disasters, weather conditions and other seasonal impacts;
•speculative trading in derivative contracts;
•currency exchange rates;
•technological advances;
•transportation and storage capacity, bottlenecks and costs in producing areas;
•the price, availability and acceptance of alternative energy sources;
•regional market conditions; and
•other matters affecting the supply and demand dynamics for these products.
Lower prices could have adverse effects on our business, financial condition and results of operations, including:
•reducing our proved oil and natural gas reserves over time;
•limiting our capital expenditures and our ability to grow or maintain future production;
•causing a reduction in our borrowing base under our Revolving Credit Facility, which could affect our liquidity;
•reducing our cash flow and ability to make interest payments or maintain compliance with financial covenants in the agreements governing our indebtedness, which could trigger mandatory loan repayments and default and foreclosure by our lenders and bondholders against our assets; and
•limiting our access to funds through the capital markets and the price we could obtain for asset sales or other monetization transactions.
Our hedging program does not provide downside protection for all of our production. As a result, our hedges do not fully protect us from commodity price declines, and we may be unable to enter into acceptable additional hedges in the future.
Our producing properties are located exclusively in California, making us vulnerable to risks associated with having operations concentrated in this geographic area, including drought, earthquake and wildfire risks.
Our operations are concentrated in California. Because of this geographic concentration, the success and profitability of our operations may be disproportionately exposed to the effect of regional conditions. Changes in state or regional laws and regulations affecting our operations, local price fluctuations and other regional supply and demand factors, including gathering, pipeline, transportation and storage capacity constraints, limited potential customers, infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor. Our operations are also exposed to natural disasters and related events common to California, such as wildfires, mudslides, high winds, earthquakes and extreme weather events, and the potential increase to the frequency of drought and flooding. Further, our operations may be exposed to power outages, mechanical failures, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut in, delay operations and growth plans, decrease cash flows, increase operating and capital costs, prevent development of lease inventory before expiration and limit access to markets for our products.
Drilling for and producing oil and natural gas carries significant operational risks and uncertainty. We may not drill wells at the times we schedule, or at all. Wells we do drill may not yield production in economic quantities or generate the expected payback.
The development of oil and natural gas properties are subject to numerous operational risks, including the risks of permitting or construction delays, equipment failures, accidents, environmental hazards, unusual geological formations or unexpected pressure or irregularities within formations, adverse weather conditions, title disputes, surface access disputes, disappointing drilling results or reservoir performance (including lack of production response to workovers or improved and enhanced recovery efforts), cost over-runs and other associated risks.
Development activities also depend in part on our analysis of geophysical, geologic, engineering, production and other technical data and processes, including the interpretation of 3D seismic data. This analysis is often inconclusive or subject to varying interpretations.
Any of the forgoing operational risks could cause actual results to differ materially from the expected payback or cause a well or project to become uneconomic or less profitable than forecast.
We have specifically identified drilling activities for the next several years, which are an integral part of our production strategy. Our actual drilling activities may materially differ from those presently identified. If future drilling activities do not generate sufficient production and reserves, we may be forced to curtail drilling or development of these and other projects. We make assumptions about the consistency and accuracy of data when we identify locations for new wells or opportunities for workovers, sidetracks and deepenings, and these assumptions may prove inaccurate. We cannot guarantee that our identified new well drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these drilling locations or from our other drilling activities. In addition, some of our leases could expire if we do not establish production in the leased acreage. The combined net acreage covered by leases expiring in the next three years represented 2% of our total net undeveloped acreage at December 31, 2024.
Our business involves substantial capital investments and we may be unable to fund these investments which could lead to a decline in our oil and natural gas reserves or production.
Our development activities involve substantial capital investments. We intend to fund our 2025 capital program using cash flow from operations. Accordingly, a reduction in projected operating cash flow could cause us to reduce our future capital investments. In general, the ability to execute our capital plan depends on a number of factors, including:
•the amount of oil, natural gas and NGLs we are able to produce;
•commodity prices;
•regulatory and third-party approvals;
•our ability to timely drill, complete and stimulate wells;
•our ability to secure equipment, services and personnel; and
•our liquidity and ability fund capital expenditures.
Access to future capital may be limited by our lenders, capital markets constraints, activist funds or investors, or poor stock price performance. Because of these and other potential variables, we may be unable to deploy capital in the manner planned, which may negatively impact our production levels and development activities and limit our ability to make acquisitions or enter into partnerships and farmout arrangements.
Unless we make sufficient capital investments and conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our ability to make the necessary long-term capital investments or acquisitions needed to maintain or expand our reserves may be impaired to the extent we have insufficient cash flow from operations or liquidity to fund those activities. Over the long term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.
We may be negatively impacted by inflation.
Increases in inflation may have an adverse effect on us. Operating and capital costs in the oil and natural gas industry are heavily influenced by commodity prices, including the prices we pay for electricity, natural gas and steel-based materials. For example, we use natural gas in our operations to generate steam for use in steamfloods and we purchase additional volumes of natural gas to support our operations. We also use electricity generated by our Elk Hills power plant to power our oil and gas operations in the Elk Hills field. If we are unable to generate sufficient electricity for use in our operations, we may need to purchase electricity from third parties. Increases in the volumes or prices of commodities used in our operations could cause increases in our operating expenses. We attempt to manage our exposure to price increases of certain commodities used in our operations, including natural gas, by entering into hedges or longer-term contracts with fixed price arrangements. However, these measures do not fully protect us from the effects of commodity price increases and we may not be able to enter into similar arrangements in the future on acceptable terms or at all. Inflation could also result in higher interest rates in the United States, which could increase the cost of future financing efforts.
We are subject to economic downturns and the effects of public health events which may materially and adversely affect the demand and the market price for our products.
The marketing of our oil, natural gas and NGLs is dependent upon the existence of adequate markets for our products. Imbalances between the supply of and demand for these products, including as a result of economic downturns or the effects of public health events, could cause extreme market volatility and a substantial adverse effect on commodity prices. A world health event, the extent of actions that may be taken to contain or treat its impact, and the impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict. This uncertainty could force us to reduce costs, including by decreasing operating expenses and lowering capital expenditures, and such actions could negatively affect future production and our reserves. We may experience labor shortages if our employees are unwilling or unable to come to work because of illness, quarantines, government actions or other restrictions in connection with a pandemic. If our suppliers cannot deliver the materials, supplies and services we need, we may need to suspend operations. In addition, we are exposed to changes in commodity prices which have been and will likely remain volatile. We cannot predict the duration and extent of a pandemic's adverse impact on our operating results.
Additionally, to the extent a world health event adversely impacts the global business and economic environment, which adversely affects our business and financial results, it may also have the effect of heightening or exacerbating many of the other risks described in the Risk Factors herein.
The military conflicts in Ukraine, Israel and other countries in the Middle East have caused price volatility and geopolitical instability which impact our business.
The military conflicts in Ukraine, Israel and other countries in the Middle East have caused volatility in the prices of natural gas, oil and NGLs, and the extent and duration of the military action, sanctions and resulting market disruptions have been significant and could continue to have a substantial impact on the global economy and our business for an unknown period of time.
In the fourth quarter of 2024, OPEC+ extended its nearly 4 million barrels per day voluntary reduction in production quotas as well as 2.2 million barrels per day in voluntary production curtailments. While actual OPEC+ production capabilities are difficult to discern, any return to previous targeted production levels-coupled with expanding Iranian, Venezuelan, Brazilian and U.S. production-could cause commodity prices to decline which would reduce the revenues we receive for our oil production.
