UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2022
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 001-36478
California Resources Corporation
(Exact name of registrant as specified in its charter)
|(State or other jurisdiction of |
incorporation or organization)
|(I.R.S. Employer |
1 World Trade Center, Suite 1500
Long Beach, California 90831
(Address of principal executive offices) (Zip Code)
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
|Title of Each Class||Trading Symbol(s)||Name of Each Exchange on Which Registered|
|Common Stock||CRC||New York Stock Exchange|
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Date File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period as the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
|Large Accelerated Filer||☑||Accelerated Filer||☐||Non-Accelerated Filer||☐|
|Smaller Reporting Company||☐||Emerging Growth Company||☐|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of June 30, 2022: $2,901,083,185.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☑ No ☐
At January 31, 2023, there were 71,491,602 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement to be filed within 120 days after December 31, 2022 with the Securities and Exchange Commission in connection with the registrant's 2023 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS
|Part I|| |
|Items 1 & 2|
BUSINESS AND PROPERTIES
Business Overview and History
Oil and Natural Gas Operations
Production, Price and Cost History
Estimated Proved Reserves and Future Net Cash Flows
|Carbon Management Business|
Human Capital Management
|Regulation of the Industries in Which We Operate|
UNRESOLVED STAFF COMMENTS
MINE SAFETY DISCLOSURES
|Part II|| || |
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Basis of Presentation
Supply Chain Constraints and Inflation
Production, Prices and Realizations
Acquisitions and Joint Ventures
Share Repurchase Program
Statement of Operations Analysis
Liquidity and Capital Resources
Uses of Cash
Lawsuits, Claims, Commitments and Contingencies
Critical Accounting Estimates
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Changes in Stockholders' Equity (Deficit)
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Oil and Gas Information (Unaudited)
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
|Part III|| || |
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
PRINCIPAL ACCOUNTANT FEES AND SERVICES
|Part IV|| |
GLOSSARY AND SELECTED ABBREVIATIONS
The following are abbreviations and definitions of certain terms used within this Form 10-K:
•ABR - Alternate base rate.
•ASC - Accounting Standards Codification.
•ARO - Asset retirement obligation.
•Bbl - Barrel.
•Bbl/d - Barrels per day.
•Bcf - Billion cubic feet.
•Bcfe - Billion cubic feet of natural gas equivalent using the ratio of one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.
•Boe - We convert natural gas volumes to crude oil equivalents using a ratio of six thousand cubic feet (Mcf) to one barrel of crude oil equivalent based on energy content. This is a widely used conversion method in the oil and natural gas industry.
•Boe/d - Barrel of oil equivalent per day.
•Btu - British thermal unit.
•CalGEM - California Geologic Energy Management Division.
•CCS - Carbon capture and storage.
•CDMA - Carbon Dioxide Management Agreement.
•CO2 - Carbon dioxide.
•DD&A - Depletion, depreciation, and amortization.
•EOR - Enhanced oil recovery.
•EPA - United States Environmental Protection Agency.
•ESG - Environmental, social and governance.
•E&P - Exploration and production.
•Full-Scope Net Zero - Achieving permanent storage of captured or removed carbon emissions in a volume equal to all of our scope 1, 2 and 3 emissions by 2045.
•GAAP - United States Generally Accepted Accounting Principles.
•G&A - General and administrative expenses.
•GHG - Greenhouse gases.
•JV - Joint venture.
•LCFS - Low Carbon Fuel Standard.
•LIBOR - London Interbank Offered Rate.
•MBbl - One thousand barrels of crude oil, condensate or NGLs.
•MBbl/d - One thousand barrels per day.
•MBoe/d - One thousand barrels of oil equivalent per day.
•MBw/d - One thousand barrels of water per day
•Mcf - One thousand cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six thousand cubic feet of natural gas.
•MHp - One thousand horsepower.
•MMBbl - One million barrels of crude oil, condensate or NGLs.
•MMBoe - One million barrels of oil equivalent.
•MMBtu - One million British thermal units.
•MMcf/d - One million cubic feet of natural gas per day.
•MMT - Million metric tons.
•MMTPA - Million metric tons per annum.
•MW - Megawatts of power.
•NGLs - Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products such as ethane, propane, isobutane and normal butane, and natural gasoline.
•NYMEX - The New York Mercantile Exchange.
•OCTG - Oil country tubular goods.
•Oil spill prevention rate - Calculated as total Boe less net barrels lost divided by total Boe.
•OPEC - Organization of the Petroleum Exporting Countries.
•OPEC+ - OPEC together with Russia and certain other producing countries.
•PHMSA - Pipeline and Hazardous Materials Safety Administration.
•Proved developed reserves - Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
•Proved reserves - The estimated quantities of natural gas, NGLs, and oil that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations.
•Proved undeveloped reserves - Proved reserves that are expected to be recovered from new wells on undrilled acreage that are reasonably certain of production when drilled or from existing wells where a relatively major expenditure is required for recompletion.
•PSCs - Production-sharing contracts.
•PV-10 - Non-GAAP financial measure and represents the year-end present value of estimated future cash flows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum and using SEC Prices. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.
•Scope 1 emissions - Our direct emissions.
•Scope 2 emissions - Indirect emissions from energy that we use (e.g., electricity, heat, steam, cooling) that is produced by others.
•Scope 3 emissions - Indirect emissions from upstream and downstream processing and use of our products.
•SDWA - Safe Drinking Water Act.
•SEC - United States Securities and Exchange Commission.
•SEC Prices - The unweighted arithmetic average of the first day-of-the-month price for each month within the year used to determine estimated volumes and cash flows for our proved reserves.
•SOFR - Secured overnight financing rate as administered by the Federal Reserve Bank of New York.
•Standardized measure - The year-end present value of after-tax estimated future cash flows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum and using SEC Prices. Standardized measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions.
•TRIR - Total Recordable Incident Rate calculated as recordable incidents per 200,000 hours for all workers (employees and contractors).
•Working interest - The right granted to a lessee of a property to explore for and to produce and own oil, natural gas or other minerals in-place. A working interest owner bears the cost of development and operations of the property.
•WTI - West Texas Intermediate.
ITEMS 1 & 2 BUSINESS AND PROPERTIES
Business Overview and History
We are an independent oil and natural gas exploration and production company operating properties exclusively within California. We provide affordable and reliable energy in a safe and responsible manner, to support and enhance the quality of life of Californians and the local communities in which we operate. We do this through the development of our broad portfolio of assets while adhering to our commitment to create shareholder value. We also have some of the lowest carbon intensity production in the United States. We are committed to energy transition and decarbonization through our carbon management business that we refer to as Carbon TerraVault. We are in the early stages of developing several carbon capture and storage projects in California. In August 2022, Carbon TerraVault entered into a joint venture with BGTF Sierra Aggregator (Brookfield) to pursue certain of these opportunities (Carbon TerraVault JV). Over time, we intend to conduct our carbon management business on a stand-alone basis. We expect that this will provide greater flexibility to consider strategic options, including the potential separation from our E&P business. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV.
We qualified for and adopted fresh start accounting in connection with our emergence from bankruptcy on October 27, 2020, at which point we became a new entity for financial reporting purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start accounting and the effects of the implementation of our joint plan of reorganization (the Plan), the financial statements after October 31, 2020 may not be comparable to the financial statements prior to that date. Accordingly, "black-line" financial statements are presented to distinguish between Predecessor and Successor companies. References to "Predecessor" refer to the Company for periods ending on or prior to October 31, 2020 and references to "Successor" refer to the Company for periods subsequent to October 31, 2020.
See Part II, Item 8 – Financial Statements and Supplementary Data, Note 15 Chapter 11 Proceedings and Note 16 Fresh Start Accounting for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.
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.
Our strategy is to continue to develop our oil and natural gas assets while pursuing opportunities in the emerging industries of decarbonization and energy transition. To accomplish our strategy, we have developed the following key priorities:
•Adjust our corporate structure. We intend to manage our carbon management business on a stand-alone basis over time. We expect that this will provide greater flexibility to consider strategic options, including the potential separation from our E&P business. We also recently installed a board of directors at Carbon TerraVault Holdings, LLC that will focus on growing and developing our carbon management business on a stand-alone basis.
•Advance our carbon management business. We intend to continue to build our carbon management business through Carbon TerraVault. Our efforts will build on the progress made in 2022, including the formation of the Carbon TerraVault JV with Brookfield. We also executed two carbon management service agreements with Lone Cypress Energy Services, LLC and Grannus, LLC to provide permanent carbon storage. We are focused on signing up additional emitter projects and submitting additional Class VI permit applications with the EPA for permanent carbon capture and sequestration. We are also evaluating our Elk Hills power plant as a potential emissions source for carbon capture and sequestration, and are working with a consortium of industry participants to advance the development of a direct air capture hub to be located in Kern County.
•Execute on a core E&P development plan. In light of recent regulatory changes in California, we will reduce our average rig count to 1.5 rigs in 2023 (down from approximately 4 rigs in 2022) with a drilling program focused on executing projects where we have permits in hand. We also intend to increase our workover activity in 2023 to help minimize production decline. We further plan to develop field level EIRs for the CEQA review process which we expect will reduce uncertainty in obtaining permits for the majority of our proved undeveloped resources in future years.
•Focus on cost reductions and portfolio optimization. In light of the changing regulatory environment in California, we will adjust our capital program in 2023 to optimize near term cash flow. We intend to focus on cost reduction initiatives and expect to reduce our non-energy operating costs and general and administrative costs by the end of the year. We also plan to continue to pursue the sale of our Huntington Beach surface acreage as well as other non-core real estate assets.
•Improve our financial flexibility and maintain a strong balance sheet. We are pursuing options to amend and extend or replace our Revolving Credit Facility, as well as refinancing options for our $600 million of Senior Notes. We expect that these steps will allow us to extend our debt maturities and provide us with greater financial flexibility to increase shareholder returns. We also intend to pursue financing options for our carbon management business that are separate from the rest of our business. We remain committed to maintaining our strong liquidity position.
•Focus on increasing shareholder returns. CRC intends to optimize capital allocation and focus on cost reduction opportunities in 2023 to drive cash flow generation. We expect that the combination of these efforts will allow us to continue to increase shareholder returns. To that end, our Board has authorized a 30% increase to its shareholder repurchase program for a total of $1.1 billion, with approximately $640 million remaining on its authorization as of December 31, 2022 after taking into account this increase.
•Maintain our commitment to safety and sustainability and demonstrate leadership on ESG practices in the E&P space. We are committed to exceptional environmental and safety performance and achieved a 99.9999% oil spill prevention rate in 2022 and registered a workforce TRIR of 0.62. We have some of the lowest carbon intensity production among oil and natural gas producers in the United States and established a Full-Scope Net Zero goal to permanently store captured or removed carbon emissions equal to our Scope 1, 2 and 3 emissions by 2045, which aligns us with the State of California's 2045 net zero ambitions and puts us ahead of the net zero goals in the Paris Agreement. We intend to achieve this goal through our existing and future decarbonization projects, including those projects that will be developed by the Carbon TerraVault JV. Our ESG goals focus not only on lowering greenhouse gas emissions, but also decreasing methane emissions, reducing freshwater consumption, expanding leadership diversity, enhancing community engagement. We have increased accountability by linking executive compensation to ESG performance. For 2023, 30% of our management team's annual incentive related to company performance is tied to safety and ESG related metrics, including the advancement of our carbon management business.
Oil and Natural Gas Operations
As of December 31, 2022, our proved reserves totaled an estimated 417 MMBoe, of which 294 MMBbl were crude oil and condensate reserves, 38 MMBbl were NGL reserves and 511 BcF, or 85 MMBoe, were natural gas reserves.
As of December 31, 2022, we held approximately 1.9 million net mineral acres, the largest non-governmental mineral acreage position in California. Our operated asset base spans 97 distinct fields with approximately 10,000 operated wells. We had average net production of approximately 91 MBoe/d (60% oil) for the year ended December 31, 2022.
The following table highlights key information about our operations as of and for the year ended December 31, 2022:
|San Joaquin Basin||Los Angeles Basin|
|Sacramento Basin||Other||Total Operations|
Net mineral acreage (thousands)
|1,248 ||29 ||6 ||466 ||118 ||1,867 |
|Average net mineral acreage held in fee (%)||81 ||%||47 ||%||— ||%||41 ||%||97 ||%||71 ||%|
|Number of producing fields we operate||42 ||5 ||— ||50 ||— ||97 |
|Average drilling rigs||2 ||2 ||— ||— ||— ||4 |
|Net wells drilled and completed||114.3 ||35.0 ||— ||— ||— ||149.3 |
|Oil (MMBbl)||182 ||112 ||— ||— ||— ||294 |
|NGLs (MMBbl)||38 ||— ||— ||— ||— ||38 |
|Natural gas (Bcf)||451 ||7 ||— ||53 ||— ||511 |
|Total (MMBoe)||295 ||113 ||— ||9 ||— ||417 |
|Oil percentage of proved reserves||62 ||%||99 ||%||— ||%||— ||%||— ||%||71 ||%|
|Total net production (MMBoe)||25 ||7 ||— ||1 ||— ||33 |
|Average daily net production (MBoe/d)||70 ||18 ||— ||3 ||— ||91 |
(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 3 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 over 520 MMcf/d. Additionally, our Elk Hills power plant generates sufficient electricity to operate the field, and sells excess power to the wholesale market and a utility. 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 700,000 acres in the San Joaquin basin, or approximately 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 certain real estate properties, including two properties in Huntington Beach. One of these properties is a one-acre parcel at Fort Apache and the other is an approximately 90 acre surface property at our Huntington Beach field. At the Huntington Beach field, we have begun the plugging and abandonment of approximately 30 existing wells and are working towards the longer-term remediation of the larger property to provide flexibility for real estate sales in the future.
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. Our significant mineral acreage position in the Sacramento basin gives us the option for future development and rapid production growth in an attractive natural gas price environment.
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. Our remaining Ventura basin asset is expected to be sold in the first half of 2023.
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.
The following table summarizes our gross and net developed and undeveloped mineral acreage as of December 31, 2022.
|San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin|
| ||(in thousands)|
| || || || || |
|460 ||20 ||6 ||259 ||2 ||747 |
|421 ||15 ||6 ||246 ||1||689 |
| || || || |
|1,008 ||17 ||— ||265 ||142||1,432 |
|827 ||14 ||— ||220 ||117||1,178 |
|1,468 ||37 ||6 ||524 ||144 ||2,179 |
|1,248 ||29 ||6 ||466 ||118 ||1,867 |
(a)Reflects remaining mineral acreage to be retained in the Ventura Basin and nearby areas. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 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, 2022, 71% of our total net mineral interest position was held in fee and the remainder was leased. Of our leased acreage, approximately 63% 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 41,000 net mineral acres will expire in 2023, 35,000 net mineral acres will expire in 2024 and 14,000 net mineral acres will expire in 2025. These leases represent 8% of our total net undeveloped acreage and 5% of our total net acreage as of December 31, 2022 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,||Year Ended December 31,||November 1, 2020 - December 31, 2020||January 1, 2020 - October 31, 2020|
|Average daily net production|
|Oil (MBbl/d)||55 ||60 ||63 ||70 |
|NGLs (MBbl/d)||11 ||13 ||12 ||13 |
|Natural gas (MMcf/d)||147 ||159 ||165 ||174 |
|Total daily net production (MBoe/d)||91 ||100 ||103 ||112 |
|Total production (MMBoe)||33 ||36 ||6 ||34 |
|Average realized prices|
|Oil with hedge ($/Bbl)||$||61.80 ||$||56.05 ||$||45.37 ||$||43.19 |
|Oil without hedge ($/Bbl)||$||98.26 ||$||70.43 ||$||45.65 ||$||41.21 |
|NGLs ($/Bbl)||$||64.33 ||$||53.62 ||$||38.00 ||$||25.70 |
|Natural gas without hedge ($/Mcf)||$||7.68 ||$||4.22 ||$||3.21 ||$||2.11 |
|Average benchmark prices|
|Brent oil ($/Bbl)||$||98.89 ||$||70.79 ||$||47.10 ||$||42.43 |
|WTI oil ($/Bbl)||$||94.23 ||$||67.91 ||$||44.21 ||$||38.44 |
|NYMEX gas ($/MMBtu) - Contract Month Average||$||6.36 ||$||3.61 ||$||2.86 ||$||1.95 |
|NYMEX gas ($/MMBtu) - Average Monthly Settled Price||$||6.64 ||$||3.84 ||$||2.95 ||$||1.90 |
|Operating costs per Boe|
|Operating costs||$||23.75 ||$||19.39 ||$||18.19 ||$||14.95 |
Oil, natural gas and NGL production for our two largest fields are presented in the table below:
| ||Elk Hills||Wilmington|
|Average daily net production|| || || || || || |
|Oil (MBbl/d)||17 ||17 ||18 ||15 ||16 ||21 |
|NGLs (MBbl/d)||8 ||10 ||10 ||— ||— ||— |
|Natural gas (MMcf/d)||75 ||81 ||90 ||— ||— ||1 |
|Total daily net production (MBoe/d)||38 ||40 ||43 ||15 ||16 ||21 |
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 16% of our total production for the year ended December 31, 2022.
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,||Year ended December 31,||November 1, 2020 - December 31, 2020||January 1, 2020 - October 31, 2020|
|(in millions)||($ per Boe)||(in millions)||($ per Boe)||(in millions)||($ per Boe)||(in millions)||($ per Boe)|
|Operating costs||$||785 ||$||23.75 ||$||705 ||$||19.39 ||$||114 ||$||18.19 ||$||511 ||$||14.95 |
|Excess costs attributable to PSCs||(74)||(2.23)||(66)||$||(1.83)||(8)||$||(1.33)||(28)||$||(0.81)|
Operating costs, excluding effects of PSCs(a)
|$||711 ||$||21.52 ||$||639 ||$||17.56 ||$||106 ||$||16.86 ||$||483 ||$||14.14 |
(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,||Year ended December 31,||November 1, 2020 - December 31, 2020||January 1, 2020 - October 31, 2020|
|Average Daily Net Production||91||100||103||112|
|Partners' share under PSC-type contracts||8||8||6||5|
|Working interest and royalty holders' share||6||8||9||11|
|Average Daily Gross Production||106||117||119||129|
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 United States Securities and Exchange Commission (SEC).
The following tables summarize our estimated proved oil (including condensate), NGLs and natural gas reserves and PV-10 as of December 31, 2022. 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 $100.25 per barrel was adjusted for gravity, quality and transportation costs. For natural gas volumes, the average NYMEX gas price of $6.36 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, 2022 were $97.50 per barrel for oil, $67.83 per barrel for NGLs and $7.84 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, 2022|
| ||San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin||Total|
|Proved developed reserves|| || || || || |
|Oil (MMBbl)||155 ||96 ||— ||— ||251 |
|NGLs (MMBbl)||36 ||— ||— ||— ||36 |
|Natural Gas (Bcf)||399 ||6 ||— ||53 ||458 |
|257 ||97 ||— ||9 ||363 |
|Proved undeveloped reserves|| || || || || |
|Oil (MMBbl)||27 ||16 ||— ||— ||43 |
|NGLs (MMBbl)||2 ||— ||— ||— ||2 |
|Natural Gas (Bcf)||52 ||1 ||— ||— ||53 |
|Total (MMBoe)||38 ||16 ||— ||— ||54 |
|Total proved reserves|| || || || || |
|Oil (MMBbl)||182 ||112 ||— ||— ||294 |
|NGLs (MMBbl)||38 ||— ||— ||— ||38 |
|Natural Gas (Bcf)||451 ||7 ||— ||53 ||511 |
|Total (MMBoe)||295 ||113 ||— ||9 ||417 |
Reserves to production ratio (years)(b)
(a)As of December 31, 2022, approximately 19% of proved developed oil reserves, 7% of proved developed NGLs reserves, 10% of proved developed natural gas reserves and, overall, 16% 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, 2022 divided by total production for the year ended December 31, 2022.
Changes to Proved Reserves
The components of the changes to our proved reserves during the year ended December 31, 2022 were as follows:
| ||San Joaquin Basin|
Los Angeles Basin(a)
|Ventura Basin||Sacramento Basin||Total|
|Balance at December 31, 2021||324 ||140 ||2 ||14 ||480 |
|Revisions related to price||3 ||2 ||— ||1 ||6 |
|Revisions related to performance||(5)||(7)||— ||(4)||(16)|
|Revisions due to California regulatory changes and court challenges||(16)||(17)||(1)||(34)|
|Extensions and discoveries||14 ||2 ||— ||— ||16 |
|Improved recovery||6 ||— ||— ||— ||6 |
|Acquisitions and divestitures||(6)||— ||(2)||— ||(8)|
|Balance at December 31, 2022||295 ||113 ||— ||9 ||417 |
(a)Includes proved reserves related to PSCs of 92 MMBoe and 111 MMBoe at December 31, 2022 and 2021, respectively.
Revisions related to price – We had net positive price-related revisions of 6 MMBoe primarily resulting from a higher commodity price environment in 2022 compared to 2021. The price revision reflects the extended economic lives of our fields, estimated using 2022 SEC pricing. Additionally, we have experienced higher vendor-related pricing and compensation-related cost increases due to inflation.
Revisions related to performance – We had 16 MMBoe of net negative performance-related revisions which included negative performance-related revisions of 31 MMBoe and positive performance-related revisions of 15 MMBoe. 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. Our positive performance-related revisions primarily related to better-than-expected well performance and addition of proved undeveloped locations due to positive drilling results in certain areas. The majority of these revisions were located in the San Joaquin and Los Angeles basins.
Revisions due to California regulatory changes and court challenges – We had 34 MMBoe of negative revisions to our proved reserves due to the impact of California regulatory changes and court challenges on our development plans. Of this amount, negative revisions of 20 MMBoe of proved reserves were 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 LA Basin. Negative revisions of 14 MMBoe to our proved reserves were due to challenges to Kern County's ability to issue well permits in reliance on an existing EIR for CEQA purposes. The volumes affected by these court challenges are in Kern County. See Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities.
Extensions and discoveries – We added 16 MMBoe from extensions and discoveries resulting from successful drilling and workovers in the San Joaquin and Los Angeles basins.
Acquisitions and Divestitures – We had a reduction of 8 MMBoe which primarily related to our Lost Hills divestiture. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more information on these transactions.
Proved Undeveloped Reserves
The total changes to our proved undeveloped reserves during the year ended December 31, 2022 were as follows:
| ||San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin||Total|
|Balance at December 31, 2021||45 ||30 ||— ||— ||75 |
|Revisions related to price||1 ||(2)||— ||— ||(1)|
|Revisions related to performance ||(5)||2 ||— ||— ||(3)|
|Revisions due to California regulatory changes and court challenges||(12)||(11)||— ||— ||(23)|
|Extensions and discoveries||10 ||1 ||— ||— ||11 |
|Improved recovery||6 ||— ||— ||— ||6 |
|Divestitures||(2)||— ||— ||— ||(2)|
|Transfers to proved developed reserves||(5)||(4)||— ||— ||(9)|
|Balance at December 31, 2022||38 ||16 ||— ||— ||54 |
Revisions related to price – We had 1 MMBoe of net negative price-related revisions. Positive price-related revisions of 2 MMBoe were offset by 3 MMBoe of negative cost recovery barrels in our PSCs.
Revisions related to performance – We had 3 MMBoe of net negative performance-related revision which included 4 MMBoe positive performance-related revisions and negative performance-related revisions of 7 MMBoe. Our positive performance-related revisions of 4 MMBoe primarily related to better-than-expected well performance and the addition of proved undeveloped locations due to positive drilling results in certain areas. The positive revision also included proved undeveloped reserves which were added to our five-year development plan in 2022. Our negative performance-related revisions primarily related to unsuccessful drilling results in certain areas. The majority of these revisions were located in the San Joaquin and Los Angeles basins.
Revisions due to California regulatory changes and court challenges – We removed 23 MMBoe from proved undeveloped reserves due to the impact of the regulatory changes and court challenges on our development plans as discussed above. 11 MMBoe of proved undeveloped reserves were affected by Senate Bill No. 1137. 12 MMBoe of proved undeveloped reserves were affected by the Kern County court challenges. These revisions are largely due to the uncertainty of near term permitting of drilling projects and the deferral of development of certain projects beyond 5 years. The volumes impacted are in Kern County. See Regulation of the Industries in Which We Operate, Regulations of Exploration and Production Activities.
Extensions and discoveries – We added 11 MMBoe of proved undeveloped reserves through extensions and discoveries, as a result of successful drilling and workover programs in the San Joaquin and Los Angeles basins.
Transfers to proved developed reserves – We converted 9 MMBoe of proved undeveloped reserves to proved developed reserves in the San Joaquin and Los Angeles basins. This resulted in a conversion rate of approximately 12% of our beginning-of-year proved undeveloped reserves, with an investment of approximately $127 million of drilling and completion capital. We believe we will have sufficient capital to develop all year end 2022 proved undeveloped reserves within five years of their original booking date.
PV-10 and Standardized Measure
PV-10 of cash flows is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC Prices. Calculation of PV-10 does not give effect to derivative transactions. Our PV-10 is computed on the same basis as our standardized measures of future net cash flows, the most comparable measure under GAAP, but does not include the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.
|As of December 31, 2022|
|Standardized measure of discounted future net cash flows||$||6,726 |
|Present value of future income taxes discounted at 10%||2,493 |
PV-10 of cash flows(a)
(a)The average realized prices for estimating our PV-10 of cash flow as of December 31, 2022 were $97.50 per barrel for oil, $67.83 per barrel for NGLs and $7.84 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, 2022 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 Vice President of Reserves has primary responsibility for overseeing the preparation of our reserves estimates. With over 25 years of technical and leadership experience in the oil and gas industry, she has been involved with all stages of petroleum exploration and development from appraisal of new discoveries to enhanced recovery methods in mature fields. She holds a Master of Business Administration from Pepperdine University, as well as bachelor’s and master’s degrees in Geology from the University of California, Santa Barbara.
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 2022. The Reserves Committee annually reports its findings to the Audit Committee.
Audits of Reserves Estimates
Ryder Scott and Netherland, Sewell & Associates, Inc. (NSAI) were engaged to provide independent audits of our reserves estimates for our fields. For the year ended December 31, 2022, Ryder Scott audited 49% of our total proved reserves. NSAI audited 36% of our total proved reserves. Collectively, 85% of our proved reserves were audited in 2022.
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. Both of our independent reserve engineers issued an unqualified audit opinion on the applicable portions of our proved reserves as of December 31, 2022, which are attached as Exhibit 99.1 and 99.2, respectively, to this Form 10-K and incorporated herein by reference.
Ryder Scott qualifications – The primary technical engineer responsible for our audit has more than 45 years of petroleum engineering experience, the majority of which has been in the estimation and evaluation of reserves. He serves on the Ryder Scott Executive Committee and the Board of Directors and is a registered Professional Engineer in the state of Texas.
NSAI qualifications – The primary technical engineer responsible for our audit has more than 21 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.
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|
|2022|| || || || || |
|Productive|| || || || || |
|Exploratory||— ||— ||— ||— ||— |
|Development||114.3 ||35.0 ||— ||— ||149.3 |
|Dry|| || || || |
|Exploratory||— ||— ||— ||— ||— |
|Development||— ||— ||— ||— ||— |
|2021|| || || || || |
|Productive|| || || || || |
|Exploratory||— ||— ||— ||— ||— |
|Development||109.4 ||6.5 ||— ||— ||115.9 |
|Dry|| || || || |
|Exploratory||— ||— ||— ||— ||— |
|Development||— ||— ||— ||— ||— |
|2020|| || || || || |
|Productive|| || || || || |
|Exploratory||— ||— ||— ||— ||— |
|Development||4.0 ||4.5 ||— ||0.4 ||8.9 |
|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, 2022.
|San Joaquin Basin||Los Angeles Basin||Ventura Basin||Sacramento Basin||Total Net Wells|
|Gross||3.0 ||3.0 ||— ||— ||6.0 |
|Net||3.0 ||2.8 ||— ||— ||5.8 |
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 92% as of December 31, 2022. 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, 2022, excluding wells that have been idle for more than five years:
|As of December 31, 2022|
|Productive Oil |
|Productive Natural Gas Wells|
|San Joaquin Basin||7,312 ||6,802 ||158 ||156 |
|Los Angeles Basin||1,730 ||1,640 ||— ||— |
|Ventura Basin||20 ||20 ||— ||— |
|Sacramento Basin||— ||— ||920 ||849 |
|Total||9,062 ||8,462 ||1,078 ||1,005 |
|Multiple completion wells included in the total above||126 ||123 ||17 ||15 |
(a)The total number of wells in which interests are owned.
(b)Net wells include wells reduced to our fractional interest.
We have had minimal investment in exploration activity in recent years, and our 2023 capital plan does not allocate any capital towards exploration drilling.
Crude Oil – We sell nearly all of our crude oil to California refiners. Substantially all 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 done on a daily basis using 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 6,500 barrels per day of NGLs through March 2023. 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.
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 wholesale power market and a local utility. We also sell the remaining capacity to community choice aggregates and other local utilities.
We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. As of December 31, 2022, we had oil delivery commitments of 10 MMBbl in 2023, 3 MMBbl in 2024 and 1 MMBbl in 2025, NGL delivery commitments of 1 MMBbl through March 2023 and natural gas delivery commitments of 13 Bcf through December 2023. 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.
We protect our operating cash flow from volatility in the commodities market through our hedging strategy. Prior to May 2022, our Revolving Credit Facility required us to maintain certain levels of hedges regardless of our leverage. We also entered into incremental hedges above and beyond these requirements for certain time periods. In certain circumstances, these hedges (including hedges entered into by us in 2020 to comply with covenants in our Revolving Credit Facility) prevent us from realizing the full benefits of price increases. Following an amendment to our Revolving Credit Facility in April 2022, we are only required to maintain hedges in the event the ratio of our consolidated total debt to consolidated EBITDAX as defined in our Credit Agreement exceeds 1:1. 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 7 Derivatives for more information on our commodity contracts.
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.
Our competitors are primarily other exploration and production companies that produce oil, natural gas and NGLs. We compete locally against small independent producers and major international oil companies 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. In 2022, we experienced increased costs due to inflation. 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 levels, 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 power plants 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.
The infrastructure used in our operations, including plants and facilities located in the Wilmington field, is presented below:
|San Joaquin Basin||Other Basins||Total|
Gas Processing Plants(a)
Water Management Systems(c)
Oil and NGL Storage(d)
(a)Includes the Elk Hills cryogenic gas plant with a capacity of 200 MMcf/d of inlet gas and two low temperature separation plants used as backup facilities. 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 contiguous operations in the San Joaquin basin. We utilize approximately a third of its capacity for operations and our subsidiary sells the excess to the grid and to a local utility. 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
In 2021, we adopted a 2045 Full-Scope Net Zero goal to achieve permanent storage of captured or removed carbon emissions in a volume equal to all of our Scope 1, 2 and 3 emissions by 2045. Our climate-related goal could be modified as standards and rules develop related to greenhouse gas emissions, and the potential separation of our carbon management business would also affect our ability to reach this goal.
We have formed a carbon management business to pursue CCS projects that are directly-sited or within close proximity to significant sources of CO2 emissions in California. We intend to manage our carbon management business on a stand-alone basis over time. We expect that this will provide greater flexibility to consider strategic options, including the potential separation from our E&P business. To facilitate that goal, we have created a new board of directors at Carbon TerraVault, initially comprised of three of our directors: Mark A. (Mac) McFarland, Andrew Bremner and James Chapman.
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. We have also submitted permit applications for two permanent sequestration projects in the Sacramento Basin.
We continue to evaluate potential storage projects in California. One of our storage projects is being jointly developed through the Carbon TerraVault JV. Several other projects are being considered by the Carbon TerraVault JV for future development. If Brookfield elects to participate in a project, 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.
In 2022, we executed two 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. The CDMAs are also subject to negotiation of definitive documents and a final investment decision. One of the CDMAs relates to a project that will be developed through the Carbon TerraVault JV. We are separately in discussions with other potential emitters to enter into joint venture 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 sources into subsurface reservoirs and permanently store CO2 deep underground. As part of our commitment to carbon management, we are also evaluating the feasibility of developing a carbon capture system for our 550-megawatt Elk Hills power plant (CalCapture) and pursuing a U.S. Department of Energy grant for the development of a direct air capture hub in California.
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 the Carbon TerraVault JV 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, payable in three equal 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. 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.
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 8 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.
As of December 31, 2022, we had approximately 1,060 employees, all in the United States. Of the total 1,060 employees, 45 full-time equivalents are focused on our carbon management business. Approximately 50 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 include 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. 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 women and minorities in our workplace. We believe increasing diversity, equity and inclusion (DE&I) will help us achieve success through better retention rates, higher innovation, and increased productivity. We have implemented a 2030 ethnic, racial and gender diversity leadership goal that prioritizes ethnic, racial and gender diversity in company leadership positions and on the Board of Directors. Our goal is three pronged, to maintain greater than 20% ethnically and racially
diverse professionals in leadership positions, increase gender diverse professionals in leadership positions to 30% and maintain current Board composition with at least 30% ethnically, racially and gender diverse Board members. We also established an Advisory Council focused on career development, promotion, recruitment and retention to help ensure that we meet our DE&I goals. In 2022, we had 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, 2022.
|Gender Diverse||Ethnically and Racially Diverse|
|Board of Directors||33%||33%|
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 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 are described in this section.
Regulation of Exploration and Production Activities
CalGEM is California's primary regulator of the oil and natural gas production industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. From time to time we have experienced significant delays with respect to obtaining drilling permits from CalGEM for our operations. A variety of factors outside of our control can lead to such delays. CalGEM has not issued any permits for new production wells to any operators since December 2022.
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.
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 (Kern County EIR Litigation). In March 2018 a trial court (Trial Court) found that the EIR inadequately analyzed the environmental impacts to rangeland and road paving mitigation for purposes of well work and rejected the plaintiffs’ other CEQA claims. The plaintiffs appealed. In February 2020, the California Fifth District Appellate Court (Appellate Court) ruled that the plaintiffs’ other CEQA claims had merit and ordered Kern County to rescind the Zoning Ordinance and cease issuing permits. In March 2021, Kern County’s Board of Supervisors approved a revised Zoning Ordinance (the Revised Ordinance) and certified a Supplemental Recirculated Environmental Impact Report (SREIR) for purposes of satisfying CEQA requirements with respect to the issuance of oil and natural gas permits. A suit was subsequently filed that same month challenging the sufficiency of the SREIR. In October 2021, the Trial Court ordered Kern County to cease using the existing EIR to meet CEQA requirements until it determined that the Revised Ordinance complied with CEQA requirements. The Trial Court subsequently identified four deficiencies in the SREIR that needed correction to conform to CEQA. In November 2022, upon the correction of those deficiencies to the Trial Court’s satisfaction, the Trial Court lifted the suspension on Kern County's ability to rely on the existing SREIR to meet CEQA requirements in Kern County (the Discharge Order). In December 2022, the Trial Court denied a motion to stay the Discharge Order. The plaintiffs appealed the judgment and Discharge Order and filed a petition requesting a stay of the ordinance pending resolution of the merits of the appeal.
On January 26, 2023, the Appellate Court issued a preliminary order on the petition reinstating a suspension of Kern County's ability to rely on the existing SREIR to meet CEQA requirements pending the outcome of a final order determining whether oil and natural gas permitting shall remain suspended for the duration of the appeals process. That order is still pending.
We intend to address CEQA compliance for our oil and natural gas permits in Kern County through alternative pathways. However, this will be a lengthy process and we cannot predict whether this approach will ultimately be successful. As a result of these issues and current lack of permits with respect to our Kern County properties, we do not currently plan to drill and complete any additional wells within Kern County until permitting is resumed in Kern County, which may be later in the 2024 calendar year. 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 71% of our proved undeveloped reserves or 9% of our total proved reserves relate to wells to be drilled in Kern County beginning in 2024 for which we would need to obtain permits.
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. Other 2019 legislation specifically addressed oil and natural gas leasing by the State Lands Commission, including imposing conditions on assignment of state leases, requiring lessees to complete abandonment and decommissioning upon the termination of state leases, and prohibiting leasing or conveyance of state lands for new oil and natural gas infrastructure that would advance production on certain federal lands such as national monuments, parks, wilderness areas and wildlife refuges.
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. For example, a similar ban was previously proposed in Monterey County, where we own mineral rights but have no production, before being declared to be preempted by state and federal regulation. Other local governments have sought to ban natural gas or the transportation of natural gas through their cities. The City of Antioch declined to extend our franchise agreement for a natural gas pipeline through its city. Several companies, including CRC, have challenged the city’s inconsistent and arbitrary approach to natural gas approvals.
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 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. The regulations included applicable requirements of notice to property owners and tenants regarding the work performed and offering the sampling of test water wells or surface water before and after drilling; the contents of required notices for new production facilities; the annual submission of a sensitive receptor inventory and sensitive receptor map and the contents and format of the same; and the requirements of statements where operators have determined a location not to be within a health protection zone. Additional provisions of Senate Bill No. 1137 include, among others, the imposition of health, safety and environmental controls applicable to both current and new wells located within this distance of sensitive receptors related to noise, light, and dust pollution controls and air emission monitoring, and the immediate suspension of operations at production facilities determined to not be in compliance with certain air emission requirements. In December 2022, proponents of a voter referendum (the Referendum) collected more than the requisite number of signatures required to put Senate Bill No. 1137 on the 2024 ballot. On February 3, 2023, 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, although any stay could be delayed if there are legal challenges to the Secretary of State's certification. In addition, even during the stay, CalGEM could attempt to initiate rulemaking with regard to setbacks.
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 develop proved undeveloped reserves within the setback zones established by Senate Bill No. 1137. As a result, we have removed from our reserves any proved undeveloped reserves that are located within setback zones, except for those reserves for which we have existing drilling permits and intend to develop prior to the November 2024 ballot. This resulted in a reduction to the net present value of our proved undeveloped reserves by 24% and our overall proved reserves by 4% as of December 31, 2022.
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.
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 sources of drinking water, 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. If CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient, 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.
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.
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.
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. Since the state and the EPA did not complete their review before the state’s deadlines, the state announced that it will not rescind permits or enforce the deadlines with respect to many of the formations pending completion of the review but has applied the deadlines to others. Several industry groups and operators challenged CalGEM’s implementation of its aquifer exemption regulations. In March 2017, the Kern County Superior Court issued an injunction barring the blanket enforcement of CalGEM’s aquifer exemption regulations. The court found that CalGEM must find actual harm results from an injection well’s operations and go through a hearing process before the agency can issue fines or shut down operations. 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. We are coordinating with the state to change injection zones in certain fields to facilitate disposal of produced water in deeper formations where feasible or to increase recycling of produced water in pressure maintenance or waterfloods in lieu of disposal. In September 2021, the EPA issued a letter to the California Natural Resources Agency and the State Water Resources Control Board regarding the state's compliance with the 2015 compliance plan relating to the state's process for approving aquifer exemptions under the SDWA. The letter requested that California take appropriate action by September 2022, or the EPA would consider taking additional action to impose limits on California's administration of the UIC program, withhold federal funds for the administration of the UIC program, and direct orders to oil and natural gas operators injecting into formations not authorized by the EPA, among other measures. The state responded in October 2021 with a proposed compliance plan and a follow-up letter in August 2022 providing a mid-year update, but, to date, the EPA has not yet responded.
With respect to major federal actions pursuant to NEPA, recent modifications 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. “Phase 2” of the process includes the release of a new rule proposing broader changes to NEPA regulations.
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
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. Protocols to support CCS are to be adopted by January 1, 2024 and a unified permit application is to be adopted by January 1, 2025. We believe our Carbon TerraVault projects, for which permits with the EPA have been filed, 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 PHMSA, which could take a number of years to effect. However, 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.
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 (the Act), 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.
President Biden signed the Act into law on August 16, 2022. Beginning in 2024, the Act’s methane emissions charge imposes a fee on excess methane emissions from certain oil and natural gas facilities, including some of our facilities, starting at $900 per metric ton of leaked methane in 2024 and rising to $1,200 in 2025, and $1,500 in 2026 and thereafter.
The Act also enhanced existing credits for emissions reduction and sequestration (45Q credit) by increasing the size of the credit to $85 per metric ton when captured from industrial and power generation facilities, and to $180 per metric ton when utilizing direct air capture facilities. The Act also extended the date for when qualifying facilities must begin construction by seven years, among other modifications. Further, a direct pay option for the 45Q credit (for a limited five-year period) was added and the Act provides an option to monetize the 45Q credit through a sale to another taxpayer. These additional energy-related tax incentives are effective for new projects beginning on January 1, 2023 and enhance the development of CCS projects in California.
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 made climate change a focus of his administration, and he has issued several executive orders on the subject, which, among other things, recommitted the United States to the Paris Agreement in 2021, called for the reinstatement or issuance of methane emissions standards for new, modified and existing oil and natural gas facilities (rules pertaining to which have been proposed by the EPA) and called for 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.
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 2025. 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 California Air Resources Board (CARB) have also expanded direct regulation of methane as a contributor to GHG emissions. In 2016, the EPA adopted regulations to require additional emission controls for methane, volatile organic compounds and certain other substances for new or modified oil and natural gas facilities. Although the EPA rescinded the methane-specific requirements for production and processing facilities in September 2020, the U.S. Congress subsequently approved, and President Biden signed into a law, a resolution to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish new source and first-time existing source standards of performance for methane and volatile organic compound emissions for oil and natural gas facilities. In November 2022, the EPA issued a supplemental proposal which sets forth specific revisions strengthening the first nationwide emissions guidelines for states to limit methane from existing oil and natural gas facilities and revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, among other items. The proposal is expected to be finalized in 2023, though it will likely be challenged. Moreover, CARB has implemented more stringent regulations that require monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil and natural gas production, pipeline gathering and boosting facilities and natural gas processing plants, as well as additional controls such as tank vapor recovery to capture methane emissions.
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.
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.
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.
Risks Related to Our Business
•Prices for our products can fluctuate widely and an extended period of low prices 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.
•We may not be able to successfully separate our carbon management business from our E&P business, or we may decide not to effect such separation.
•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.
•Our ability to grow our Carbon TerraVault business and develop large scale CCS projects is subject to numerous risks and uncertainties. If we are unable to successfully execute our CCS strategy, it could have an adverse effect on our business, results of operations and financial condition.
•The economics of CCS projects depend on financial and tax incentives that may not currently be sufficient for our CCS projects to be economical or could be changed or terminated.
•Our Carbon TerraVault JV with Brookfield is subject to inherent uncertainties, which could force us to delay or cancel CCS projects or seek alternative sources of capital to fund our CCS projects and thereby adversely affect our ability to implement our carbon management strategy.
•Drilling for and producing oil and natural gas carry significant operational and financial 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. We may be unable to fund our capital program, or reach satisfactory terms for other future capital requirements which could lead to a decline in our oil and natural gas reserves or production. Our capital investment program is also susceptible to risks that could materially affect its implementation.
•We have been negatively impacted by inflation.
•We are subject to economic downturns and the effects of public health events, such as the COVID-19 pandemic, which may materially and adversely affect the demand and the market price for our products.
•The conflict in Ukraine and 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 current and potential competitors have or may potentially have greater resources than we have and we may not be able to successfully compete in acquiring, exploring and developing new properties.
•Our hedging activities limit our ability to realize the full benefits of increases in commodity prices.
•Our level of hedging activities 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 lower than estimated.
Risks Related to Regulation and Government Action
•We may not be able to timely obtain drilling permits as a result of recent and future actions by the State of California.
•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, which 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 that, among other things, requires us to obtain and maintain permits for the injection and sequestration of CO2. Many of these regulations are 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.
•Recent changes in California law may result in delays to our carbon capture, sequestration and storage projects.
•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.
•Adverse tax law changes may affect our operations.
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.
General Risk Factors
•Increasing attention to ESG matters may adversely impact our business.
•Acquisition and disposition activities involve substantial risks.
•We may incur substantial losses and be subject to substantial liability claims as a result of pollution, environmental conditions or catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
•Cybersecurity attacks, systems failures and other disruptions could adversely affect us.
Risks Related to Our Business
Prices for our products can fluctuate widely and an extended period of low prices 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 sustained period of low prices for oil, natural gas and NGLs 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 supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:
•changes in domestic and global supply and demand;
•domestic and global inventory levels;
•political and economic conditions, including international disputes such as the conflict between Ukraine and Russia;
•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;
•weather conditions and other seasonal impacts;
•speculative trading in derivative contracts;
•currency exchange rates;
•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 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;
•affecting our ability to attract counterparties and enter into commercial transactions, including hedging, surety or insurance transactions; 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.
We may not be able to successfully separate or finance our carbon management business from our E&P business, or we may decide not to effect such separation.
On February 24, 2023, we announced that we had adjusted our corporate operating structure, including setting up a board of directors at Carbon TerraVault, to facilitate the separate operation of our E&P and carbon management businesses. We also intend to pursue 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.
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. See Risks Related to our Business – The economics of CCS projects depend on financial and tax incentives that may not currently be sufficient for our CCS projects to be economical or could be changed or terminated, Risks Related to our Business – Our Carbon TerraVault JV with Brookfield is subject to inherent uncertainties, which could force us to delay or cancel CCS projects or seek alternative sources of capital to fund our CCS projects and thereby adversely affect our ability to implement our carbon management strategy. 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.
Our ability to grow our Carbon TerraVault business and develop large scale CCS projects is subject to numerous risks and uncertainties. If we are unable to successfully execute our CCS strategy, it could have an adverse effect on our business, results of operations and financial condition.
We have announced a strategy to pursue the development of a carbon management business in California. To our knowledge, there are no existing large scale CCS projects in California similar to those that we are seeking to have developed. These projects face operational, technological and regulatory risks that could be considerable due to 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 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 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 being developed.
•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 procure sufficient quantities of CO2 on terms that are acceptable to us, and the failure to do so may have a material impact on our ability to execute our CCS strategy.
•The development and operation of cost-effective, commercial-scale hydrogen and ammonia production facilities and associated sequestration facilities is highly complex. There can be no assurances that 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.
•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.
•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 – Senate Bill 905 may result in delays to our CCS projects described below.
•Other regulatory uncertainties, see Risks Related to Regulation and Government Action – Our Carbon TerraVault business and our CCS projects are subject to extensive government regulation that, among other things, requires us to obtain permits for the injection of CO2. Many of these regulations are still being developed. Failure to comply with these requirements and obtain the necessary permits, or the development of government regulation that is unfavorable to our CCS projects, could have a material adverse effect on our business, results of operations and financial condition described below.
There can be no assurances that we will successfully develop our CCS projects, including Carbon TerraVault and 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.
The economics of CCS projects depend on financial and tax incentives that may not currently be sufficient for our CCS projects to be economical or could be changed or terminated.
Congress has incentivized the development of carbon capture projects through the establishment of tax credits for the capture and sequestration of CO2, the production of clean hydrogen and the production of other clean fuels. The successful development of our 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 on our CCS projects is dependent upon satisfaction of certain requirements, which we cannot assure you that we (or our partners) will satisfy. One of those requirements is that a minimum volume of CO2