EDGAR 10-K Filing

Company CIK: 1609253
Filing Year: 2024
Filename: 1609253_10-K_2024_0001609253-24-000043.json

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ITEM 1. BUSINESS
ITEMS 1 & 2 BUSINESS AND PROPERTIES
Business Overview and History
We are an independent oil and natural gas exploration and production and carbon management company operating properties exclusively within California. We are committed to energy transition and have some of the lowest carbon intensity production in the United States. We are in the early stages of developing several carbon capture and storage projects in California. Our carbon management business, that we refer to as Carbon TerraVault, is expected to build, install, operate and maintain CO2 capture equipment, transportation assets and storage facilities in California.
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.
Recent Developments
Pending Aera Merger
On February 7, 2024, we entered into a definitive agreement and plan of merger (Merger Agreement) to combine with Aera Energy, LLC (Aera) in an all-stock transaction (Aera Merger) with an effective date of January 1, 2024. Aera is a leading operator of mature fields in California, primarily in the San Joaquin and Ventura basins, with high oil-weighted production.
Pursuant to the Merger Agreement, we have agreed to issue 21,170,357 shares of common stock (subject to customary adjustments in the event of stock splits, dividend paid in stock and similar items) plus an additional number of shares determined by reference to the dividends declared by us having a record date between the effective date and closing as more fully described in the Merger Agreement. Under the terms of the Merger Agreement, we have also agreed to assume Aera’s outstanding long-term indebtedness of $950 million at closing. We expect to repay a significant portion of this indebtedness with cash on hand and borrowings under our Revolving Credit Facility. We intend to refinance the balance through one or more debt capital markets transactions and, only to the extent necessary, borrowings under a bridge loan facility provided by Citigroup Global Markets, Inc. (the Bank). Under the terms of our debt commitment letter with the Bank, it has committed, subject to satisfaction of customary conditions, to provide us with an unsecured 364-day bridge loan facility in an aggregate principal amount of $500 million (Bridge Loan Facility).
Closing of the Aera Merger is subject to certain conditions, including, among others, approval of the stock issuance by our stockholders, expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, prior authorization by the Federal Energy Regulatory Commission under Section 203 of the Federal Power Act and other customary closing conditions.
Upon completion of the transaction, we currently expect our existing stockholders to own approximately 77.1% of the combined company and the existing Aera owners to own approximately 22.9% of the combined company, on a fully diluted basis. The Aera Merger is expected to close in the second half of 2024. Post closing of the Aera Merger, and subject to Board approval, we expect to increase our quarterly dividend.
Amendment to our Revolving Credit Facility
In connection with the Merger Agreement, on February 9, 2024, we entered into a second amendment to our Revolving Credit Facility to permit us to incur indebtedness under the Bridge Loan Facility.
Sale of Fort Apache in Huntington Beach
In February 2024, we entered into an agreement to sell our 0.9-acre Fort Apache real estate property in Huntington Beach, California for approximately $10 million.
Oil and Natural Gas Operations
As of December 31, 2023, our proved reserves totaled an estimated 377 MMBoe, of which 256 MMBbl were crude oil and condensate reserves, 35 MMBbl were NGL reserves and 518 BcF, or 86 MMBoe, were natural gas reserves.
As of December 31, 2023, we held approximately 1.7 million net mineral acres, the largest privately owned mineral acreage position in California. Our operated asset base spans 97 distinct fields with approximately 9,000 net operated wells. We had average net production of approximately 86 MBoe/d (60% oil) for the year ended December 31, 2023.
The following table highlights key information about our operations as of and for the year ended December 31, 2023:
San Joaquin Basin Los Angeles Basin Ventura Basin(a)
Sacramento Basin Other Total Operations
Mineral Acreage
Net mineral acreage (thousands)
1,111 28 6 430 117 1,692
Average net mineral acreage held in fee (%) 89 % 49 % - % 45 % 97 % 77 %
Number of producing fields we operate 42 5 - 50 - 97
Average drilling rigs - 1 - - - 1
Net wells drilled and completed 4.0 26.5 - - - 30.5
Proved reserves
Oil (MMBbl) 165 91 - - - 256
NGLs (MMBbl) 35 - - - - 35
Natural gas (Bcf) 456 5 - 57 - 518
Total (MMBoe) 276 92 - 9 - 377
Oil percentage of proved reserves 60 % 99 % - % - % - % 68 %
Production
Total net production (MMBoe) 23 7 - 1 - 31
Average daily net production (MBoe/d) 64 19 - 3 - 86
(a)Reflects one non-operated field in the Ventura basin included in assets held for sale. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions for more information on our Ventura Basin divestiture.
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 hold substantially all the working, surface and mineral interests in the Elk Hills field, which is our largest producing asset in the San Joaquin basin and have a large ownership interest in several other oil fields located in the San Joaquin basin including Buena Vista and Coles Levee. We have also been successfully developing steamfloods in our Kern Front operations.
At Elk Hills 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 the Elk Hills field, and offers excess power to the California Independent System Operator (CAISO) wholesale energy marketplace. We also market power plant capacity in excess of our internal needs to the CAISO Resource Adequacy (RA) marketplace. 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. Large active oil fields in this basin include the Wilmington and Huntington Beach fields, where we have significant operations. 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.
We are pursuing the potential divestiture of our 90-acre Huntington Beach field, which is currently a producing oil field with average daily net production of 3 MBoe/d. At our Huntington Beach field we have begun the plugging and abandonment work of approximately 50 wells in 2024. We are working towards the longer-term remediation of this property to provide flexibility for real estate sales in the future. Refer to Recent Developments above for information on an agreement to sell a one-acre parcel of land in Huntington Beach.
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. We are in the process of pursuing permits to facilitate production growth and develop this resource, leveraging the existing infrastructure already in place.
Ventura Basin
We divested a vast majority of our assets in the Ventura basin other than a de minimis non-operated asset, during the fourth quarter of 2021 and the first quarter of 2022. We expect the sale of our remaining Ventura basin asset could occur in 2024.
Other
Other than the basins described above, we also have mineral interests in undeveloped acreage throughout California including in the Salinas basin and the Santa Maria basin.
Mineral Acreage
The following table summarizes our gross and net developed and undeveloped mineral acreage as of December 31, 2023.
San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin Other(a)
Total
(in thousands)
Developed(b)
Gross(c)
457 20 6 255 2 740
Net(d)
420 15 6 242 1 684
Undeveloped(e)
Gross(c)
811 15 - 226 140 1,192
Net(d)
691 13 - 188 116 1,008
Total
Gross(c)
1,268 35 6 481 142 1,932
Net(d)
1,111 28 6 430 117 1,692
(a)Reflects remaining mineral acreage retained in the Ventura Basin and nearby areas. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions for more information on our Ventura Basin divestiture.
(b)Mineral acres spaced or assigned to productive wells.
(c)Total number of mineral acres in which interests are owned.
(d)Net mineral acreage includes acreage reduced to our fractional ownership interest and interests under our PSCs.
(e)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, 2023, 77% of our total net mineral interest position was held in fee and the remainder was leased. Of our leased acreage, approximately 87% 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 2,000 net mineral acres will expire in 2024, 21,000 net mineral acres will expire in 2025 and 14,000 net mineral acres will expire in 2026. These leases represent 4% of our total net undeveloped acreage and 2% of our total net acreage as of December 31, 2023 and these expirations, should they occur, would not have a material adverse impact 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 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 commodity price increases and inflation on our operating costs per Boe, among other factors.