Materialization of either of the events described above may also magnify the impact of the other risks described in this “Risk Factors” section.
Some of our competitors have greater resources than us and we may not be able to successfully compete in acquiring and developing new properties.
We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases, obtaining goods and services and hiring and retaining employees needed to operate and manage our business and marketing natural gas, NGLs or oil. Competitors include a multinational oil company, independent production companies and individual producers and operators. In California, our competitors are few, which may limit available acquisition opportunities. Some of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address such competitive factors more effectively than we can or withstand industry downturns more easily than we can.
Our hedging activities limit our ability to realize the full benefits of increases in commodity prices.
We enter into hedges to mitigate our economic exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. Our Revolving Credit Facility also includes a covenant that would require us to enter into hedges if the ratio of our indebtedness to Consolidated EBITDAX (as defined in the Revolving Credit Facility) exceeds certain levels. These hedges expose us to the risk of financial losses depending on commodity price movements and may prevent us from realizing the full benefits of price increases. Our ability to realize the benefits of our hedges also depends in part upon the counterparties to these contracts honoring their financial obligations. If any of our counterparties are unable to perform their obligations in the future, we could be exposed to increased cash flow volatility that could affect our liquidity. In addition, our level of hedging activity may be impacted by financial regulations that could increase our costs of hedging and/or limit the number of hedging counterparties available to us.
Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be higher or lower than estimated.
Many uncertainties exist in estimating quantities of proved reserves and related future net cash flows. Our estimates are based on various assumptions that require significant judgment in the evaluation of available information. Our assumptions may ultimately prove to be inaccurate. Additionally, reservoir data may change over time as more information becomes available from development and appraisal activities.
Our ability to maintain or increase our reserves, other than through acquisitions, depends on our ability to drill new wells, which is currently limited due to the lack of availability of new well permits as described below. See Risks Related to Regulation and Government Action - We may face material delays related to our ability to timely obtain permits necessary for our operations or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.
To the extent we are able to drill new wells, our ability to maintain or increase reserves (other than through acquisitions) is contingent on the success of improved recovery, extension and discovery projects, each of which hinges on reservoir characteristics, technology improvements and oil and natural gas prices, as well as capital and operating costs. Many of these factors are outside management’s control and will affect whether the historical sources of proved reserves additions continue to provide reserves at similar levels.
Generally, lower prices adversely affect the quantity of our reserves as those reserves expected to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. In addition, a portion of our proved undeveloped reserves may no longer meet the economic producibility criteria under the applicable rules or may be removed due to the lack of drilling permits or insufficient capital to develop these projects within the SEC-mandated five-year limit.
In addition, our reserves information represents estimates prepared by internal engineers. Although 85% of our estimated proved reserve volumes as of December 31, 2024, were audited by our independent petroleum engineer, NSAI, we cannot guarantee that the estimates are accurate.
Reserves estimation is a partially subjective process of estimating accumulations of oil and natural gas. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows from those reserves depend upon a number of variables and assumptions. Changes in these variables and assumptions could require us to make significant negative reserves revisions, which could affect our liquidity by reducing the borrowing base under our Revolving Credit Facility. In addition, factors such as the availability of capital, geology, government regulations and permits, the effectiveness of development plans and other factors could affect the source or quantity of future reserves additions.
From time to time we may engage in step-out drilling or drilling in new or emerging plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is unsuccessful.
The risk profile for step-out drilling or drilling in new or emerging plays is higher than for other locations because we have less geologic and production data and drilling history, in particular for drilling in unconventional reservoirs, which are in unproven geologic plays. Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, capital availability, costs, drilling results, regulatory approvals, available transportation capacity and other factors. We may not find commercial amounts of oil or natural gas or the costs of drilling, completing, stimulating and operating wells in these locations may be higher than initially expected. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. In either case, the value of our undeveloped acreage may decline and could be impaired.
Risks Related to Carbon TerraVault and Our Carbon Management Segment
We may not be able to grow our Carbon TerraVault business and develop large scale CCS projects.
We are developing a carbon management business in California that relies on CCS projects. To our knowledge, there are no existing large-scale CCS projects in California similar to those that we are seeking to develop. These projects face operational, technological and regulatory risks that could be considerable due to the early-stage nature of these projects and the sector generally. Our ability to successfully develop these projects depends on a number of factors that we are not able to fully control, including the following:
•Obtaining Class VI permits for carbon dioxide injection and storage from the EPA may take years, and the time to obtain permits may vary with the complexity and type of storage reservoir. The analysis of the suitability of a reservoir for carbon sequestration is complex and our permit applications are subject to extensive review by the EPA. There can be no assurances that the EPA will release Class VI permits to us when we expect, if at all. Even if we are successful in our efforts to obtain Class VI permits, the permits could be subject to legal challenges.
•The development of large-scale CCS projects is an emerging sector and there are no meaningful precedents to gauge the likely range of economic terms upon which these projects may be feasibly developed. In addition, any of the operational, regulatory or financial risks described herein could cause actual results to differ materially from expected payback or cause a project to become uneconomic or less profitable than forecast.
•The development of CCS and related projects will likely require us, our joint venture partner, and third-party emitters to make significant capital investments in the relevant technology and infrastructure and we may not have sufficient capital resources to fund such investments. Such projects may also depend on third party financing and such financing may not be available on reasonable terms or at all. In some cases, these projects will involve the production and sale of hydrogen, ammonia or other products and markets for some of these products are still emerging.
•The development of a CCS project will likely require us to enter into long term binding agreements with large carbon emitters and other third parties and we may not be able to do so on agreeable terms or at all. Such agreements are complex and may involve allocation of not only fees but also various credits, incentives and environmental attributes associated with the storage of CO2. Not all emission sources produce sufficiently large quantities of pure or relatively pure streams of CO2, or have installed equipment to capture such CO2, so as to be useable in one or more of our CCS projects. As a result, we cannot assure
whether we will be able to access CO2 emissions in sufficient quantities or on terms that are acceptable to us.
•The development and operation of cost-effective, commercial-scale hydrogen and ammonia production facilities and associated sequestration facilities are highly complex. We may participate in the development of production facilities that provide the emissions for our CCS business. There can be no assurances that we or our partners will be able to successfully develop these production facilities, or that we will be able to develop the related sequestration facilities, in a timely manner or at all. In addition, there can be no assurances that these facilities can be maintained and operated over the longer term. The financing and development of these projects may depend on the availability of long term off-take agreements for these products and the market for hydrogen is still developing. It may not be possible for us or our partners to enter into these types of agreements on acceptable terms or at all.
•Certain of our anticipated CCS project sites rely on pore space that we do not own and we may need to enter into agreements with landowners to allow us to inject CO2. The market for such landowner agreements is evolving with the evolution of the CCS industry and it may not be possible for us to enter into these types of agreements on acceptable terms or at all.
•Complex recordkeeping and GHG emissions/sequestration accounting may be required in connection with one or more of our projects, which may increase the costs of such operations. Different methodologies may be required for various regulatory and non-regulatory accounts regarding GHG emissions/sequestration at one or more of our projects, including but not limited to compliance with the EPA’s Mandatory Greenhouse Gas Reporting Program.