Year Ended December 31,
Average daily net production
Oil (MBbl/d) 52 55 60
NGLs (MBbl/d) 11 11 13
Natural gas (MMcf/d) 135 147 159
Total daily net production (MBoe/d) 86 91 100
Total production (MMBoe) 31 33 36
Average realized prices
Oil with hedge ($/Bbl) $ 65.97 $ 61.80 $ 56.05
Oil without hedge ($/Bbl) $ 80.41 $ 98.26 $ 70.43
NGLs ($/Bbl) $ 48.94 $ 64.33 $ 53.62
Natural gas without hedge ($/Mcf) $ 8.59 $ 7.68 $ 4.22
Average benchmark prices
Brent oil ($/Bbl) $ 82.22 $ 98.89 $ 70.79
WTI oil ($/Bbl) $ 77.62 $ 94.23 $ 67.91
NYMEX gas ($/MMBtu) - Average Monthly Settled Price $ 2.74 $ 6.64 $ 3.84
Operating costs per Boe
Operating costs $ 26.24 $ 23.75 $ 19.39
Oil, natural gas and NGL production for our two largest fields are presented in the table below:
Elk Hills Wilmington
2023 2022 2021 2023 2022 2021
Average daily net production
Oil (MBbl/d) 16 17 17 16 15 16
NGLs (MBbl/d) 8 8 10 - - -
Natural gas (MMcf/d) 68 75 81 - - -
Total daily net production (MBoe/d) 35 38 40 16 15 16
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 are 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 18% of our total production for the year ended December 31, 2023.
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,
2023 2022 2021
(in millions) ($ per Boe) (in millions) ($ per Boe) (in millions) ($ per Boe)
Operating costs $ 822 $ 26.24 $ 785 $ 23.75 $ 705 $ 19.39
Excess costs attributable to PSCs (71) (2.25) (74) $ (2.23) (66) $ (1.83)
Operating costs, excluding effects of PSCs(a)
$ 751 $ 23.99 $ 711 $ 21.52 $ 639 $ 17.56
(a)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 for fields operated by others) for the periods presented:
Year ended December 31,
2023 2022 2021
(MBoe/d)
Average Daily Net Production 86 91 100
Partners' share under PSC-type contracts 7 8 8
Working interest and royalty holders' share 7 6 8
Other 1 1 1
Average Daily Gross Production 101 106 117
Estimated Proved Reserves and Future Net Cash Flows
The information with respect to our estimated reserves presented below has been prepared in accordance with the rules and regulations of the SEC.
The following tables summarize our estimated proved oil (including condensate), NGLs and natural gas reserves and PV-10 as of December 31, 2023. 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 $82.84 per barrel was adjusted for gravity, quality and transportation costs. For natural gas volumes, the average NYMEX gas price of $2.64 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, 2023 were $80.97 per barrel for oil, $50.00 per barrel for NGLs and $4.57 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, 2023
San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin Total
Proved developed reserves
Oil (MMBbl) 136 87 - - 223
NGLs (MMBbl) 34 - - - 34
Natural Gas (Bcf) 389 5 - 51 445
Total (MMBoe)(a)
235 88 - 8 331
Proved undeveloped reserves
Oil (MMBbl) 29 4 - - 33
NGLs (MMBbl) 1 - - - 1
Natural Gas (Bcf) 67 - - 6 73
Total (MMBoe) 41 4 - 1 46
Total proved reserves
Oil (MMBbl) 165 91 - - 256
NGLs (MMBbl) 35 - - - 35
Natural Gas (Bcf) 456 5 - 57 518
Total (MMBoe) 276 92 - 9 377
Reserves to production ratio (years)(b)
12 13 - 9 12
(a)As of December 31, 2023, approximately 18% of proved developed oil reserves, 7% of proved developed NGLs reserves, 10% of proved developed natural gas reserves and, overall, 15% 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, 2023 divided by total production for the year ended December 31, 2023.
Changes to Proved Reserves
The components of the changes to our proved reserves during the year ended December 31, 2023 were as follows:
San Joaquin Basin Los Angeles Basin(a)
Ventura Basin Sacramento Basin Total
(in MMBoe)
Balance at December 31, 2022
295 113 - 9 417
Revisions related to price (6) (5) - (2) (13)
Revisions related to performance 20 1 - 2 23
Revisions due to California regulatory changes and court challenges (1) (11) - (12)
Extensions
3 1 - 1 5
Improved recovery 1 - - - 1
Divestitures
(12) - - - (12)
Production (24) (7) - (1) (32)
Balance at December 31, 2023
276 92 - 9 377
(a)Includes proved reserves related to PSCs of 76 MMBoe and 92 MMBoe at December 31, 2023 and 2022, respectively.
Revisions related to price - We had net negative price-related revisions of 13 MMBoe primarily resulting from a lower commodity price environment in 2023 compared to 2022. Negative price-related revisions of 22 MMBoe were partially offset by 9 MMBoe of positive revisions from operating cost efficiencies.
Revisions related to performance - We had 23 MMBoe of net positive performance-related revisions which included positive performance-related revisions of 38 MMBoe and negative performance-related revisions of 15 MMBoe. Our positive performance-related revisions primarily related to better-than-expected well performance. Our negative performance-related revisions primarily were due to wells and incremental waterflood response that underperformed forecasts and removal of proved undeveloped locations due to unsuccessful drilling results in certain areas. The majority of these revisions were located in the San Joaquin basin.
Revisions due to California regulatory changes and court challenges - We had 12 MMBoe of negative revisions to our proved reserves due to the uncertainty of the outcome of the referendum and potential impact of Senate Bill No. 1137. The majority of these volumes are in the Los Angeles Basin. See Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities.
Extensions - We added 5 MMBoe from extensions resulting from successful drilling and workovers in the San Joaquin, Los Angeles and Sacramento basins.
Divestitures - We had a reduction of 12 MMBoe which related to our Round Mountain Unit divestiture. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 8 Divestitures and Acquisitions for more information on this transaction.
Proved Undeveloped Reserves
The total changes to our proved undeveloped reserves during the year ended December 31, 2023 were as follows:
San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin Total
(in MMBoe)
Balance at December 31, 2022
38 16 - - 54
Revisions related to price (2) 1 - - (1)
Revisions related to performance 4 - - - 4
Revisions due to California regulatory changes and court challenges (1) (11) - - (12)
Extensions
1 1 - 1 3
Improved recovery 1 - - - 1
Transfers to proved developed reserves - (3) - - (3)
Balance at December 31, 2023
41 4 - 1 46
Revisions related to price - We had 1 MMBoe of net negative price-related revisions. Negative price-related revisions of 3 MMBoe were offset by 2 MMBoe of positive cost recovery barrels under our PSCs.
Revisions related to performance - We had 4 MMBoe of net positive performance-related revision, which included positive revisions of 9 MMBoe, partially offset by negative revisions of 5 MMBoe. Our positive performance-related revisions of 9 MMBoe primarily related to proved undeveloped reserves which were added to our five-year development plan in 2023. The majority of these revisions were located in the San Joaquin basin.
Revisions due to California regulatory changes and court challenges - We removed 12 MMBoe from proved undeveloped reserves due to the uncertainty of the outcome of the referendum and potential impact of Senate Bill No. 1137 as discussed above. The majority of these revisions were located in the Los Angeles basin. See Regulation of the Industries in Which We Operate, Regulations of Exploration and Production Activities.
Extensions - We added 3 MMBoe of proved undeveloped reserves through extensions as a result of successful drilling and workover programs in the San Joaquin, Los Angeles and Sacramento basins.