•Carbon capture may be viewed as a pathway to the continued use of fossil fuels and there may be organized opposition (including lawsuits) to CCS projects from environmental groups, local residents and legislators.
•Other regulatory uncertainties described below.
There can be no assurances that we will successfully develop our CCS projects, including our cryogenic gas plant CCS project or CalCapture, and a failure to do so would have an adverse effect on our carbon management business and its prospects. Our carbon management segment is currently in an early stage of development, and we do not expect the failure of a single CCS project to create an impact on our overall financial condition or operations. However, as the scale of our CCS projects grows, so will its impact on our overall financial condition and operations. Moreover, our failure to successfully develop our CCS projects would adversely affect our ability to claim emissions reductions related to our sequestration activities and our ability to meet our carbon management goals, which in turn could have an adverse effect on our business and reputation.
Our ability to achieve our emissions and other goals related to our carbon management activities is subject to risks and uncertainties.
We have adopted a number of targets and objectives related to sustainability matters. Our efforts to research, establish, accomplish, and accurately report on these targets and objectives expose us to numerous operational, reputational, financial, legal, and other risks. Our ability to achieve any stated target or objective is not guaranteed and is subject to numerous factors and conditions, some of which are outside of our control. We are reviewing the impact of the Aera Merger and its assets on our ability to meet our previously announced 2045 Full-Scope Net Zero goal and may revise our goal to reflect our current business and other considerations. In any event, this goal includes Scope 1, 2 and 3 emissions and estimation and management of Scope 3 emissions are subject to some degree of uncertainty. We cannot guarantee that we have been able to completely quantify the full scope of our emissions and account for mitigating all such emissions in our Full-Scope Net Zero goal.
Our ability to achieve our emissions goal relies heavily on our ability to develop our Carbon TerraVault business and related CCS projects, which is subject to uncertainties and risks (including those risks described herein), such as the timely receipt of permits and third party challenges relating to the same. In addition, the commercial and regulatory environment related to emissions reductions and reporting is evolving and uncertain, and changes in GHG emission accounting methodologies or new developments related to climate science could impact our ability to claim emissions reductions related to our sequestration activities and timely achieve our emissions goal or at all. If we are not able to successfully develop Carbon TerraVault and its CCS projects and claim related emissions reductions, our ability to achieve our emissions goal would be materially and adversely affected.
Our business may face increased scrutiny from investors and other stakeholders related to our sustainability activities, including the goals, targets, and objectives that we announce, and our methodologies and timelines for pursuing them. If our sustainability practices do not meet investor or other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected. Similarly, our failure or perceived failure to pursue or fulfill our sustainability-focused goals, targets, and objectives, to comply with ethical, environmental, or other standards, regulations, or expectations, or to satisfy various reporting standards with respect to these matters, within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and private litigation.
Our Carbon TerraVault business and other CCS projects depend on financial and tax incentives to be economical, and these incentives may not currently be sufficient for our Carbon TerraVault business and other CCS projects to be economical, may not be fully realized, or could be changed or terminated.
Congress has incentivized the development of carbon capture projects, clean hydrogen production projects and other projects relating to the production of certain clean fuels through the establishment of various tax credits, including the 45Q credit (credit for carbon oxide sequestration) and the 45V credit (credit for production of clean hydrogen). The successful development of our Carbon TerraVault business and other CCS projects is dependent upon our ability to directly or indirectly benefit from these tax credits. The amount of tax credits from which we may directly or indirectly benefit in connection with our Carbon TerraVault business and other CCS projects is dependent upon satisfaction of certain requirements, some of which have not been fully developed and issued by the Treasury Department and IRS, and we cannot assure you that we (or our partners) will be able to satisfy those requirements. For example, the Treasury Department and IRS recently issued final regulations pertaining to the 45V credit which, among other things, imposed certain requirements, restrictions and limitations on the use of renewable natural gas in connection with the production of clean hydrogen that qualifies for the 45V credit, which could have a negative impact on the development of future hydrogen projects in connection with our Carbon TerraVault business. Additional financial incentives may also be required for our Carbon TerraVault business and other CCS projects to be economical. In particular, we anticipate that CCS projects associated with carbon emission reductions for transportation fuels will generate LCFS credits and that these additional credits will improve the economics of CCS projects. If the existing legal requirements for incentives such as the 45Q credit, the 45V credit or LCFS credits are subsequently amended in a manner that such incentives no longer apply or are restricted in application, directly or indirectly, to our projects, we may not be able to successfully achieve an economic return from our Carbon TerraVault business and our other CCS projects or, alternatively, the construction or operation of applicable projects may be substantially delayed such that one or more projects is unprofitable or otherwise infeasible.
The current administration signed several Executive Orders reversing, revoking or rescinding many climate-related actions and has expressed a desire to make modifications to the Inflation Reduction Act. On January 20, 2025, the current administration issued an Executive Order which paused distribution of federal funds appropriated through the IRA or the Infrastructure Investment and Jobs Act. The pause was aimed at providing time to review the processes, policies and issuance of various grants, loans, contracts or financial disbursements of appropriated funds but did not modify the IRA statutory language with respect to federal income tax credits, such as 45Q or 45V credits (for more information, see Tax law changes could have an adverse effect on our business, financial condition and results of operations). However, on January 29, 2025, the White House Office of Management and Budget rescinded the freezing of federal grants and loans, although not its efforts to review the processes with respect to federal spending. At this time, the potential impact of these various actions remains uncertain. If the current administration or Congress repeals, modifies, or otherwise limits the grants, funding and tax incentives made available under the IRA, such actions could particularly harm our carbon management business and its prospects.
If the existing legal requirements for incentives such as the 45Q credit, the 45V credit or LCFS credits are eliminated or subsequently amended in a manner that such incentives no longer apply or are restricted in application, directly or indirectly, to our projects, we may not be able to successfully achieve an economic return from our Carbon TerraVault business and our other CCS projects or, alternatively, the construction or operation of applicable projects may be substantially delayed such that one or more projects is unprofitable or otherwise infeasible.
The ability to monetize the 45Q credit is not certain. Either the owner of the carbon capture equipment or the sequester must have the ability to use the 45Q credit itself, or the owner of the carbon capture equipment must utilize direct pay (which is generally limited to the first five years of the twelve-year credit period), procure tax equity financing, or transfer the credits to another taxpayer. Similar issues exist with respect to the monetization of the 45V credit. The accessibility of direct pay, tax equity financing, and the credit transfers market for tax credits provided under the Inflation Reduction Act is still developing for the 45Q and 45V credits, and therefore uncertainties and complexities with respect to our (or our partners) ability to efficiently monetize the 45Q credit and the 45V credit exist.
The 45Q credit and the LCFS credits require that the captured CO2 be stored in secure geological storage for long periods of time. If we are not able to satisfy this requirement for the duration of time required, there is the risk of recapture of 45Q credits or LCFS credits from us (or our partners) by the government, as well as a risk of indemnification obligations to our partners, claims from landowners and potential for fines and penalties for violations of environmental requirements. Accidental releases of CO2 could also adversely impact our ability to meet our emissions goals.
There can be no assurances that we (or our partners) will successfully comply with the requirements for the available tax credits or LCFS, and such failure could have an adverse effect on our business, financial condition and results of operations.
Our Carbon TerraVault JV with Brookfield is subject to inherent uncertainties which could adversely affect our ability to implement our carbon management strategy.
In August 2022, we entered into the Carbon TerraVault JV with Brookfield to pursue the development of a carbon management segment in California. The management and financing of the joint venture are subject to inherent uncertainties. These uncertainties could potentially force us to delay or cancel CCS projects or to seek alternative sources of capital to fund our CCS projects, any of which could adversely affect our ability to achieve our emissions and other goals related to our carbon management activities.
Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through Carbon TerraVault JV. Brookfield has contributed $92 million to date. The remaining amount of Brookfield's initial investment will depend on the amount of storage capacity that is permitted subject to certain contractual adjustments. The parties have certain put and call rights with respect to the 26R reservoir if certain milestones are not met. Future storage projects for Brookfield’s initial commitment are subject to approval of the joint venture, including Brookfield. There can be no assurances that any of these funding milestones will be achieved so that Brookfield will fund the rest of its commitment.
Furthermore, even though we own a 51% interest in the Carbon TerraVault JV, we share decision making power with Brookfield on matters that most significantly impact the economic performance of the joint venture. Any failure to reach a decision with Brookfield could potentially prevent or delay our pursuit of CCS projects or cause such projects to be cancelled. Moreover, if Brookfield does not approve a proposed CCS project that we want to pursue, we will have to seek alternative sources of capital to fund the project and there can be no assurances that such sources of capital will be available.
Risk Factors Related to Our Business Generally
Increasing activism against the industries in which we operate, including the oil and gas industry and our involvement in carbon capture, storage, utilization and sequestration, presents risks to our business.
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. 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 were recently 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 sought the shut down of the Long Beach Unit on the basis of a purported CEQA violation by certain governmental entities. While the court ruled against the claimants in this matter, we cannot provide any assurances that we will be similarly successful in any future litigation by activists.
This opposition also extends to our carbon management segment as certain activists oppose carbon capture and sequestration efforts by the oil and gas industry for various reasons. For example, on November 22, 2024, a group of non-governmental organizations filed a Petition for Writ of Mandate and Complaint for Injunctive Relief against Kern County and its Board of Supervisors (CTV I Complaint) in Kern County for our CTV I project. See Regulation of Carbon Capture, Sequestration and Storage - CCS Project Permitting. Such lawsuits have the potential to delay timely construction of the project and commencement of operations and could otherwise have a material and adverse effect on our carbon management business and its prospects.
Due to heightened concerns around climate change and GHG emissions, there is often considerable pressure on lawmakers, regulators and others to take action with respect to these allegations regardless of their perceived merit. This pressure is particularly high in California. We may need to incur significant costs associated with responding to these initiatives and such actions may have a material adverse effect on our financial results. Complying with any resulting additional legal or regulatory requirements that are substantial or prevent our activity could have a material adverse effect on our business, financial condition and results of operations.
Increased attention to ESG matters may adversely impact our business.
We face increased attention and expectations from various sources related to our business. This includes increased social expectations on energy companies to address climate change and other environmental and social impacts. In addition, investors and others have evolving expectations regarding voluntary or mandatory ESG disclosures. Finally, increased consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation. Any of the foregoing negative impacts on our stock price and access to capital. Increased attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. While we may participate in various voluntary frameworks and certification programs to improve or support the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on expectations and assumptions or hypothetical scenarios that may or may not be representative of actual risks or events, including the costs associated therewith. Such expectations, assumptions or hypothetical scenarios are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets, such targets are often aspirational and may be subject to change depending on changed circumstances, methodologies, business forecasts or other factors. For example, we are reviewing the impact of the Aera Merger and its assets on our ability to meet our previously announced 2045 Full-Scope Net Zero goal and may revise our goal to reflect our current business and other considerations. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent we do meet such targets, they may ultimately be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net zero goals, or that, notwithstanding our reliance on any reputable third-party registries, that the offsets we do purchase will successfully achieve the emissions reductions they represent. Some of these arrangements may receive scrutiny from certain constituencies who criticize the methodology of offsets or do not believe offsets should be utilized to neutralize GHG emissions. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to pursue or implement such goals because of potential costs or technical or operational obstacles.
Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to evaluate their investment and voting decisions. Companies in the energy industry, and in particular those focused on oil or natural gas extraction, often do not score as well under ESG assessments compared to companies in other industries. While such ratings do not impact all investors' investment or voting decisions, unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of their investment away from the fossil fuel industry to other industries which could have a negative impact on our stock price and our access to and costs of capital. To the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations.
Public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain employment practices or social initiatives, are becoming increasingly subject to heightened scrutiny from public and governmental authorities. For example, the SEC has recently taken enforcement action against companies for ESG-related misconduct, including alleged “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. Certain non-governmental organizations and other private actors have filed lawsuits against entities under various securities and consumer protection laws alleging that certain ESG statements, goals, or standards were misleading, false or otherwise deceptive. Certain employment practices or social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. More recent political developments could mean that the Company faces increasing criticism or litigation risks from certain “anti-ESG” parties, including various government agencies. Such sentiment may focus on the Company’s environmental commitments (such as reducing GHG emissions) or its pursuit of certain employment practices or social initiatives, which anti-ESG proponents may assert as unlawful, political or polarizing in nature or are alleged to violate laws based, in part, on changing priorities of, or interpretations by, federal agencies or state governments. Consideration of ESG-related factors in the Company’s decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties. As a result, the Company may be subject to pressure from the media or through other means, such as governmental investigations, enforcement actions, or other proceedings, all of which could adversely affect our reputation and our business. Accordingly, there may be increased costs related to review, implementation, and management of such policies, as well as compliance and litigation risks based both on positions we do or do not take, or work we do or do not perform.
Such ESG-related matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
Acquisition and disposition activities, including continued integration of the Aera Merger, involve substantial risks.
We engage in acquisition activities from time to time, including the Aera Merger which closed on July 1, 2024. The Aera Merger and other acquisition activities carry risks that we may:
•not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances;
•bear unexpected integration costs or experience other integration difficulties;
•assume liabilities that are greater than anticipated; and
•be exposed to currency, political, marketing, labor and other risks.
In connection with our acquisitions, we are often only able to perform limited due diligence. Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing for recovering the reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact and incomplete, and we may be unable to make these assessments with a high degree of accuracy.
Our acquisition activities may require us to seek approvals from our shareholders, government agencies or other regulatory bodies, depending on the nature and extent of the businesses being acquired. There can be no assurances that we would be able to obtain such approvals. If we are not able to complete acquisitions, we may not be able to grow our reserves or develop our properties in a timely manner or at all.
We regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Our disposition activities carry risks that we may:
•not be able to realize reasonable prices or rates of return for assets;
•be required to retain liabilities that are greater than desired or anticipated;
•experience increased operating costs; and
•reduce our cash flows if we cannot replace associated revenue.
There can be no assurance that we will be able to divest assets on financially attractive terms or at all. Our ability to sell assets is also limited by the agreements governing our indebtedness. If we are not able to sell assets as needed, we may not be able to generate proceeds to support our liquidity and capital investments.
In addition, we have expended and will continue to expend significant time and resources in connection with any future acquisition and disposition activities.
We may incur substantial losses and be subject to substantial liability claims as a result of pollution, environmental conditions or catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not fully insured against all risks. Our business and assets are subject to risks from natural disasters and operating risks associated with oil and natural gas exploration and production activities. Pollution or environmental conditions with respect to our operations or on or from our properties, whether arising from our operations or those of our predecessors or third parties, could expose us to substantial costs and liabilities. Such events may cause operations to cease or be curtailed and could adversely affect our business, workforce and the communities in which we operate. The cost and availability of insurance for natural disasters has increased in recent years. We may be unable to obtain, or may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is excessive relative to the risks presented.