Transfers to proved developed reserves - We converted 3 MMBoe of proved undeveloped reserves to proved developed reserves in the Los Angeles basin. This resulted in a conversion rate of approximately 6% of our beginning-of-year proved undeveloped reserves, with an investment of approximately $65 million of drilling and completion capital. We plan to increase our active rig count in the second half of 2024 assuming the resumption of permitting of new wells and sidetracks. We believe we will have sufficient capital to develop all year end 2023 proved undeveloped reserves within five years of their original booking date. For more information on the 2024 Capital Program, see Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources 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, 2023
(in millions)
Standardized measure of discounted future net cash flows $ 4,069
Present value of future income taxes discounted at 10% 1,464
PV-10 of cash flows(a)
$ 5,533
(a)The average realized prices for estimating our PV-10 of cash flow as of December 31, 2023 were $80.97 per barrel for oil, $50.00 per barrel for NGLs and $4.57 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, 2023 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. 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, which reviewed and approved our oil and natural gas reserves for 2023. 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, 2023, NSAI audited 88% 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 it had resolved its 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, 2023, 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 has more than 22 years of petroleum engineering experience, with the majority spent evaluating California properties, and is a registered Professional Engineer in the state of Texas. The primary geoscientist for the audit has more than 25 years of experience practicing petroleum geoscience and is a Licensed Professional Geoscientist in the state of Texas.
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.
San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin Total Net Wells
Productive
Exploratory - - - - -
Development 4.0 26.5 - - 30.5
Dry
Exploratory - - - - -
Development - - - - -
Productive
Exploratory - - - - -
Development 114.3 35.0 - - 149.3
Dry
Exploratory - - - - -
Development - - - - -
Productive
Exploratory - - - - -
Development 109.4 6.5 - - 115.9
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, 2023.
San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin Total Net Wells
Gross 1.0 - - - 1.0
Net 1.0 - - - 1.0
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 96% as of December 31, 2023. 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, 2023, excluding wells that have been idle for more than five years:
As of December 31, 2023
Productive Oil
Wells Productive Natural Gas Wells
Gross(a)
Net(b)
Gross(a)
Net(b)
San Joaquin Basin 6,532 6,347 142 139
Los Angeles Basin 1,699 1,610 - -
Ventura Basin 20 20 - -
Sacramento Basin - - 904 843
Total 8,251 7,977 1,046 982
Multiple completion wells included in the total above 52 49 18 15
(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 2024 capital plan does not allocate any capital towards exploration drilling.
Marketing Arrangements
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 are typically based on local third-party postings that are closely tied to Brent prices. 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.
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 on 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 in the market and producing areas. Transportation capacity influences prices because California imports more than 90% of its natural gas from other states and Canada. As a result, we typically obtain higher realizations relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas.
In addition to selling natural gas, we also use natural gas in steam generation for our steamfloods and power generation. As a result, the positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to net higher revenue. Conversely, lower natural gas prices lower these operating costs but have a net negative effect on our financial results.
We currently hold transportation capacity contracts to transport all of our natural gas volumes for multiple years.
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 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 6,100 barrels per day of NGLs through March 2026. Our contract to transport NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually shipped. We have met all our shipping commitments under this contract for the periods presented.
Electricity - A portion of the electrical output of the Elk Hills power plant is used by Elk Hills and other nearby production fields. This provides a reliable source of power. We sell remaining electrical output to the CAISO wholesale power market. We sell capacity in excess of our site needs into the CAISO RA marketplace.
Delivery Commitments
We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. As of December 31, 2023, we had oil delivery commitments averaging 9 MMBbl in 2024 and 1 MMBbl in 2025, NGL delivery commitments of 1 MMBbl through March 2024 and natural gas delivery commitments of 15 Bcf through December 2024. We generally have significantly more production than the amounts committed for delivery and have the ability to secure additional volumes of products as needed. These commitments are typically index-based contracts with prices set at the time of delivery.
Derivatives
We protect our operating cash flow from volatility in the commodities market through our hedging strategy. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. Our prior credit agreement included covenants that required us to maintain a certain level of hedges at all times. Our current Revolving Credit Facility includes covenants that require us to maintain a certain level of hedges unless the ratio of our indebtedness to Consolidated EBITDAX (as defined in the Revolving Credit Facility) is less than or equal to 1.5:1.0. We also entered into a limited number of hedges above and beyond those that were required for certain periods. In prior years, these hedges prevented us from realizing the full benefits of price increases. We continuously evaluate our hedging strategy to take into account changes in prevailing market prices and conditions.
Refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 6 Derivatives for more information on our open derivative contracts as of December 31, 2023 and Note 4 Debt for more information on an amendment to the hedging requirements included in our Revolving Credit Facility.
Our Principal Customers
We sell crude oil, natural gas and NGLs to marketers, California refineries and other purchasers that have access to transportation and storage facilities. Our ability to sell our products can be affected by factors that are beyond our control and cannot be accurately predicted. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 1 Nature of 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 which secure our debt, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 4 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 who operate in California. We also compete with foreign oil and gas companies because California imports approximately 75% of the oil it consumes. 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 similar characteristics to the low-carbon intensity oil produced from our fields. 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. Higher commodity prices could intensify competition for drilling and workover rigs, pipe, other oil field equipment and personnel. However, in the current environment, we anticipate modest price increases for materials and services as contracts are renewed in the future. We believe our relative size and activity level, compared to other in-state producers, favorably influences the pricing we receive from third-party providers in the markets in which we operate.
We also face competition in our oil and natural gas operations from other sources of energy, including wind and solar power. These products compete directly with the electricity we generate from our Elk Hills power plant and indirectly as substitutes for oil, natural gas and NGLs. We expect competition from these sources to intensify in the future due to technological advances and as California continues to develop renewable energy and implements climate-related policies.
In our carbon management business, we compete with other potential storage providers to acquire and develop storage reservoirs and enter into agreements with existing and future emission sources.
Infrastructure
The infrastructure used in our operations, including plants and facilities located in the Wilmington field, is presented below:
Description Quantity Unit Capacity
San Joaquin Basin Other Basins Total
Gas Processing Plants(a)
MMcf/d 335 18 353
Power Plants(b)
3 MW 595 48 643
Steam Generators/Plants(c)
MBbl/d 120 - 120
Compressors 300
MHp 320 21 341
Water Management Systems(c)
MBw/d 1,900 1,980 3,880
Water Softeners(c)
16 MBw/d 125 - 125
Oil and NGL Storage(d)
MBbls 408 195 603
Pipelines(e)
Miles >8,000
(a)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.
(b)Includes our 550-megawatt combined-cycle Elk Hills power plant, located adjacent to the Elk Hills natural gas processing facility and typically generates all the electricity needed by our Elk Hills field and certain other operations. We utilize approximately a third of its capacity for operations and market the remaining capacity into the resource adequacy market. We offer the balance of the available energy to the CAISO grid. Also included is a 45-megawatt cogeneration facility at Elk Hills that provides additional flexibility and reliability to support field operations and a 48-megawatt power generating facility that is part of the Long Beach Unit located in the Los Angeles basin.
(c)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.
(d)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.
(e)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 settings 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.
Carbon Management Business
Our carbon management business, which we refer to as Carbon TerraVault, pursues CCS projects that are directly sited or within close proximity to significant sources of CO2 emissions in California.
EPA Class VI Permits and CCS Projects
We are in the early stages of developing several CCS projects in California. To date, we have submitted Class VI permit applications to the EPA for two permanent sequestration projects at our Elk Hills field. In December 2023, the EPA released draft Class VI permits for one of these projects. This project is held by a joint venture with BGTF Sierra Aggregator LLC (Brookfield) (Carbon TerraVault JV), which is discussed further below. The draft permits for this project are currently subject to public comment, and we expect to receive the final Class VI permits in the middle of 2024. We have also submitted permit applications for four permanent sequestration projects in the Sacramento Basin that are under review by the EPA.