Cybersecurity attacks, systems failures, and other disruptions could adversely affect us.
We rely on electronic systems and networks to communicate, control and manage our exploration, development and production activities. We also use these systems and networks to prepare our financial management and reporting information, to analyze and store data and to communicate internally and with third parties, including our service providers and customers. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected.
Cybersecurity attacks on businesses have escalated and become more sophisticated. If we or the third parties with whom we interact were to experience a successful attack, the potential consequences to our business, workforce and the communities in which we operate could be significant. We utilize various technologies, controls and procedures, as well as internal staff and external specialists to protect our systems and data, to identify and remediate vulnerabilities and to monitor and respond to threats. However, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. If a breach occurs, it may remain undetected for an extended period of time. If we or third parties with whom we interact were to experience a cybersecurity attack or a successful breach, the potential consequences could be significant, including loss of data, loss of business, damage to our reputation, potential financial or legal liability requiring us to incur significant costs, disruptions related to investigations and costs related to remediation.
Energy-related assets may be at a greater risk of strategic terrorist attacks or cybersecurity attacks than other targets. A cybersecurity attack on the digital technology that controls most oil and natural gas refining and distribution necessary to transport and market our products could impact critical distribution and storage assets or the environment, disrupt energy markets by delaying or preventing product delivery, or make it difficult or impossible to accurately account for production and settle transactions.
As cybersecurity threats continue to evolve in sophistication and magnitude, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any cybersecurity vulnerabilities. Further, state and federal cybersecurity and data privacy legislation could result in complex new requirements that increase our cost of doing business.
Risks Related to Regulation and Government Action
We may face material delays related to our ability to timely obtain permits necessary for our operations or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.
We must obtain various governmental permits to conduct exploration and production activities, as well as other aspects of our operations. Obtaining the necessary governmental permits is often a complex and time-consuming process involving numerous federal, state and local agencies. The duration and success of each permitting effort is contingent upon many variables not within our control. In the context of obtaining permits or approvals, the Company will need to comply with known standards, existing laws (such as CEQA), and regulations that may entail greater or lesser costs and delays depending on the nature of the activity to be permitted and the interpretation of the laws and regulations implemented by the permitting authority.
In recent years, we have experienced significant delays with respect to obtaining new well, sidetrack, deepening and rework permits from CalGEM for our operations. A variety of factors outside of our control can lead to such delays. Recent changes in CalGEM management have contributed to permitting delays and uncertainty with respect to our ability to timely obtain permits for our operations. Following such change in management, during the second half of 2023 CalGEM focused on the development of standard operating procedures (SOPs) for permit review, and as a practical matter ceased issuing permits pending the completion of this process. CalGEM released its SOP for the review of applications for rework permits in late Q4 2023 and recently finalized its Lead Agency Preliminary Review process for sidetrack permits. In 2024, CalGEM resumed issuing permits for reworks and sidetracks to CRC and other operators. Subject to limited exceptions, CalGEM has not issued any permits for new production wells to any operators since December 2022.
We have experienced delays obtaining permits as a result of litigation related to the Kern County EIR for the past several years. Most recently, in March 2023, Kern County was directed to prepare a revised EIR that corrects certain CEQA violations, circulate the revised EIR for public review and comment, and prepare and publish responses to any comments received before certifying the revised EIR. The suspension of the Kern County EIR remains in effect. We are in the process of pursuing alternative pathways for addressing CEQA compliance for our oil and natural gas permitting process, this would be a lengthy process and we cannot predict with complete certainty whether we would be able to timely obtain permits using this alternative.
As a result of these issues and current lack of permits with respect to our Kern County properties, we currently plan to operate one active rig within Kern County in 2025 and have the requisite number of permits in hand to keep that rig active throughout the year. We also plan to increase our active rig count in Kern County from one rig to two in the second half of 2025 based on our existing permits. However, there is no certainty that we will obtain permits on that timeline or at all, which may further adversely affect our future development plans, proved undeveloped reserves, business, operations, cash flows, financial position and results of operations. In 2025, approximately $21 million of capital to develop proved reserves relates to drilling and completing sidetracks in Kern County for which we do not presently have a permit.
We have also experienced delays obtaining drilling permits from CalGEM since the passage of Senate Bill No. 1137, which established 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. The law became effective January 1, 2023 and CalGEM issued emergency regulations implementing the requirements of the law on January 6, 2023. However, on February 3, 2023, the Secretary of State of California certified voter signatures collected in connection with a referendum for the November 2024 ballot to repeal Senate Bill No. 1137. However, in June 2024, the ballot proposal was withdrawn with the proposal’s sponsors indicating a view to challenging Senate Bill No. 1137 in court. The provisions of Senate Bill No. 1137 became effective immediately in June 2024. Then, on September 30, 2024, the Governor signed into law Assembly Bill 218, which delays the deadline for some compliance with CalGEM’s regulations implementing Senate Bill No. 1137 until July 1, 2026, and further delays compliance with certain other requirements of Senate Bill No. 1137 by up to three years. There is continued uncertainty with respect to the ability to book proved undeveloped reserves and drill within the setback zone established by Senate Bill No. 1137. As a result, we do not have and proved undeveloped reserves booked within currently defined setback zones as of year-end 2024. As a result of Senate Bill No. 1137, in addition to write-downs recorded in 2023, we further reduced the net present value of our proved undeveloped reserves by 6% and our overall proved reserves by 1% in 2024. We expect any further impact from SB 1137 to proved reserves to be minimal. (See Part I, Item 1 and 2 - Business and Properties, Regulation of Exploration and Production Activities for more information).
In 2025, none of our aggregate capital to develop proved reserves relates to drilling and completing wells in Wilmington for which we do not presently have a permit. We do not plan on operating an active drilling rig in Wilmington in 2025. However, there is no certainty that we will be able to obtain a permit in the future, which may further adversely affect our future development plans, proved undeveloped reserves, business, operations, cash flows, financial position and results of operations.
We cannot guarantee that these issues or new ones that may arise in the future will not continue to delay or otherwise impair our ability to obtain drilling permits. In the past we have generally been able to mitigate permitting risks by building up a reserve of drilling permits for use throughout the year, but as a result of the issues described above, we have not been able to build our reserve of approved permits to the same level as we have in the past. If we cannot obtain new drilling or sidetrack permits in a timely manner, we have limited options to meet our drilling plans, such as the use of workovers to extend the life of existing production, which may not ultimately be sufficient to achieve our business goals. Any continuing failure to obtain certain permits or the adoption of more stringent permitting requirements could have a material adverse effect on our business, financial condition and results of operations.
We may face increased local restrictions on oil and gas exploration and production operations or even be prohibited from operating in certain areas as a result of recently enacted California legislation.
On September 25, 2024, Assembly Bill 3233 (AB 3233) was enacted which authorizes local governments to prohibit, oil and gas operations or development, or impose regulations, limits or prohibitions that are more protective of public health, the climate or the environment than prescribed by state law, regulation or order on such oil and gas operations or development, within their jurisdiction, including with respect to existing operations. Prior to the passage of this law, certain local governments within California had previously taken steps to limit oil and gas operations that were struck down by California courts. Monterey County previously sought to ban only new production and prohibit the use of wastewater injection as a production method. The City and County of Los Angeles previously sought to both ban new wells and phaseout existing wells over a certain period of time. If these bans were enacted, for the year ended December 31, 2024, less than 1% of our net production and proved reserves were located in the City of Los Angeles; and our operations are otherwise in unincorporated areas of Los Angeles, which would not be affected by such bans. Approximately 2% of our net production and 1% of proved reserves were located in Monterey County as of and for the year ended December 31, 2024. Although both of those local measures were struck down in court, following the adoption of AB 3233, certain legal arguments used to challenge these local actions are no longer valid and it is possible that these or other local governments in places where we operate may pass similar regulations. It is difficult to predict how local governments in California may choose to exercise their new authority under AB 3233.
While there may be future legal challenges to AB 3233 and any local ordinances enacted thereunder, we cannot predict whether or not such challenges will be successful. Notwithstanding any potential claims for regulatory takings we may have in the event local jurisdictions seek to prohibit any of our existing operations, to the extent that the local governments in the areas where we operate in California enact new restrictions or prohibitions with respect to oil and gas exploration and production activities, we could face increased operating costs, loss of revenues, and other material and adverse impacts to our business and results of operations.
Recent and future actions by the State of California could reduce both the demand for and supply of oil and natural gas within the state and consequently have a material and adverse effect on our business, and financial condition and results of operations.
In recent years, the Governor of California, the Legislature and state agencies have taken a series of actions that could materially and adversely affect the state’s oil and natural gas sector. For additional information, see Part I, Item 1 and 2 - Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities, and Risk Factors, We may face material delays related to our ability to timely obtain permits necessary for our operations, or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.
The trend in California is to impose increasingly stringent restrictions on oil and natural gas activities. We cannot predict what actions the Governor of California, the Legislature or state agencies may take in the future, but we could face increased compliance costs, delays in obtaining the approvals necessary for our operations, exposure to increased liability, or other limitations as a result of future actions by these parties. Moreover, new developments resulting from the current and future actions of these parties could also have a material and adverse effect on our ability to operate, successfully execute drilling plans, or otherwise develop our reserves. Accordingly, recent and future actions by the Governor of California, the Legislature, and state agencies could have a material and adverse effect on our business, results of operations, and financial condition.
Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans.
Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products.
To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, stimulation, operation, inspection, maintenance, transportation, storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and threatened or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection and disposal and water consumption, recycling and reuse. For example, our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by both the City of Long Beach and CalGEM. We are currently in discussions with the City of Long Beach and CalGEM with respect to what injection well pressure gradient complies with CalGEM’s requirements for the protection of underground aquifers while at the same time mitigating subsidence risks. CalGEM’s local office has preliminarily indicated that the injection well pressure gradient should be reduced from the gradient that has been used for several decades. As part of our ongoing discussions, we and the City of Long Beach have provided CalGEM with technical information regarding how the historical injection well pressure gradient complies with CalGEM’s requirements and to inform them of the absence of risk of leakage and a plan to gradually lower the injection gradient over time in a manner that we believe would mitigate subsidence risks. If CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient other than in a gradual manner or at a gradient which we believe is unnecessary, and we were unable to reverse that decision on appeal or other legal challenge, we expect that any such reduction in injection well pressure gradient for our operations in the Wilmington Oil Field could result in a decrease in production and reserves from the field.
Failure to comply may result in the assessment of administrative, civil and/or criminal fines and penalties, liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or prohibiting certain operations or our access to property, water, minerals or other necessary resources, and may otherwise delay or restrict our operations and cause us to incur substantial costs. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
Our Carbon TerraVault business and our CCS projects are subject to extensive government regulation much of which is still being developed. Failure to comply with these regulations and obtain the necessary permits, or the development of government regulations that are unfavorable to our CCS projects, could have an adverse effect on our business, financial condition and results of operations.
Successful development of CCS projects in the United States require that we comply with what we anticipate will be a stringent regulatory scheme requiring that we obtain certain permits applicable to subsurface injection of CO2 for geologic sequestration. Moreover, as the operator of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response. There are no assurances that we will be successful in obtaining or maintaining permits or adequate levels of financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition, or otherwise.
Separately, permitting CCS projects requires obtaining a number of other permits and approvals unrelated to subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility. We cannot guarantee that we will be able to obtain or maintain all applicable permits for CCS activities on a timely basis or on favorable terms, if at all. Moreover, to the extent any of our CCS projects will require any supporting pipeline infrastructure, we could face additional costs and delays obtaining the necessary permits and rights of ways for such infrastructure, and increased risk of opposition to our projects, which may ultimately mean we are unable to successfully pursue certain CCS projects because of these risks.
As CCS and carbon management represent an emerging sector, laws and regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects. To the extent additional legal or regulatory requirements are imposed, are amended, or more stringently enforced, we may incur additional costs in the pursuit of one or more of our carbon capture projects, which costs may be material or may render any one or more of our projects uneconomical.
New and developing regulations related to the CO2 unitization, permitting and pipeline safety could negatively impact our business, financial condition and results of operations.
Senate Bill No. 905 contemplates the development of unitization, permitting and pipeline safety regulations over a multi-year period to facilitate the development of CCS projects in California, though the legislation does not provide for compulsory unitization. Senate Bill No. 905 also provides for a unified permitting process to simplify the permitting process for CCS projects, although this will be optional for project applicants. Additionally, the law contemplates the implementation of a new regulatory program incorporating standards that are not yet defined and that could affect the timing of future CCS projects in California. The California Air Resources Board has been tasked with developing this proposed framework. We believe our Carbon TerraVault projects will continue to be developed on a timeline consistent with our initial expectations. These initial projects are not reliant on the unitization or permitting regulations being developed. In addition, our Carbon TerraVault projects are expected to either use emitters that are directly sited above these storage facilities or rely on pipelines for transporting CO2 Senate Bill No. 905 provides that pipelines may be used to transport carbon dioxide to or from a carbon dioxide capture, removal or sequestration project only upon conclusion of PHMSA’s rulemaking strengthening safety requirements for carbon dioxide pipelines. Although PHMSA released a notice of proposed rulemaking to this effect in early January 2025, it has not yet been published in the Federal Register and its disposition is uncertain at this time. The terms of these final pipeline safety regulations may impair or prohibit projects that rely on the transportation of CO2.
Senate Bill No. 905 also prohibits CCS projects that utilize and permanently sequester CO2 in connection with EOR projects. Although we do not have any existing oil and natural gas production or proved reserves associated with EOR projects, this legislation required us to transition our CalCapture project to target CCS and may require us to make other adjustments to projects in the future.
Our operations and financial performance may be negatively affected directly or indirectly by changes in trade policies and tariffs.
In recent years, the United States increased tariffs for certain goods, which triggered other nations to also increase tariffs on certain of their goods. In recent weeks, the current administration has made many announcements regarding tariffs and the extent and duration of such tariffs remain uncertain. If maintained, the newly announced tariffs and the potential escalation of trade disputes could pose a risk to our business and also directly impact our operating expenses. For example, recently announced 25% tariffs on imported steel are likely to lead to increased material costs.