To date, we have executed six carbon dioxide management agreements (CDMAs) with emitters to provide permanent carbon storage. The CDMAs frame the material economics and terms of the project and include conditions precedent to close. These CDMAs contemplate the construction of production facilities for hydrogen, ammonia and other substances, some of which may be co-located with our planned CCS sites. The CDMAs are also subject to negotiation of definitive documents and a final investment decision. We are separately in discussions with other potential emitters and may enter into joint ventures or other commercial arrangements with respect to CCS projects.
Once completed, we expect that our Carbon TerraVault CCS projects will inject CO2 captured from industrial, electrical, agriculture and carbon removal sources into subsurface reservoirs and permanently store CO2 deep underground. As part of our commitment to carbon management, we are also installing and upgrading carbon capture equipment at our cryogenic gas processing facility at Elk Hills field which will remove CO2 from inlet gas, where the CO2 will be stored at a nearby 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. 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 by the U.S. Department of Energy grant for this project.
We expect that the size and scope of our projects providing these and similar services and capital spent on such projects will continue to grow given our strategy of expansion into these services and the development of our carbon management business as a stand-alone business. For more information about the risks involved in our carbon management business, see Part I, Item 1A - Risk Factors.
Carbon TerraVault JV
In August 2022, we entered into a joint venture with Brookfield for the further development of our carbon management business. We hold a 51% interest in the Carbon TerraVault JV and Brookfield holds a 49% interest. Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through the Carbon TerraVault JV. At the formation of the Carbon TerraVault JV, we contributed rights to inject CO2 into the 26R reservoir in our Elk Hills field for permanent CO2 storage (26R reservoir) and Brookfield committed to make an initial investment of $137 million, subject to adjustment based on permitted storage capacity, payable in three installments with the last two installments subject to the achievement of certain milestones. Brookfield contributed the first $46 million installment of their initial investment to the Carbon TerraVault JV during the year ended December 31, 2022. The next two installments are due upon completion of certain pre-agreed milestones, which are anticipated to occur in 2024. This amount may, at our sole discretion, be distributed to us or used to satisfy future capital contributions, among other items. 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.
Several other projects are being considered by the Carbon TerraVault JV for future development. If Brookfield elects to participate in a project, a portion of our upfront costs to evaluate and permit that project will be subsequently recovered through Brookfield's investment in the Carbon TerraVault JV. We may also pursue the development of CCS projects independently of the Carbon TerraVault JV if Brookfield elects not to participate.
The Carbon TerraVault JV has an option to participate in certain projects that involve the capture, transportation and storage of CO2 in California. This option expires upon the earlier of (1) August 2027, (2) when a final investment decision has been approved by the Carbon TerraVault JV for storage projects representing in excess of 5 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). Refer to Part II, Item 8 - Financial Statements and Supplementary Data, Note 3 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on our Carbon TerraVault JV.
Human Capital Management
Our employees are our most valuable asset and we strive to provide a safe and healthy workplace, development opportunities and financial rewards, ensuring focus on fair and equitable treatment. We believe our core values of Character, Responsibility and Commitment and our comprehensive business and ethical conduct policies sustain shareholder value.
Our comprehensive business and ethical conduct policies apply to all directors, officers and employees, each of whom personally commits to following our code of conduct and our corporate policies, as well as to suppliers and vendors working in our operations. Our position is that no business goal is worth our employees compromising their integrity or our shared values.
We had approximately 970 employees as of December 31, 2023 as compared to 1,060 as of December 31, 2022, all in the United States. In 2023, we undertook initiatives to streamline our operations and implemented organizational changes that resulted in a headcount reduction of approximately 75 employees. That decrease was partially offset by growth in our headcount in our carbon management business. Of the total 970 employees, approximately 50 full-time equivalent employees are focused on our carbon management business. Approximately 55 of our employees are covered by a collective bargaining agreement. We also utilize the services of many third-party contractors throughout our operations.
Continued Employee 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. Our mandatory training reinforces our company-wide commitment to operate in accordance with all applicable laws, rules and regulations and to sustain a diverse and empowered workforce comprising of our employees and those of our suppliers, vendors and joint ventures. In addition to training, our employees receive regular performance and career development discussions from their direct managers. All employees receive annual performance reviews.
Our largest development initiatives in the past couple of years included the Future Leaders Development Program with the University of California, Los Angeles (UCLA) Anderson School; our Intrepid Women's Program, a program of coaching and development circles for women; and ELEVATE, a manager workshop on communication styles and culture changing behaviors to develop our future leaders.
We have taken steps to promote the development of a pipeline of candidates as we develop our carbon management business. In 2022, we pledged $2.5 million to fund several Kern County initiatives with Kern Community College District (Kern CCD) and California State University, Bakersfield (CSUB) to help advance the energy transition and further benefit local communities. As of December 31, 2023, we contributed approximately $1.9 million of the $2.5 million pledged. We anticipate contributing the remainder of our commitment in 2024.
We will collaborate with Kern CCD to establish the CRC Carbon Management Institute, a first-of-its-kind initiative that will empower local private and public partnerships to lead the way in defining how collaboration between education and industry can positively impact communities. Funding will also be used for research and development, community outreach and education, workforce training and education, and carbon management academics that will focus on advancing CCS and emerging technologies. Additionally, CSUB will launch the CRC Energy Transition Lecture Series on relevant topics and emerging issues related to CCS and technologies that will lead the way to achieving a net zero future. Finally, the CRC Carbon TerraVault Scholarship will be established to help provide students with academic opportunities.
Diversity, Equity and Inclusion
Our goal is to foster an open and diverse culture and we are committed to advancing people of all backgrounds and perspectives, including women and persons from historically underrepresented communities in our workplace. We believe supporting diversity, equity and inclusion (DE&I) efforts encourages higher levels of workforce engagement by helping to enable team members to bring diverse experiences and perspectives to their day-to-day jobs. We believe this, in turn, leads to more thoughtful and innovative business decisions and higher levels of engagement and lower levels of turnover. We established an Advisory Council focused on career development, promotion, recruitment and retention to help support our DE&I commitments. We have all employees attend DE&I training to reinforce an open and diverse culture.
The table below approximates our self-reported gender diverse and ethnically and racially diverse employees and members of our Board of Directors as of December 31, 2023.
Gender Diverse Ethnically and Racially Diverse
All Employees 19% 39%
Managers 23% 27%
Executives 28% 28%
Board of Directors 33% 44%
Employee 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 a threshold TRIR as a quantitative metric that directly impacts incentive compensation for all of our employees. We achieved a 99.9999% oil spill prevention rate in 2023 and registered a workforce TRIR of 0.31. We have achieved exemplary, steadily improved 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 throughout the 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 host regular townhalls so employees can engage with them through question and answer sessions.
We provide our employees industry competitive base wages and annual and long-term incentive compensation opportunities, as well as matching and profit-sharing retirement contributions to employees' 401(k) accounts; comprehensive health benefits; life, disability and accident insurance coverages; sick pay, paid holidays, paid parental leave and vacation; employee assistance for confidential counseling services, a wellness program to promote the well-being of our employees and their families; and various group discount programs. Our employee stock purchase program allows our employees to purchase shares of our common stock at a discounted price. We also provide options for alternate work schedules, flexible work hours, part-time work options and telecommuting.
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
In 2023, we 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 led to such delays, including recent changes in CalGEM management. Since December 2022, CalGEM has issued a limited number of permits for new production wells in California, and those permits were issued to other operators. In addition, CalGEM effectively ceased issuing permits for sidetracks, deepenings and reworks at various points in 2023 pending the development of standard operating procedures (SOPs). CalGEM recently finalized its SOP for the review of permit applications for reworks in December 2023 and a noticeable increase in rework approvals has followed. CalGEM also recently finalized its Lead Agency Preliminary Review process. Since the implementation of that process, the pace of approvals has been slow, with only a limited number of sidetrack permits issued to other operators.
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. Any continuing failure to obtain certain permits or the adoption of more stringent permitting requirements could have a material adverse effect on our business, operations, properties, 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.
CalGEM currently requires an operator to identify the manner in which the California Environmental Quality Act (CEQA) has been satisfied prior to issuing various state permits, typically through either an environmental review or an exemption by a state or local agency. In Kern County, this requirement has typically been satisfied by complying with the local oil and natural gas ordinance which was supported by an Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015.
Kern County EIR Litigation
Our operations in Kern County have been subject to significant uncertainty over the past several years as a result of ongoing challenges to the County's ability to rely on an existing EIR to meet the County's obligations under CEQA. In December 2015, several groups challenged the sufficiency of the EIR for satisfying CEQA requirements in Kern County for oil and natural gas permit approvals. Litigation proceedings remain ongoing; currently, the use of the EIR is stayed and has been throughout most of the litigation. Although the County has issued a supplemental EIR to address the plaintiffs’ concerns, operators still cannot rely on this supplemental EIR at this time as a result of the ongoing litigation. A ruling as to whether oil and natural gas permitting shall remain suspended for the duration of the appeals process is expected sometime in the first half of 2024.
We have pursued and continue to pursue alternative pathways for addressing CEQA compliance for oil and natural gas permits in Kern County and have submitted applications for conditional use permits from Kern County for projects located at our Elk Hills, Kern Front and Buena Vista fields. However, subject to one narrow exception, CalGEM has not approved any permits for new drill wells in Kern County since December 2022, through alternative pathways or otherwise. We expect that our pursuit of the conditional use permits in Kern County will be a lengthy process. The timing of this process is difficult to estimate and could extend well into 2025.
As a result of these issues and current lack of permits with respect to our Kern County properties, we plan to operate one active rig within Kern County in the first half of 2024 and have the requisite number of permits in hand to keep that rig active throughout 2024. We plan to increase our active rig count in Kern County to three rigs in the second half of 2024 assuming the resumption of permitting of new wells and sidetracks or through alternative pathways. 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. Approximately $75 million of our aggregate capital for oil and natural gas development in 2024 relates to drilling and completing wells 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 2024 Capital Program, see Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources.
Wilmington Oil Field
In addition, commencing in February 2023, CalGEM began returning our applications for permits in the Wilmington Oil Field, including permits for new production wells, workovers and plugging and abandonment operations. CalGEM cited concerns regarding the adequacy of the related environmental impact report for purposes of meeting CEQA requirements. We are working together with the City of Long Beach to address CalGEM’s concerns regarding conducting future re-drills, workover and plugging and abandonment activities.
Approximately $25 million of our aggregate capital for oil and natural gas development in 2024 relates to drilling and completing wells in Wilmington 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.
We plan to operate one active rig on the THUMS Islands in the second half of 2024 assuming the resumption of permitting of sidetracks and deepenings. 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.
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. For example, 2019 state legislation expanded CalGEM’s duties effective on January 1, 2020 to include public health and safety and reducing or mitigating greenhouse gas emissions while meeting the state’s energy needs, and will require CalGEM 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. CalGEM issued updated regulations in April 2019 governing management of idle wells and underground fluid injection, which include specific implementation periods. The updated idle well management regulations require operators to either submit annual idle well management plans describing how they will plug and abandon or reactivate a specified percentage of long-term idle wells or pay additional annual fees and perform additional testing to retain greater flexibility to return long-term idle wells to service in the future. The updated underground injection regulations address injection approvals, project data requirements, testing of injection wells, monitoring and reporting requirements with respect to injection parameters, containment and incident response, among other topics.
In addition, certain local governments have proposed or adopted ordinances that would restrict certain drilling activities in general and well stimulation, completion or injection activities in particular, impose setback distances from certain other land uses, or ban such activities outright. For example, both the City and the County of Los Angeles have voted to prohibit new oil and natural gas wells and phase out existing wells over a number of years. Our operations in unincorporated areas of Los Angeles are not affected by these bans, and we do not anticipate a material impact from these bans to our future drilling operations as we have no drilling plans or proved undeveloped reserves within the area that would be covered by these bans. However, from time to time, other local governments in California have sought to enact similar bans and others may seek to do so in the future. Other local governments have sought to ban natural gas or the transportation of natural gas through their cities. 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. A response is tentatively expected by year-end 2024.
Setbacks
On September 16, 2022, the Governor of California signed Senate Bill No. 1137 into law, 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 imposing a number of potential impact analysis and mitigation and reporting requirements effective January 1, 2023. On January 6, 2023, CalGEM's emergency regulations to support implementation of Senate Bill No. 1137 were approved by the Office of Administrative Law and final regulations were published. Proponents of a voter referendum to repeal Senate Bill No. 1137 (the Referendum) have collected more than the requisite number of signatures required and the Secretary of State of California certified the signatures and confirmed that the Referendum qualifies for the November 2024 ballot. Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote. CalGEM could attempt to initiate rulemaking with regard to setbacks during the stay, although this has not occurred thus far.
The majority of our production is in rural areas in the San Joaquin basin and is unlikely to be affected by Senate Bill No. 1137 should the outcome of the Referendum result in the bill being implemented. We would not expect the implementation of this law to result in any change in our existing proved developed producing reserves or current production rates or any material change to the timing of plugging and abandonment liabilities. However, there is significant uncertainty with respect to our ability to book proved undeveloped reserves within the setback zones established by Senate Bill No. 1137. As a result, we have not booked any proved undeveloped reserves located within setback zones, except for those reserves for which we have drilling permits or intend to have drilling permits for, prior to the November 2024 ballot. Due to Senate Bill No. 1137, in 2023 we reduced the net present value of our proved undeveloped reserves by 19% and our overall proved reserves by 2%.
Separately, in early 2023, Senate Bill No. 556 was introduced into the California Senate providing for presumptive liability for certain adverse health conditions in a setback zone, subject to limited defenses. The bill did not advance through the legislature in 2023. However, similar proposed legislation was introduced as Assembly Bill 3155 in February 2024. If AB 3155, or similar bills, are ultimately enacted, such legislation would further impact our ability to operate in a setback zone and increase our exposure to liability.
Pipeline Transportation
Federal and state pipeline regulations have also been recently revised. CalGEM imposed more stringent inspection and integrity management requirements in 2019 and 2020 with respect to certain natural gas pipelines in specified locations, with additional regulations anticipated in 2022 regarding digital mapping of such lines. The Office of the State Fire Marshal adopted regulations in 2020 to require risk assessment of various oil lines in the coastal zone, followed by retrofitting of certain of those lines with the best available control technology to mitigate oil spills over a specified implementation period. Finally, the federal PHMSA has, from time to time, issued new regulations expanding or otherwise revising pipeline integrity requirements. For example, in November 2021, PHMSA issued a final rule imposing safety regulations on an aggregate of approximately 400,000 miles of previously unregulated onshore gas gathering lines across the United States that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. And, in August 2022, PHMSA finalized additional pipeline safety rules, which adjusted the repair criteria for pipelines in high consequence areas, created new criteria for pipelines in non-high consequence areas, and strengthened integrity management assessment requirements, among other items. Additionally, in May 2023, PHMSA published a proposed rule that would enhance requirements for detecting and repairing leaks on new and existing natural gas distribution, gas transmission and gas gathering pipelines and, separately, in September 2023, 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.
Water Injection
Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by 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 and have supplied technical information to CalGEM in support of our position. If CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient other than in a gradual manner, and we were unable to reverse that decision on appeal or other legal challenge, we expect any material reduction in injection well pressure gradient for our operations in the Wilmington Oil Field would result in a decrease in production and reserves from the field.
Collectively, the effect of these regulations is to potentially limit the number and location of our wells and the amount of oil and natural gas that we can produce from our wells compared to what we otherwise would be able to do.
Bonding
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 the state of 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 the state of California.
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 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 SDWA. In 2015, the state set deadlines to obtain the EPA’s confirmation of aquifer exemptions under the SDWA 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 and EPA’s delays in approval of the exemption proposals that remain outstanding. Of the 30 original aquifer exemption proposals addressing permitted injection into a potential underground source of drinking water, 21 have been approved by EPA, with nine 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. In a January 2024 status hearing, the court also preserved the stay and preliminary injunction for an additional six months at which time it will reevaluate case management due to the age of the lawsuit.
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 July 2023-“Phase 2”-the CEQ published a proposed 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 is expected in the second quarter of 2024.
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 fresh water 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. A unified permit application is to be adopted by January 1, 2025. We believe permitting for our Carbon TerraVault projects, for which the EPA has issued draft permits that are open to public notice and comment until March 20, 2024, 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. 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. Those projects that will rely only on pipelines for transporting CO2 will need to comply with yet to be developed CO2 pipeline safety regulations from the federal PHMSA, which could take a number of years to effect. Further, the terms of the final pipeline safety regulations may impair or prohibit those projects that rely on the transportation of CO2. In addition, delays in developing the required pipeline safety regulations would delay projects requiring pipeline transportation of CO2. The lack of compulsory unitization could also delay project timelines.
The unified permitting process contemplated by Senate Bill No. 905 will be optional for project applicants and is intended to simplify the permitting process for CCS projects. In the meantime, pursuant to this legislation, we are permitted to proceed with our existing and future permit applications with the EPA. This law also 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 Department of Conservation has been tasked with developing this proposed framework, an initial draft of which was expected in December 2023 and remains pending.
Senate Bill No. 905 also prohibits CCS projects that utilize and permanently sequester CO2 in connection with Enhanced Oil Recovery (EOR) projects. In light of this prohibition and the enhancement of energy credits under the Inflation Reduction Act of 2022, we transitioned our CalCapture project to target CCS. We currently do not have any oil and natural gas production or proved reserves associated with EOR projects that rely on CO2 floods. As a result, we do not expect the limitations on EOR activities included in Senate Bill No. 905 to impact our existing oil and natural gas production or proved reserves.
CCS Project Permitting
The development, construction and operation of our CCS projects is contingent upon securing certain permits from federal, state and local authorities, including “Class VI” injection well permits from EPA and conditional use permits from the county in which a project is sited. Draft permits and corresponding draft EIRs are subject to public review and comment. The process for permitting CCS projects continues to evolve. In December 2023, EPA released draft Class VI permits for our “CTV I - 26R” CCS project located at our Elk Hills field in Kern County. These draft permits are the first draft permits released by EPA in California. In December 2023, Kern County also released the draft EIR prepared in connection with the conditional use permit application for CTV I - 26R. The draft Class VI permits and draft EIR are subject to public review and comment. We anticipate that EPA and Kern County will deliver their final decisions on the permits in the second half of 2024.
Federal Tax Credits
The Inflation Reduction Act also 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 tax credits provided under the Inflation Reduction Act is still developing and is subject to further guidance from the IRS, 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 December 26, 2023, the IRS released proposed regulations to amend the Income Tax Regulations under section 45V. The proposed regulations would 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 of the regulations that will be adopted by the IRS upon the conclusion of its rulemaking process. The proposed regulations indicate that the Treasury Department and IRS are considering imposing certain requirements, restrictions and potential 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 tax credits provided under the Inflation Reduction Act is still developing and is subject to further guidance from the IRS, and therefore uncertainties and complexities with respect to our (or our partners) ability to efficiently monetize the 45V credit still exist.
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. President Biden has issued several executive orders on climate change, which have ultimately resulted in the United States rejoining the Paris Agreement, EPA issuing final methane emissions standards for new, modified and existing oil and natural gas and an increased emphasis on climate-related risk across governmental agencies and economic sectors. Additionally, the EPA has adopted federal regulations to:
•require 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;
•incorporate measures to reduce GHG emissions in permits for certain facilities; and
•restrict GHG emissions from certain mobile sources.
California has adopted stringent laws and regulations to reduce GHG emissions. These 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.
On December 19, 2023, CARB released its proposed amendments to the LCFS Regulation, which focus on “key concepts” including increasing the stringency of the program “to more aggressively decarbonize fuels”, incentivizing production of clean fuels, such as “low-carbon hydrogen”, and supporting methane emissions reductions. The proposed amendments would increase both the pre- and post-2030 stringency of the LCFS carbon intensity (CI) benchmarks, including a 30% reduction in fuel CI by 2030 and a 90% reduction in fuel CI by 2045 from the 2010 baseline, near-term step-down of a 5% reduction in the CI benchmark in 2025 that increases the stringency of the CI target, and an automatic acceleration mechanism which advances all annual carbon intensity benchmarks by one year when specific regulatory conditions are met.
In connection with the foregoing, CARB has proposed the adoption of a new Oil Production Greenhouse Gas Emission Estimator (OPGEE), which models an increase in the CI of crudes. CARB has also proposed a phase-out of project-based crediting and limiting the duration of the crediting period for innovative petroleum projects. Any changes to the LCFS or other California initiatives related to climate change, including the foregoing proposals, could result in increased compliance costs if we are forced to purchase additional credits or otherwise adversely impact demands for the hydrocarbons we produce.
The proposed amendments also exclude “blue” hydrogen from the definition of “Renewable Hydrogen”. Blue hydrogen is produced 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 “blue” hydrogen if the produced carbon dioxide is captured and permanently sequestered. If adopted, the exclusion of blue hydrogen as a “Renewable Hydrogen” may directly or indirectly impact our ability to develop, construct and operate blue hydrogen production projects if such projects were to become economically unviable as a result.
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 and adverse effect on our business, results of operations and financial condition.
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 requirement 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. It is likely, however, that the final rule and requirements will be subject to legal challenges. CARB has implemented similar regulations.
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.
California Climate Disclosures
In October 2023, the Governor of California signed two bills that will require climate-related disclosures, both of which apply to us. Senate Bill 253 (SB-253) requires both public and private U.S. companies that are “doing business in California” and that have a total annual revenue of $1 billion to publicly disclose, on an annual basis, Scope 1, Scope 2 and Scope 3 GHG emissions, with certain GHG emissions data subject to third-party assurance. The bill requires disclosure beginning in 2026 (for the 2025 reporting year). Senate Bill 261 (SB-261) requires public and private U.S. companies “doing business in California” with a total annual revenue of $500 million to publish biennial disclosures on the company's website related to climate-related financial risks and the measures a company has adopted to reduce and adapt to such risks, with the report in line with the Task Force on the Climate-related Financial Disclosure recommendations or equivalent disclosure requirements under the International Sustainability Standards Board’s climate-related disclosure standards. Additionally, in October 2023, the Governor of California also signed Assembly Bill 1305 (AB 1305) which creates new reporting obligations related to voluntary carbon offsets. AB 1305 requires business entities that (1) market or sell voluntary carbon offsets in California, (2) purchase or use voluntary carbon offsets sold in California that make emissions-related claims, or (3) make claims that an entity or product has eliminated or made significant reductions to its carbon dioxide or GHG emissions to make certain public disclosures on the business entity’s website. Under the final prong, such claims covered by AB 1305 include “significant reductions” to carbon dioxide or GHG emissions and the achievement of net zero.
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 materially and adversely affect 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.
•Drilling for and producing oil and natural gas carry significant operational risks and uncertainty. We may not drill wells at the times we scheduled, 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 have been 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 Yemen and the Red Sea have caused related price volatility and geopolitical instability could negatively impact our business.
•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.
•Many 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.
Risks Related to Carbon TerraVault and Our Carbon Management Business
•Our ability to achieve our 2045 Full-Scope Net Zero target and other goals related to carbon management activities, is subject to risks and uncertainties.
•We may not be able to grow our Carbon TerraVault business and develop large scale CCS projects.
•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 oil and gas industry presents risks to our business.
•Increasing attention to ESG matters may adversely impact our business.
•We may not decide to separate our carbon management business from our E&P business, or be successful in the event we choose to pursue such separation.
•Acquisition and disposition activities, including the Aera Merger, involve substantial risks.
•While the Aera Merger is pending, we will be subject to certain contractual restrictions that could adversely affect our business and operations.
•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.
•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 requirements 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.
•Concerns about climate change and other air quality issues may prompt governmental action that could materially affect 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 conditions, results of operations and cash flows.
•Recent action by the State of California imposing additional 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 the state of 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 to capital.
•Restrictive covenants in our Revolving Credit Facility and the indenture 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.
•There is an increased potential for short sales of our common stock due to the sales of shares issued upon exercise of warrants, which could materially affect the market price of the 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.
•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 materially and adversely affect 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 Yemen and the Red Sea;
•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, results of operations and cash flow, 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.
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. These 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 carry significant operational risks and uncertainty. We may not drill wells at the times we scheduled, 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 locations for drilling over 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 results in these projects do not establish sufficient production and reserves to achieve an economic return, we may curtail drilling or development of these projects. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate. We cannot guarantee that our identified drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these drilling locations. 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 4% of our total net undeveloped acreage at December 31, 2023.
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 2024 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 have been negatively impacted by inflation.
Increases in inflation may have an adverse effect on us. Current and future inflationary effects may be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal policies, and geopolitical instability. We have taken measures to limit the effects of the inflationary market by entering into contracts for materials and services with terms of one to three years. Additionally, we continually look at productivity and performance improvements from our vendors in order to mitigate these price increases and also to reduce volumes consumed. However, there can be no assurances that such measures will be effective. 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 their 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 Yemen and the Red Sea have caused price volatility and geopolitical instability could negatively impact our business.
The military conflicts in Ukraine, Israel and Yemen and the Red Sea 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.
During the fourth quarter of 2023, OPEC+ announced a continuation of its combined 4 million barrels per day voluntary reduction in production quotas. 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 and natural gas production.
Materialization of either of the events described above may also magnify the impact of the other risks described in this “Risk Factors” section.
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.
Many 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 and large, which may limit available acquisition opportunities. Many 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. In addition, we have previously entered into incremental hedges above these requirements for certain time periods. 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 add reserves, other than through acquisitions, depends on the success of improved recovery, extension and discovery projects, each of which depends 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 88% of our estimated proved reserve volumes as of December 31, 2023, 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.
Risks Related to Carbon TerraVault and Our Carbon Management Business
Our ability to achieve our 2045 Full-Scope Net Zero target 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, including our 2045 Full-Scope Net Zero target and our energy transition strategy. 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. In particular, our 2045 Full-Scope Net Zero goal includes Scope 1, 2 and 3 emissions and estimation and management of Scope 3 emissions is 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 2045 Full-Scope Net Zero 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). 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 2045 Full-Scope Net Zero goal or at all. If we are not able to successfully develop Carbon TerraVault and its CCS projects and claim related emissions reductions, or we are successful in separating our carbon management business, our ability to achieve our 2045 Full-Scope Net Zero 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.
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:
•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 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 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 is 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 to CCS projects from environmental groups, local residents and legislators.
•We may need to transport CO2 in pipelines if a CCS project relies on storage space that is not co-located with the production facilities. Our ability to transport CO2 is subject to regulatory uncertainty, see Risks Related to Regulation and Government Action - New and developing regulations related to the CO2 unitization, permitting and pipeline safety could negatively impact our business, financial condition and results of operations described below.
•Other regulatory uncertainties described below.
There can be no assurances that we will successfully develop our CCS projects, including CalCapture, and such failure could have an adverse effect on our business. Our carbon management business 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 their 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 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 proposed regulations pertaining to the 45V credit which, among other things, indicated that the Treasury Department and IRS are considering imposing certain requirements, restrictions and potential limitations on the use of renewable natural gas in connection with the production of clean hydrogen that qualifies for the 45V credit, which, if implemented, could have a negative impact on 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 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 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 and is subject to further guidance from the IRS, 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 2045 Full-Scope Net Zero goal.
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 liquidity, 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 business 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 2045 Full-Scope Net Zero target 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, of which $46 million has been funded to date. At the time the Carbon TerraVault JV was formed, Brookfield committed to make an initial investment of $137 million payable in three installments. The first $46 million installment was contributed to the joint venture in August 2022, and the next two installments are due upon completion of certain pre-agreed milestones related to the permitting process with the EPA and final investment decision which are anticipated (but not certain) to occur in 2024. 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 oil and gas industry 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. This opposition also extends to our carbon management business as certain activists oppose carbon capture and sequestration efforts by the oil and gas industry. These activists use a variety of tactics that primarily rely on allegations regarding safety, environmental compliance and business practices. At both the state and federal level, these tactics including seeking changes to laws, pressuring governmental agencies to promulgate regulations or engage in rulemaking, or pursuing litigation. Due to heightened concerns around global warming 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. We may need to incur significant costs associated with responding to these initiatives and such actions may materially adversely affect 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, cash flows and results of operations.
Increasing attention to ESG matters may adversely impact our business.
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. 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.
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 that may or may not be representative of actual risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets, such targets are aspirational. 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. 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 implement such goals because of potential costs or technical or operational obstacles.
Public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further ESG-related focus and scrutiny.
Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
We may not decide to separate our carbon management business from our E&P business, or be successful in the event we choose to pursue separation.
We are considering the potential separation of our E&P and carbon management businesses at some point in the future. We are also pursuing financing options for our carbon management business that are separate from the rest of our business. Our carbon management business faces operational, technological and regulatory risks that could be considerable due to early stage nature of these projects and the sector generally, which may make it more difficult to independently finance and there are no assurances that it will be a viable standalone business in the near term or at all. Further, there can be no assurances that we will be able to successfully separate our E&P and carbon management businesses. We also may decide not to pursue such separation if we do not believe it would maximize shareholder value.
Acquisition and disposition activities, including the Aera Merger, involve substantial risks.
On February 7, 2024, we entered into the Merger Agreement with Aera. In addition, from time to time, we engage in acquisition activities. The Aera Merger and other such 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.
The Aera Merger is expected to close in the second half of 2024 and is subject to certain closing conditions, including the approval of the stock issuance by our stockholders and the receipt of certain required government approvals, and other customary closing conditions. Our other acquisition activities may similarly require us to seek approvals from government agencies and 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 the Aera Merger, as well as any future acquisition and disposition activities. For example, time and resources will be expended in connection with seeking regulatory approvals for the Aera Merger.
While the Aera Merger is pending, we will be subject to certain contractual restrictions that could adversely affect our business and operations.
Due to certain restrictions in the Merger Agreement on the conduct of business prior to completing the Aera Merger, we may be unable, during the pendency of the Aera Merger, to pursue strategic transactions, undertake certain significant financing transactions and otherwise pursue other actions, even if such actions would prove beneficial, and we may have to forgo certain opportunities we might otherwise pursue.
In addition, the Merger Agreement prohibits us from initiating, soliciting or knowingly encouraging any competing acquisition proposals, subject to certain limited exceptions. The Merger Agreement also contains certain termination rights for us and Aera. Upon termination of the Merger Agreement in accordance with its terms, under certain circumstances, we will be required to pay Aera a termination fee of $50 million, or $100 million in certain circumstances, including if the Merger Agreement is terminated by Aera due to our Board changing its recommendation in favor of the Aera Merger to support a competing acquisition proposal.
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 obtaining 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, including financial losses, loss of business, litigation risks and damage to reputation. 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 2023 we 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. CalGEM has recently resumed issuing permits for reworks to CRC and other operators. It has issued some permits for sidetracks to 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. Following a favorable trial court order in 2022, plaintiffs appealed, and, the appellate court issued a preliminary order reinstating a suspension of Kern County’s ability to rely on the existing EIR pending the outcome of a final order determining whether oil and natural gas permitting shall remain suspended for the duration of the appeals process. We expect the Appellate Court to issue its ruling on the matters at issue in the second quarter of 2024. 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 the first half of 2024, and have the requisite number of permits in hand to keep that rig active throughout the year. We plan to increase our active rig count in Kern County from one rig to three in the second half of 2024, assuming new well and sidetrack permitting resumes in Kern County. 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. Approximately $75 million of our aggregate capital for oil and natural gas development in 2024 relates to drilling and completing wells 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. As a result, any implementation of Senate Bill No. 1137 is stayed until it is put to a vote. There is significant uncertainty with respect to the ability to book proved undeveloped reserves and drill within the setback zone established by Senate Bill No. 1137 and, as a result, we have only booked proved undeveloped reserves for which we already have permits within the zone or intend to have permits for prior to the November 2024 ballot. As a result of Senate Bill No. 1137, in 2023 we reduced the net present value of our proved undeveloped reserves by 19% and our overall proved reserves by 2%. (See Part I, Item 1 and 2 - Business and Properties, Regulation of Exploration and Production Activities for more information).
In addition, commencing in February 2023, CalGEM began returning our applications for permits in the Wilmington Oil Field, including permits for new production wells, workovers and plugging and abandonment operations. CalGEM cited concerns regarding the adequacy of the related environmental impact report for purposes of meeting CEQA requirements. We are working together with the City of Long Beach to address CalGEM’s concerns regarding conducting future re-drills, workover and plugging and abandonment activities.
Approximately $25 million of our aggregate capital for oil and natural gas development in 2024 relates to drilling and completing wells in Wilmington for which we do not presently have a permit. We plan to operate one active rig on the THUMS Islands in the second half of 2024, assuming permitting of sidetracks and deepenings resumes. 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.
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, that 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, operations, properties, results of operations, and our financial condition.
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.
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 materially and adversely affect 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 materially and adversely affect 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, and we were unable to reverse that decision on appeal or other legal challenge, we expect any material reduction in injection well pressure gradient for our operations in the Wilmington Oil Field would 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 ability to timely obtain and maintain permits for our operations in 2023, including from CalGEM, has been subject to significant delays and uncertainties and is subject to factors that are not within our control. These factors include changes in agency practices, new regulations, or legal challenges to existing approvals for our operations from individual citizens and non-governmental organizations. For example, beginning in 2021, CalGEM ceased issuing new well stimulation permits. In 2023, CalGEM virtually ceased issuing permits for new wells, sidetracks, deepenings, and reworks throughout the state (though it recently resumed issuing permits for reworks, and has slowly been resuming the issuance of permits for sidetracks), even as it continues approving permits for plugging and abandonment. CalGEM communicated that permitting would resume (with the exception of permits for new wells in Kern County, the issuance of which has been stayed pending the final ruling of the Appellate Court) upon its development of standard operating procedures for reviewing permit applications and cited staffing shortages within its CEQA unit as an additional reason for the delays. See Part I, Item 1 and 2 - Business and Properties, Regulation of the Industries in which we Operate, Regulations of Exploration and Production Activities.
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. Changes to elected or appointed officials or their priorities and policies could result in different approaches to the regulation of the oil and natural gas industry. 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, that 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, operations, properties, results of operations, and our financial condition.
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 requirements 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.
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 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. 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. A unified permit application is to be adopted by January 1, 2025. We believe our Carbon TerraVault projects, for which the EPA has issued draft permits that are open to public notice and comment until March 20, 2024, 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 that will need to comply with yet to be developed CO2 pipeline safety regulations from the federal Pipeline and Hazardous Materials Safety Administration, which could take a number of years to effect. Delays in developing required pipeline safety regulations would delay projects requiring pipeline transportation of CO2. The lack of compulsory unitization could also delay project timelines.
The unified permitting process contemplated by Senate Bill No. 905 will be optional for project applicants and is intended to simplify the permitting process for CCS projects. In the meantime, pursuant to this legislation we are permitted to proceed with our existing and future CCS Class VI permit applications with the EPA. This law also 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.
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.
Concerns about climate change and other air quality issues may prompt governmental action that could materially affect 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 materially affect 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 is expected to be applicable to the reported annual methane emissions of certain oil and natural gas facilities, above specified methane intensity thresholds, starting in 2024. 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 operations.
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. Additionally, in March 2022, the Securities and Exchange Commission (SEC) released a proposed rule that would establish a framework for the reporting of climate risks, targets and metrics. We cannot predict the final form and substance of the rule and its requirements. 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, California Climate Disclosures 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 would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and 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, increase our compliance and operating costs and consequently materially and adversely affect our business and results of operations.
Tax law changes could have an adverse effect on our financial condition, results of operations and cash flows.
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 financial condition, results of operations and cash flows. 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 financial condition, results of operations and cash flows.
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.
Recent action by the State of California imposing additional 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 the state of California or increase our costs in connection with the same.
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 the state of 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 will be in an amount determined by the state to sufficiently cover plugging and abandonment costs, decommissioning, and site restoration, and AB 1167 prohibits the closing of any acquisition of 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. We are still assessing the impact of AB 1167. In addition, although AB 1167 has been signed into law, Governor Newsom has 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 acquisitions or dispositions, which could impact our ability to grow or explore new strategic areas - or exit others - within the state of 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.
In light of our strategic goals and the restrictions under our existing debt, we are evaluating options to replace our Senior Notes. 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, 2023, we had $545 million of total long-term debt, and additional borrowing capacity of $477 million under the Revolving Credit Facility (after taking into account $153 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 $1.2 billion and the availability under our Revolving Credit Facility is limited by the aggregate elected commitment amount of our lenders, which as of February 1, 2024 was set at $630 million.
A reduction in our borrowing base below the aggregate commitment amount of our lenders would materially and adversely affect our liquidity and may hinder our ability to execute on our business strategy.
Restrictive covenants in our Revolving Credit Facility and the indenture governing our Senior Notes may limit our financial and operating flexibility.
Both our Revolving Credit Facility and the indenture governing our Senior Notes contain certain restrictions, which may have adverse effects on our business, financial condition, cash flows 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, 2023, 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 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 $1.24 per share, payable to shareholders in quarterly increments of $0.31 per share of common stock, subject to board authorization and declaration each quarter. We recently increased the size of our share repurchase program by $250 million to $1.35 billion and extended the program through December 31, 2025. As of February 6, 2024 we had approximately $747 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.
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. As of December 31, 2023, we had 68,693,885 outstanding shares of common stock and 4,182,521 shares of common stock issuable upon exercise of outstanding warrants. Upon the completion of the Aera Merger, we expect to issue 21,170,357 shares of common stock. 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.
There is an increased potential for short sales of our common stock due to the sales of shares issued upon exercise of warrants, which could materially affect the market price of the stock.
Downward pressure on the market price of our common stock that likely will result from sales of our common stock issued in connection with the exercise of warrants could encourage short sales of our common stock by market participants. Generally, short selling means selling a security, contract or commodity not owned by the seller. The seller is committed to eventually purchase the financial instrument previously sold. Short sales are used to capitalize on an expected decline in the security’s price. Such sales of our common stock could have a tendency to depress the price of the stock, which could increase the potential for short sales.
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, 2023, four of our shareholders owned at least 5% each and collectively owned approximately 40% 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.
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