Concerns about climate change and other environmental issues may prompt governmental action that could have a material adverse effect on our operations or results.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions, and regulation of GHGs and other air quality issues, may have a material adverse effect on our business in many ways, including increasing the costs to provide our products and services and reducing demand for, and consumption of, our products and services, and we may be unable to recover or pass through a significant portion of our costs. In addition, legislative and regulatory responses to such issues at the federal, state and local level may increase our capital and operating costs and render certain wells or projects uneconomic, and potentially lower the value of our reserves and other assets. Both the EPA and California have implemented laws, regulations and policies that seek to reduce GHG emissions. California’s cap-and-trade program operates under a market system and the costs of such allowances per metric ton of GHG emissions are expected to increase in the future as the CARB tightens program requirements and annually increases the minimum state auction price of allowances and reduces the state’s GHG emissions cap. As the foregoing requirements become more stringent, we may be unable to implement them in a cost-effective manner, or at all.
In August 2022, President Biden signed the Inflation Reduction Act into law. The Inflation Reduction Act includes a charge on methane emissions that exceed certain thresholds from sources required to report their GHG emissions to the EPA, including certain oil and natural gas operations. The methane emissions charge began in 2024 at $900 per ton of methane, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and subsequent years. We cannot predict if Congress may take actions to repeal or revise the Inflation Reduction Act, including with respect to the methane emissions charge. In fact, the full impact of future climate regulations is uncertain at this time and it is unclear what additional actions may be taken that may have an adverse effect upon our carbon management business and its prospects.
To the extent financial markets view climate change and GHG or other emissions as an increasing financial risk, this could adversely impact our cost of, and access to, capital and the value of our stock and our assets. Current investors in oil and natural gas companies may elect in the future to shift some or all of their investments into other sectors, and institutional lenders may elect not to provide funding for oil and natural gas companies. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector, although this trend has waned recently and several high-profile banks and institutional investors have withdrawn from various associations that aim to limit financing of industries that emit significant GHG emissions. Additionally, in March 2024, the Securities and Exchange Commission (SEC) released a final rule that establishes a framework for the reporting of climate risks, targets and metrics. However, the future of the rule is uncertain at this time given that its implementation has been stayed pending the outcome of legal challenges. Moreover, the Commission may, under the current Administration seek to change or revoke the rule, though we cannot predict whether such action will occur or its timing. Relatedly, California has enacted new laws requiring additional disclosure with respect to certain climate-related risks and GHG emissions reduction claims. (See Part I, Item 1 and 2 - Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Climate Change and Greenhouse Gas (GHG) Emissions for more information). Non-compliance with these new laws may result in the imposition of substantial fines or penalties. Other states are considering similar laws. Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate-related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, additional costs to comply with any such disclosure requirements and increased costs of and restrictions on access to capital.
We believe, but cannot guarantee, that our local production of oil, NGLs and natural gas will remain essential to meeting California’s energy and feedstock needs for the foreseeable future. We have also established 2030 Sustainability Goals for water recycling, renewables integration, methane emission reduction and carbon capture and sequestration in our life-of-field planning in an attempt to align with the state’s long-term goals and support our ability to continue to efficiently implement federal, state and local laws, regulations and policies, including those relating to air quality and climate, in the future. However, there can be no assurances that we will be able to design, permit, fund and implement such projects in a timely and cost-effective manner or at all, or that we, our customers or end users of our products will be able to satisfy long-term environmental, air quality or climate goals if those are applied as enforceable mandates.
The adoption and implementation of new or more stringent international, federal, state or local legislation, regulations or policies that impose more stringent standards for GHG or other emissions from our operations or otherwise restrict the areas in which we may produce oil, natural gas, NGLs or electricity or generate GHG or other emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or the value of our products and services. Additionally, political, litigation and financial risks may result in restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages or other losses as a result of climate change, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may pose increasing risks of physical impacts to our operations and those of our suppliers, transporters and customers through damage to infrastructure and resources resulting from drought, wildfires, sea level changes, flooding and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.
The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could impose new costs on our operations.
In August 2022, President Biden signed the Inflation Reduction Act into law. The Inflation Reduction Act contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and CCS, amongst other provisions. In addition, the Inflation Reduction Act imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. The Inflation Reduction Act amends the Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production categories. The methane emissions charge began in calendar year 2024 at $900 per ton of methane, increased to $1,200 in 2025, and will be set at $1,500 for 2026 and each year thereafter. Calculation of the fee is based on certain thresholds established in the Inflation Reduction Act. However, compliance with the EPA’s new methane rules (see Part I, Item 1 and 2 - Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Climate Change and Greenhouse Gas (GHG) Emissions) would exempt an otherwise covered facility from the requirement to pay the fee. In addition, the multiple incentives offered for various clean energy industries referenced above could further accelerate the transition of the economy away from fossil fuels towards lower- or zero-carbon emission alternatives. The methane charges and various incentives for clean energy industries could decrease demand for crude oil and natural gas and increase our compliance and operating costs, which consequently could have a material adverse effect on our business and results of operations. However, at this time, we cannot predict if Congress may take actions to repeal or revise the Inflation Reduction Act, including with respect to the methane emissions charge.
Tax law changes could have an adverse effect on our business, financial condition and results of operations.
We are subject to taxation by various tax authorities at the federal, state and local levels where we do business. New legislation could be enacted by any of these government authorities that could adversely affect our business.
In addition, from time to time, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits currently available to oil and natural gas exploration and production companies. Such changes have included, but have not been limited to: (i) the repeal of percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) an extension of the amortization period for certain geological and geophysical expenditures; (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies; and (v) an increase in the U.S. federal income tax rate applicable to corporations such as us. However, it is unclear whether any such changes will be enacted and, if enacted, how soon any such changes would be effective. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced demand for our products. The passage of any such legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development or could increase costs and any such changes could have an adverse effect on our business, financial condition and results of operations. Similarly, legislation could be enacted that changes or terminates the current tax incentives that our CCS projects depend on to be economical. The enactment of any legislation that reduces or eliminates 45Q credits or tax credits for the production of clean hydrogen could have an adverse effect on our business, financial condition and results of operations.
In California, there have been numerous state and local proposals for additional income, sales, excise and property taxes, including additional taxes on oil and natural gas production and a windfall profits tax on refineries. Although such proposals targeting the oil and natural gas industry have not become law, campaigns by various interest groups could lead to additional future taxes.
Financial assurance requirements related to plugging and abandonment costs, decommissioning, and site restoration on those who acquire the right to operate wells and production facilities could impact our ability to sell or acquire assets in California or increase our costs in connection with the same.
California law imposes stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in California, requiring them to file either an individual indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities. The bond imposed on the acquirer is an amount determined by the state to sufficiently cover plugging and abandonment costs, decommissioning, and site restoration, and California law prohibits the closing of any acquisition of the right to operate a well or production facility until a determination on the appropriate bond amount has been completed by the state and the bond has been filed. This bonding requirement significantly impacts the economic feasibility of transferring the right to operate wells and production facilities, including transfers from smaller, less-capitalized operators to more financially stable operators such as ourselves. As of the year ended December 31, 2024, our asset retirement obligations were $1,129 million, including the obligations assumed as part of the Aera Merger. This law will continue to impact our ability to grow or divest our assets within California.
Risks Related to our Indebtedness
We may not be able to amend or refinance our existing debt to create more operating and financial flexibility and to enhance shareholder returns.
Our ability to refinance our debt depends on a variety of factors, including our ability to access the commercial banking and debt capital markets. Changes in interest rates could also impact our ability to refinance our debt. If interest rates increase, the interest expense burden of any refinanced debt or other variable rate debt would increase even though the amount borrowed remained the same. There can be no assurances that we will be successful in amending, replacing or refinancing our existing debt on acceptable terms or at all.
Our existing and future indebtedness may adversely affect our business and limit our financial flexibility.
As of December 31, 2024, we had $1,132 million of total long-term debt, net and additional borrowing capacity of $983 million under the Revolving Credit Facility (after taking into account $167 million of outstanding letters of credit). The terms of our Revolving Credit Facility and Senior Notes permit us to incur significant additional debt, some of which may be secured. Our level of future indebtedness could affect our business in several ways, including the following:
•limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•require us to dedicate a portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities due to restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
•limit our ability to pay dividends and repurchase shares;
•increase our vulnerability to downturns and adverse developments in our business and the economy generally;
•limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other expenses, or to refinance existing indebtedness;
•make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
•make us vulnerable to increases in interest rates as our indebtedness under the Revolving Credit Facility varies with prevailing interest rates.
Our ability to satisfy our obligations depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. Our business may not generate sufficient cash flow, and future financings may not be available to provide sufficient net proceeds, to meet these obligations or to successfully execute our business strategy.
We may not be able to generate sufficient cash to service all of our indebtedness, and may be forced to take other actions to satisfy the obligations under our indebtedness, which may not be successful.
Our earnings and cash flow could vary significantly from year to year due to the nature of our industry despite our commodity price risk-management activities. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments at that time. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control as discussed in this “Risk Factors” section. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
The lenders under our Revolving Credit Facility could limit our ability to borrow and restrict our use or access to capital.
Our Revolving Credit Facility is an important source of our liquidity. Our ability to borrow under our Revolving Credit Facility is limited by our borrowing base, the size of our lenders’ commitments and our ability to comply with covenants.
The borrowing base under our Revolving Credit Facility is redetermined semi-annually by our lenders who review the value of our reserves and other factors that may be deemed appropriate. Currently, our borrowing base is set at $1.5 billion and the availability under our Revolving Credit Facility is limited to the aggregate elected commitment amount of our lenders, which as of February 1, 2025 is $1.15 billion.
A reduction in our borrowing base below the aggregate commitment amount of our lenders would have a material adverse effect on our liquidity and may hinder our ability to execute on our business strategy.
Restrictive covenants in our Revolving Credit Facility and the indentures governing our Senior Notes may limit our financial and operating flexibility.
Both our Revolving Credit Facility and the indentures governing our Senior Notes contain certain restrictions, which may have adverse effects on our business, financial condition or results of operations. These restrictions limit our ability to, among other things, (i) incur additional indebtedness; (ii) pay dividends or repurchase shares; (iii) sell properties; and (iv) make capital investments.
The Revolving Credit Facility also requires us to comply with certain financial maintenance covenants, including a leverage ratio and current ratio.
A breach of any of these restrictive covenants could result in a default under the Revolving Credit Facility and/or the Senior Notes. If a default occurs under the Revolving Credit Facility, the lenders may elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to be immediately due and payable. If we are unable to repay our indebtedness when due or declared due, the lenders under the Revolving Credit Facility will also have the right to proceed against the collateral pledged to them to secure the indebtedness. An event of default under the Senior Notes may cause all outstanding Senior Notes to become due and payable immediately or give the trustee and the holders the right to declare all outstanding Senior Notes to become due and payable immediately.
Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our Revolving Credit Facility are at variable rates of interest and expose us to interest rate risk. As of December 31, 2024, we had no amounts borrowed under our Revolving Credit Facility. If in the future we borrow under the Revolving Credit Facility, then our results of operations would be sensitive to movements in interest rates. There are many economic factors outside our control that have in the past and may, in the future, impact rates of interest including publicly announced indices that underlie the interest obligations related to our Revolving Credit Facility. Factors that impact interest rates include governmental monetary policies, inflation, economic conditions, changes in unemployment rates, international disorder and instability in domestic and foreign financial markets. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our results of operations would be adversely impacted. Such increases in interest rates could have a material adverse effect on our business, financial condition and results of operations if we borrow under the Revolving Credit Facility in the future.
Risks Related to Our Common Stock
Our ability to pay dividends and repurchase shares of our common stock is subject to certain risks.
We have adopted a cash dividend policy which anticipates a total annual dividend of $1.55 per share, payable to shareholders in quarterly increments of $0.3875 per share of common stock, subject to board authorization and declaration each quarter. Our Board of Directors authorized a share repurchase program to acquire up to $1.35 billion of our common stock through December 31, 2025. As of December 31, 2024 we had approximately $557 million of remaining authorized capacity. Any payment of future dividends or repurchasing shares of our common stock will be at the discretion of our Board of Directors and will depend upon, among other things, our earnings, liquidity, capital requirements, financial condition and other factors deemed relevant. Our Revolving Credit Facility and Senior Notes both limit our ability to pay dividends and repurchase shares of our common stock. In addition, cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. We can provide no assurances that we will continue to pay dividends at the anticipated rate or repurchase shares of our common stock within the authorized amount or at all.
The trading price of our common stock may decline, and you may not be able to resell shares of our common stock at prices equal to or greater than the price you paid or at all.
The trading price of our common stock may decline for many reasons, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. Numerous factors, including those referred to in this "Risk Factors" section could affect our stock price. These factors include, among other things, changes in our results of operations and financial condition; changes in commodity prices; changes in the national and global economic outlook; changes in applicable laws and regulations; variations in our capital plan; changes in financial estimates by securities analysts or ratings agencies; changes in market valuations of comparable companies; and additions or departures of key personnel.
Future issuances of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
As of December 31, 2024, we had 91,100,322 outstanding shares of common stock. We may sell additional shares of common stock in subsequent public or private offerings. We may also issue additional shares of common stock or convertible securities, such as in July 2024 when we issued 21,315,707 shares of common stock in connection with the Aera Merger. We expect to issue additional shares of common stock in connection with post-closing settlements for the Aera Merger. We cannot predict the size of other future issuances of our common stock or securities convertible into common stock or the effect, if any, that such other future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
The ownership position of certain of our stockholders limits other stockholders’ ability to influence corporate matters and could affect the price of our common stock.
As of December 31, 2024, six of our shareholders owned at least 5% each and collectively owned approximately 57% of our common stock. As a result, each of these stockholders, or any entity to which such stockholders sell their stock, may be able to exercise significant control over matters requiring stockholder approval. Further, because of this large ownership position, if these stockholders sell their stock, the sales could depress our share price. Refer to Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Transactions Related to Our Common Stock for information on the Registration Rights Agreement related to the Aera Merger.
Sales of shares of our common stock by our executive officers could negatively impact the market price for our common stock.
Sales of our common stock by our executive officers may adversely impact the trading price of our common stock, even when done in compliance with our policies with respect to insider sales. Although we do not expect that the relatively small volume of such sales will itself significantly impact the trading price of our common stock, the market could react negatively to the announcement of such sales, which could in turn affect the trading price of our common stock.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B UNRESOLVED STAFF COMMENTS
Not applicable.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS

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ITEM 4. MINE SAFETY DISCLOSURE

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

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ITEM 9A. CONTROLS AND PROCEDURES

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ITEM 9B. OTHER INFORMATION

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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ITEM 11. EXECUTIVE COMPENSATION

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES