UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

☑    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

    For the fiscal year ended December 31, 2021

☐    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)

Delaware	46-5670947
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

27200 Tourney Road, Suite 200

Santa Clarita, California 91355

(Address of principal executive offices) (Zip Code)

(888) 848-4754

(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.                         ☑

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, 2021: $2,467,158,949.

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, 2022, there were 78,744,340 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement to be filed within 120 days after December 31, 2021 with the Securities and Exchange Commission in connection with the registrant's 2022 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

		Page
Part I
Items 1 & 2	BUSINESS AND PROPERTIES	7
	Business Overview and History	7
	Business Strategy	7
	Operations	9
	Mineral Acreage	11
	Production, Price and Cost History	12
	Estimated Proved Reserves, Future Net Cash Flows and Drilling Locations	14
	Drilling Statistics	19
	Productive Wells	19
	Exploration Inventory	20
	Carbon Management Business	20
	Human Capital	20
	Marketing Arrangements	22
	Infrastructure	24
	Regulation of the Oil and Natural Gas Industry	24
	Available Information	29
Item 1A	RISK FACTORS	30
Item 1B	UNRESOLVED STAFF COMMENTS	45
Item 3	LEGAL PROCEEDINGS	45
Item 4	MINE SAFETY DISCLOSURES	45
Part II
Item 5	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	46
Item 6	RESERVED	49
Item 7	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	50
	Basis of Presentation	50
	Production, Prices and Realizations	51
	Divestitures	53
	Acquisitions and Joint Ventures	54
	Dividend Payment	54
	Share Repurchase Program	55
	Seasonality	55
	Income Taxes	55
	Statement of Operations Analysis	56
	Liquidity and Capital Resources	62
	Uses of Cash	63
	Lawsuits, Claims, Commitments and Contingencies	65
	Critical Accounting Estimates	65
	Significant Accounting and Disclosure Changes	67
	FORWARD-LOOKING STATEMENTS	68
Item 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	70
Item 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	71
	Report of Independent Registered Public Accounting Firm	71
	Consolidated Balance Sheets	74

3

		Page
	Consolidated Statements of Operations	75
	Consolidated Statements of Comprehensive Income (Loss)	76
	Consolidated Statements of Changes in Stockholders' Equity (Deficit)	77
	Consolidated Statements of Cash Flows	79
	Notes to Consolidated Financial Statements	81
	Supplemental Oil and Gas Information (Unaudited)	132
	SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS	137
Item 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	138
Item 9A	CONTROLS AND PROCEDURES	138
Item 9B	OTHER INFORMATION	139
Item 9C	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	139
Part III
Item 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	140
	EXECUTIVE OFFICERS	140
Item 11	EXECUTIVE COMPENSATION	141
Item 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	141
Item 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	141
Item 14	PRINCIPAL ACCOUNTANT FEES AND SERVICES	141
Part IV
Item 15	EXHIBITS	142

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GLOSSARY AND SELECTED ABBREVIATIONS

The following are abbreviations and definitions of certain terms used within this Form 10-K:

•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 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.

•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.

•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.

•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.

•OPEC - Organization of the Petroleum Exporting Countries.

•PHMS - 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.

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•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.

•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.

•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.

6

PART I

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 ample, 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 making value-based capital investments. Further, we are committed to energy transition and have some of the lowest carbon intensity production in the United States. Through our subsidiary, Carbon TerraVault, we are in the early stages of developing several carbon capture and sequestration projects in California. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant (CalCapture). We are also pursuing multiple solar projects for supplying the grid (front-of-the-meter solar) and powering our operations (behind-the-meter solar). 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.

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 14 Chapter 11 Proceedings and Note 15 Fresh Start Accounting for additional information on the terms of the Plan, our emergence from bankruptcy and application of fresh start accounting.

Business Strategy

Our strategy is to continue to develop our oil and natural gas assets and while pursuing opportunities in the emerging industries of decarbonization and energy transition. To accomplish our strategy, we have developed the following key priorities:

•Maintain our oil production with a self-funded capital program focused on low-risk, high return investments. The lower base decline of our conventional assets and more efficient capital requirements compared to many of our peers provides us with a significant advantage. We are targeting investing up to approximately 50% of our operating cash flow back into our exploration and production business over the next several years. Our capital allocation priorities focus on enhancing the value of our oil and gas assets while protecting our balance sheet, maintaining mechanical integrity of our infrastructure and sustaining our base oil production. With the premium Brent-based pricing for our oil, we intend to continue our focus on crude oil projects which have a higher return than our natural gas projects.

•Preserve balance sheet strength and return capital to our shareholders. We maintain a robust hedging strategy to help protect our cash flow from operations from volatility in the commodities market. Additionally, we are committed to maintaining low leverage and a strong liquidity position. Over the next several years, we are targeting investing approximately 25% of our operating cash flow for shareholder returns and other strategic opportunities. In 2021, we adopted a dividend policy by which we expect to pay a quarterly dividend of $0.17 per share of our common stock, subject to final quarterly approval by our Board of Directors. We have also adopted a $350 million share repurchase program that is expected to run through December 31, 2022. We have repurchased 4,089,988 shares as of December 31, 2021 at an average price of $36.08 per share.

7

•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 have some of the lowest carbon intensity production among oil and natural gas producers in the United States. We recently announced a Full-Scope Net Zero goal and are seeking 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 Carbon TerraVault. We strive to create a culture of safety and achieved a 99.9997% oil spill prevention rate in 2021 and registered a workforce total recordable incident rate of 0.43 per 100 employees and contractors. As part of our commitment to this priority, our annual incentive compensation metrics for our management team include specific ESG targets for safety, environmental stewardship and sustainability project milestones. For 2022, 30% of our management team's annual incentive related to company performance is tied to ESG related metrics.

•Advancing decarbonization and other emissions reducing projects. Over the next several years, we are targeting investing approximately 25% of our operating cash flows in carbon management projects. These projects include Carbon TerraVault, which is in the early stages of permitting and developing several carbon capture and permanent storage projects in suitable reservoirs. Separately, we are evaluating the feasibility of our CalCapture project which utilizes the Elk Hills power plant as the emissions source for CO2 EOR in our Elk Hills field. We are also pursuing multiple front-of-the-meter and behind-the-meter solar projects.

8

Operations

As of December 31, 2021, our proved reserves totaled an estimated 480 MMBoe, of which 343 MMBbl were crude oil and condensate reserves, 41 MMBbl were NGL reserves and 576 BcF, or 96 MMBoe, were natural gas reserves.

As of December 31, 2021, we held approximately 1.9 million net mineral acres, the largest non-governmental mineral acreage position in California. Our operated asset base spans 99 distinct fields with approximately 10,000 operated wells. We had average net production of approximately 100 MBoe/d (60% oil) for the year ended December 31, 2021. Our average net revenue interest was 85% as of December 31, 2021. From time to time, we will assess our robust portfolio of assets for divestitures.

The following table highlights key information about our operations as of and for the year ended December 31, 2021:

	San Joaquin Basin		Los Angeles Basin		Ventura Basin		Sacramento Basin		Other(a)		Total Operations
Mineral Acreage
Net mineral acreage (thousands)	1,260		30		11		472		118		1,891
Average net mineral acreage held in fee (%)	78	%	45	%	3	%	40	%	97	%	69	%
Number of producing fields we operate	42		5		2		50		—		99
Average net revenue interest (%)(b)	91	%	69	%	85	%	81	%	100	%	85	%
Average drilling rigs(c)	2		—		—		—		—		2
Net wells drilled and completed	109.4		6.5		—		—		—		115.9
Proved reserves
Oil (MMBbl)	203		138		2		—		—		343
NGLs (MMBbl)	41		—		—		—		—		41
Natural gas (Bcf)	481		11		1		83		—		576
Total (MMBoe)	324		140		2		14		—		480
Oil percentage of proved reserves	63	%	99	%	100	%	—	%	—	%	71	%
Production
Total net production (MMBoe)	27		7		1		1		—		36
Average daily net production (MBoe/d)	75		19		3		3		—		100

(a)Reflects retained non-operating interest in the Ventura Basin and nearby areas. Our other interests include unproved locations. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more information on our Ventura Basin divestiture.

(b)The average net revenue interest represents our interest in oil, natural gas and NGL production as a percentage of gross production. Our revenue interest considers royalties and similar burdens and third-party working interests.

(c)We operated three drilling rigs in the San Joaquin basin and one drilling rig in the Los Angeles basin at December 31, 2021.

San Joaquin Basin

The San Joaquin basin contains some of the largest oil fields in the United States based on cumulative production and proved oil and natural gas reserves. Commercial petroleum development 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 one of the largest fields in the continental United States.

9

At Elk Hills we operate efficient natural gas processing facilities, including a state-of-the-art 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 have a large ownership interest in several of the largest existing oil fields in the San Joaquin basin including Buena Vista and Coles Levee. We have also been successfully developing steamfloods in our Kern Front operations.

We believe our extensive 3D seismic library, which covers approximately 800,000 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 and further exploration.

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. The basin contains multiple stacked formations throughout its depths, and we believe that the Los Angeles basin provides a considerable inventory of existing field re-development opportunities as well as new play discovery potential. 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.

Sacramento Basin

The Sacramento basin is a deep, thick sequence of sedimentary deposits of natural gas within an elongated northwest-trending structural feature covering about 7.7 million acres. Exploration and development in the basin began in 1918. 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.

Ventura Basin

During the fourth quarter of 2021, we divested a vast majority of our assets in the Ventura basin. Other than a de minimis non-operated asset, our remaining Ventura basin assets are expected to be sold in the first half of 2022.

Other

Other than the basins described above, we also have mineral interests in undeveloped acreage throughout California including in the Salinas basin and the Santa Maria basin.

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Mineral Acreage

The following table summarizes our gross and net developed and undeveloped mineral acreage as of December 31, 2021.

	San Joaquin Basin	Los Angeles Basin	Ventura Basin	Sacramento Basin	Other(a)	Total
	(in thousands)
Developed(b)
Gross(c)	462	21	10	267	2	762
Net(d)	422	16	10	250	1	699
Undeveloped(e)
Gross(c)	1,027	17	2	270	144	1,460
Net(d)	838	14	1	222	117	1,192
Total
Gross(c)	1,489	38	12	537	146	2,222
Net(d)	1,260	30	11	472	118	1,891

(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, 2021, 69% of our total net mineral interest position was held in fee and the remainder was leased. Of our leased acreage, approximately 59% 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 72,000 net mineral acres will expire in 2022, 46,000 net mineral acres will expire in 2023 and 34,000 net mineral acres will expire in 2024. These leases represent 13% of our total net undeveloped acreage and 8% of our total net acreage as of December 31, 2021 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.

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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.

For additional information on production and prices, see information set forth in Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Production, Prices and Realizations.

	Successor				Predecessor
	Year Ended December 31,		November 1, 2020 - December 31, 2020		January 1, 2020 - October 31, 2020		Year Ended December 31,
	2021						2019
Average daily production
Oil (MBbl/d)	60		63		70		80
NGLs (MBbl/d)	13		12		13		15
Natural gas (MMcf/d)	159		165		174		197
Total daily production (MBoe/d)(a)	100		103		112		128
Total production (MMBoe)(a)	36		6		34		47
Average realized prices
Oil with hedge ($/Bbl)	$	56.05	$	45.37	$	43.19	$	68.65
Oil without hedge ($/Bbl)	$	70.43	$	45.65	$	41.21	$	64.83
NGLs ($/Bbl)	$	53.62	$	38.00	$	25.70	$	31.71
Natural gas without hedge ($/Mcf)	$	4.22	$	3.21	$	2.11	$	2.87
Average benchmark prices
Brent oil ($/Bbl)	$	70.79	$	47.10	$	42.43	$	64.18
WTI oil ($/Bbl)	$	67.91	$	44.21	$	38.44	$	57.03
NYMEX gas ($/MMBtu)	$	3.61	$	2.86	$	1.95	$	2.67
Operating costs per Boe
Operating costs	$	19.39	$	18.19	$	14.95	$	19.16

(a)See Part II, Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Production, Prices and Realizations for more information on our production activity.

Oil, natural gas and NGL production for our two largest fields are presented in the table below:

	Elk Hills			Wilmington
	2021	2020	2019	2021	2020	2019
Average daily production
Oil (MBbl/d)	17	18	22	16	21	20
NGLs (MBbl/d)	10	10	12	—	—	—
Natural gas (MMcf/d)	81	90	103	—	1	1
Total daily production (MBoe/d)	40	43	51	16	21	20

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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 15% of our total production for the year ended December 31, 2021.

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:

	Successor								Predecessor
	Year ended December 31,				November 1, 2020 - December 31, 2020				January 1, 2020 - October 31, 2020				Year ended December 31,
	2021												2019
	(in millions)		($ per Boe)		(in millions)		($ per Boe)		(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	$	705	$	19.39	$	114	$	18.19	$	511	$	14.95	$	895	$	19.16
Excess costs attributable to PSCs	(66)		$	(1.83)	$	(8)	$	(1.33)	(28)		$	(0.81)	(68)		$	(1.46)
Operating costs, excluding effects of PSCs(a)	$	639	$	17.56	$	106	$	16.86	$	483	$	14.14	$	827	$	17.70

(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.

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Estimated Proved Reserves, Future Net Cash Flows and Drilling Locations

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, 2021. 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 $69.47 per barrel was adjusted for gravity, quality and transportation costs. For natural gas volumes, the average NYMEX gas price of $3.60 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, 2021 were $68.73 per barrel for oil, $52.81 per barrel for NGLs and $3.99 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, 2021
	San Joaquin Basin	Los Angeles Basin	Ventura Basin	Sacramento Basin	Total
Proved developed reserves
Oil (MMBbl)	171	109	2	—	282
NGLs (MMBbl)	38	—	—	—	38
Natural Gas (Bcf)	418	8	1	83	510
Total (MMBoe)(a)	279	110	2	14	405
Proved undeveloped reserves
Oil (MMBbl)	32	29	—	—	61
NGLs (MMBbl)	3	—	—	—	3
Natural Gas (Bcf)	63	3	—	—	66
Total (MMBoe)	45	30	—	—	75
Total proved reserves
Oil (MMBbl)	203	138	2	—	343
NGLs (MMBbl)	41	—	—	—	41
Natural Gas (Bcf)	481	11	1	83	576
Total (MMBoe)	324	140	2	14	480
Reserves to production ratio (years)(b)	12	20	2	14	13

(a)As of December 31, 2021, approximately 22% of proved developed oil reserves, 8% of proved developed NGLs reserves, 16% of proved developed natural gas reserves and, overall, 19% 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, 2021 divided by total production for the year ended December 31, 2021.

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Changes to Proved Reserves

The components of the changes to our proved reserves during the year ended December 31, 2021 were as follows:

	San Joaquin Basin	Los Angeles Basin(a)	Ventura Basin	Sacramento Basin	Total
	(in MMBoe)
Balance at December 31, 2020	317	105	12	8	442
Revisions related to price	30	25	2	7	64
Revisions related to performance	(8)	17	—	—	9
Extensions and discoveries	5	—	—	—	5
Improved recovery	1	—	—	—	1
Acquisitions and divestitures	6	—	(11)	—	(5)
Production	(27)	(7)	(1)	(1)	(36)
Balance at December 31, 2021	324	140	2	14	480

(a)Includes proved reserves related to PSCs of 111 MMBoe and 85 MMBoe at December 31, 2021 and 2020, respectively.

Revisions related to price – We had positive price-related revisions of 64 MMBoe primarily resulting from a higher commodity price environment in 2021 compared to 2020. The net price revision reflects the extended economic lives of our fields, estimated using 2021 SEC pricing, partially offset by our higher operating costs.

Revisions related to performance – We had 9 MMBoe of net positive performance-related revisions which included positive performance-related revisions of 21 MMBoe and negative performance-related revisions of 12 MMBoe. Our positive performance-related revisions of 21 MMBoe primarily related to better-than-expected well performance and addition of proved undeveloped locations due to positive drilling results in certain areas. The positive revision also included proved undeveloped reserves added to our five-year development plan in 2021. Our negative performance-related revisions primarily relate to wells and incremental waterflood response that underperformed forecasts and removal of proved undeveloped locations due to unsuccessful drilling results in certain areas. The majority of these revisions were located in the San Joaquin and Los Angeles basins.

Extensions and discoveries – We added 5 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 11 MMBoe in connection with our Ventura divestiture. We added 6 MMBoe in connection with our acquisition of the working interest in certain wells from Macquarie Infrastructure and Real Assets Inc. (MIRA). See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more information on these transactions.

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Proved Undeveloped Reserves

The total changes to our proved undeveloped reserves during the year ended December 31, 2021 were as follows:

	San Joaquin Basin	Los Angeles Basin	Ventura Basin	Sacramento Basin	Total
	(in MMBoe)
Balance at December 31, 2020	39	19	—	2	60
Revisions related to price	2	(1)	—	—	1
Revisions related to performance	6	13	—	(2)	17
Extensions and discoveries	3	—	—	—	3
Improved recovery	—	—	—	—	—
Transfers to proved developed reserves	(5)	(1)	—	—	(6)
Balance at December 31, 2021	45	30	—	—	75

Revisions related to price – We had 1 MMBoe of net positive price-related revisions. Positive price-related revisions of 2 MMBoe were offset by 1 MMBoe of negative cost recovery barrels in our PSCs.

Revisions related to performance – We had 17 MMBoe of net positive performance-related revision which included 19 MMBoe positive performance-related revisions and negative performance-related revisions of 2 MMBoe. Our positive performance-related revisions of 19 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 2021. 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.

Extensions and discoveries – We added 3 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 6 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 10% of our beginning-of-year proved undeveloped reserves, with an investment of approximately $64 million of drilling and completion capital. We believe we will have sufficient capital to develop all year end 2021 proved undeveloped reserves within five years of their original booking date.

PV-10, Standardized Measure and Reserve Replacement Ratio

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, 2021
	(in millions)
Standardized measure of discounted future net cash flows	$	4,549
Present value of future income taxes discounted at 10%	1,624
PV-10 of cash flows(a)	$	6,173

(a)The average realized prices for estimating our PV-10 of cash flow as of December 31, 2021 were $68.73 per barrel for oil, $52.81 per barrel for NGLs and $3.99 per Mcf for natural gas.

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Reserves Evaluation and Review Process

Our estimates of proved reserves and related discounted future net cash flows as of December 31, 2021 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 2021. 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, 2021, Ryder Scott audited 47% of our total proved reserves. NSAI audited 35% of our total proved reserves.

Our independent reserve engineers examined the assumptions underlying our reserves estimates, adequacy and quality of our work product and estimates of future production rates. They also examined the appropriateness of the methodologies employed to estimate our reserves as well as their categorization, using the definitions set forth by the SEC, and found them to be appropriate. As part of their process, they developed their own independent estimates of reserves for those fields that they audited. When compared on a field-by-field basis, some of our estimates were greater and some were less than the estimates of our independent reserve engineers. Given the inherent uncertainties and judgments in estimating proved reserves, differences between our estimates and those of our independent reserve engineers are to be expected. The aggregate difference between our estimates and those of the independent reserve engineers was less than 10%, which was within the Society of Petroleum Engineers (SPE) acceptable tolerance.

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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, 2021, 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 44 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 primarily responsible for our audit has more than 20 years of petroleum engineering experience, with the majority spent evaluating California properties, and is a registered Professional Engineer in the state of Texas.

Drilling Locations

The table below sets forth our total gross identified drilling locations by basin for our proved undeveloped reserves as of December 31, 2021, excluding injection wells.

	Proved Drilling Locations
San Joaquin Basin	401
Los Angeles Basin	262
Total	663

We use production data and experience gained from our development programs to identify and prioritize our drilling inventory. Drilling locations are included in our reserves only after we have adopted a development plan to drill them within a five-year time frame of the original reserve booking. As a result of rigorous technical evaluation of geologic and engineering data, we can estimate with reasonable certainty that reserves from these locations will be commercially recoverable in accordance with SEC guidelines. Management considers the availability of local infrastructure, drilling support assets, state and local regulations and other factors it deems relevant in determining such locations. Our year-end development plans and associated proved undeveloped reserves are consistent with SEC guidelines for development within five years. We believe we will have sufficient capital to develop all year-end 2021 proved undeveloped reserves within five years of their original booking date.

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Drilling Statistics

The following table sets forth information on our net exploration and development wells drilled and completed during the periods indicated, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. We refer to gross wells as the total number of wells in which interests are owned, including outside operated wells. Net wells represent wells reduced to our fractional interest.

	San Joaquin Basin	Los Angeles Basin	Ventura Basin	Sacramento Basin	Total Net Wells
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
Dry
Exploratory	—	—	—	—	—
Development	—	—	—	—	—
2019
Productive
Exploratory	0.3	—	—	—	0.3
Development	117.5	25.2	2.0	2.4	147.1
Dry
Exploratory	—	—	—	—	—
Development	—	—	—	—	—

The following table sets forth information on our development wells where drilling was either in progress or pending completion as of December 31, 2021.

	San Joaquin Basin	Los Angeles Basin	Ventura Basin	Sacramento Basin	Total Net Wells
Gross	15.0	1.0	—	—	16.0
Net	12.3	1.0	—	—	13.3

Productive Wells

Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce at a reasonable rate of return. Our average working interest in our producing wells was 89% as of December 31, 2021. Wells are categorized based on the primary product they produce.

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The following table sets forth our productive oil and natural gas wells (both producing and capable of production) as of December 31, 2021, excluding wells that have been idle for more than five years:

	As of December 31, 2021
	Productive Oil Wells		Productive Natural Gas Wells
	Gross(a)	Net(b)	Gross(a)	Net(b)
San Joaquin Basin	7,577	6,732	152	141
Los Angeles Basin	1,725	1,635	—	—
Ventura Basin	56	56	—	—
Sacramento Basin	—	—	755	696
Total	9,358	8,423	907	837
Multiple completion wells included in the total above	44	51	8	5

(a)The total number of wells in which interests are owned.

(b)Net wells include wells reduced to our fractional interest.

Exploration Inventory

We have had minimal investment in exploration activity in recent years, and our 2022 capital plan does not allocate any capital towards exploration drilling. Although we do not anticipate exploration drilling in the near term, we do have a portfolio of 65 exploration prospects in the San Joaquin and Sacramento basins that we may pursue in the future. We also have an extensive 3D and 2D seismic library that we use to develop and refine exploration prospects.

Carbon Management Business

In November 2021, our Board of Directors announced a Full Scope Net Zero Goal. As part of this strategy, we intend to pursue CCS projects and believe our existing assets are well positioned to support the development of these projects. In addition, our operations are in close proximity to significant sources of carbon dioxide (CO2) emissions in California.

Through our subsidiary, Carbon TerraVault, we are in the early stages of developing several CCS projects in California. Currently, we have applied for permits for two initial permanent CCS projects at the Elk Hills Field. We are also in discussions with potential emitters to enter into joint venture or other commercial arrangements with respect to Carbon TerraVault. Once completed, we expect that our Carbon TerraVault CCS projects will inject CO2 captured from industrial sources into depleted underground oil and natural gas reservoirs and permanently store CO2 deep underground. Separately, we are also evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant.

While all of these projects are in early stages and we do not consider the financial impact of our carbon sequestration activities to be material to our operating and financial results for the year ended December 31, 2021, 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. For more information about the risks involved in our CCS projects, see Part I, Item 1A – Risk Factors.

Human Capital

Our employees are our most important asset and we strive to provide a safe and healthy workplace, development opportunities and financial rewards so that our employees remain engaged and focused on providing safe, affordable and abundant energy for the communities in California.

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Employee development opportunities are provided to enhance leadership development and expand career opportunities. A copy of our policies are provided to all employees, who also undergo mandatory annual training on the policies. Employer sponsored 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 our employees and those of our suppliers, vendors and joint ventures. We provide our employees industry competitive base wages and incentive compensation opportunities, as well as comprehensive health and retirement benefits; life, disability and accident insurance coverages; and employee assistance and wellness programs to promote financial stability and healthy lifestyles. We promote the health and well-being of our employees by providing these comprehensive health benefits and time off for maternity and parental leave for the adoption or birth of a child, illness and vacation. We also provide options for alternate work schedules, flexible work hours, part-time work options and telecommuting.

As of December 31, 2021, we had approximately 970 employees, all in the United States. 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.

Core Values

We believe our core values of Character, Responsibility and Commitment and our comprehensive business and ethical conduct policies sustain and enhance 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.

Diversity, Equity and Inclusion

Our goal is to foster a strong culture that promotes diversity, equity and inclusion and are committed to advancing women and minorities in our workplace. We believe increasing diversity, equity and inclusion will improve financial performance through better retention rates, higher innovation, and increased productivity. Beginning in 2022, we plan to establish a diversity, equity and inclusion executive council to oversee our initiatives and incorporate a quantitative metric that directly impacts incentive compensation for all of our employees.

As of December 31, 2021, 19% of our employees and 18% of our senior managers were female. Additionally, 38% of our employees and 21% of our senior managers were ethnically diverse. Currently, 33% of our Board of Directors are female.

Employee Safety

Our unwavering commitment to safety and the environment defines how we operate our business. We prepare our workforce to work safely through comprehensive training, on-the-job guidance and tools and safety meetings. Each year, we set a threshold injury and illness incidence rate 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 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. The tightening labor market has not adversely affected our operations and we continue to attract the talent needed to support our operations.

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Marketing Arrangements

Crude Oil – We sell nearly all of our crude oil into the California refining markets. 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 indices that are closely tied to Brent prices. International waterborne-based Brent prices are used 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 markets on a daily basis at average monthly index pricing. 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 enjoy 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 pipeline transportation contract for 6,500 barrels per day of NGLs. 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 local utilities.

Delivery Commitments

We have short-term commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. As of December 31, 2021, we had oil delivery commitments of 52 MBbl/d through March 2022, NGL delivery commitments of 12 MBbl/d through March 2022 and natural gas delivery commitments of 32 MMcf/d through October 2022. 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.

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Hedging

Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. Our Revolving Credit Facility includes covenants that require us to maintain a certain level of hedges over our reasonably anticipated oil production from our proved reserves. We have also entered into incremental hedges above and beyond these requirements for some time periods and will continue to evaluate our hedging strategy based on 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.

We had three customers that individually accounted for at least 10%, and collectively accounted for 51%, of our sales (before the effects of hedging). These purchasers are in the crude oil refining industry. In light of the ongoing energy deficit in California and the strong demand for native crude oil production, we do not believe that the exit of any single customer from the market would have a material adverse effect on our financial condition or results of operations at this time.

Title to Properties

As is customary in the oil and natural gas industry for acquired properties, we initially conduct a high-level review of the title to our properties at the time of acquisition. Individual properties may be subject to ordinary course burdens that we believe do not materially interfere with the use or affect the value of such properties. Burdens on properties may include customary royalty or net profits interests, liens incident to operating agreements and tax obligations or duties under applicable laws, or development and abandonment obligations, among other items. Prior to the commencement of drilling operations on those properties, we typically conduct a more thorough title examination and may perform curative work with respect to significant defects. We generally will not commence drilling operations on a property until we have cured known title defects that are material to the project. For additional information on properties which secure our debt, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt.

Competition

Our competitors are primarily other exploration and production companies that produce oil, natural gas and NGLs. We compete locally against 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 70% of the oil it consumes and virtually all of that arrives from waterborne sources. 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 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. At current commodity price levels, we have experienced modest price increases for materials and services as contracts are renewed. 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 face competition 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.

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Infrastructure

Our infrastructure, including plants and facilities owned by the Wilmington field and used in our operations, is presented below:

Description	Quantity	Unit	Capacity
			San Joaquin Basin	Other Basins	Total
Gas Processing Plants(a)	6	MMcf/d	525	18	543
Power Plants(b)	3	MW	595	48	643
Steam Generators/Plants(c)	>30	MBbl/d	150	—	150
Compressors	>300	MHp	320	21	341
Water Management Systems(c)		MBw/d	1,900	1,980	3,880
Water Softeners(c)	16	MBw/d	125	—	125
Oil and NGL Storage(d)		MBbls	408	195	603
Gathering Systems(e)		Miles			>8,000

(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-megawat cogeneration facility at Elk Hills that provides additional flexibility and reliability to support field operations and a 48-megawatt power generating facility within our Long Beach operations 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 gathering lines 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 gathering systems 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.

Regulation of the Oil and Natural Gas Industry

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

CalGEM is California's primary regulator of the oil and natural gas industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. The Bureau of Land Management (BLM) of the U.S. Department of the Interior exercises similar jurisdiction on federal lands in California, on which CalGEM also asserts jurisdiction over certain activities. Government actions, including the issuance of certain permits or approvals, by state and local agencies or by federal agencies may be subject to environmental reviews, respectively, under the California Environmental Quality Act (CEQA) or the National Environmental Policy Act (NEPA), which may result in delays, imposition of mitigation measures or litigation. CalGEM currently requires an operator to identify the manner in which 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 gas ordinance, which was supported by an Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015. A group of plaintiffs challenged the EIR and on February 25, 2020, a California Court of Appeal issued a ruling that invalidates a portion of the EIR. Kern County circulated and certified a supplementary EIR to address the ruling from the court and, thereafter, resumed issuing local permits relying on the revised Kern County EIR. However, the trial court required that Kern County pause its local permitting system until the trial court has reviewed the supplementary EIR and confirmed that it satisfied the concerns raised by the Court of Appeal. A hearing is scheduled for April 2022. If the Kern County EIR is not reinstated or adequately modified following resolution of the litigation described above, obtaining drilling permits for our operations in areas where we do not have field or project specific CEQA coverage could be delayed or become more costly as a result of compliance with CEQA. We believe that we currently have a sufficient inventory of drilling permits for our anticipated operations; however, we cannot guarantee our ability to timely obtain additional permits in the future.

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The California Legislature has 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. 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 October 2021, CalGEM released for public comment public health regulations, which include expanded land use setbacks of up to 3,200 feet from new wells in new surface locations. The proposed regulation would also require pollution controls for existing wells and facilities within the same 3,200-foot setback area. CalGEM is currently in the process of conducting an economic analysis of the proposed rule. Following this analysis, CalGEM will submit the proposed rule to the Office of Administrative Law and begin an additional process of receiving comments and refinement of the proposal as needed before a final rule can be issued. Litigation regarding any final rulemaking is also expected.

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 approximately 400,000 miles of previously unregulated onshore gas gathering lines 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.

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 gas wells and phase out existing wells over a number of years. These bans do not apply to our operations in unincorporated areas of Los Angeles, 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.

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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.

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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, and 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 gas operators injecting into formations not authorized by EPA, among other measures. The state responded in October 2021 with a proposed compliance plan but, to date, EPA has not yet responded.

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 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 announced that climate change will be 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, called for the reinstatement or issuance of methane emissions standards for new, modified and existing oil and gas facilities 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.

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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 2020, the Governor of California 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.

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 gas facilities. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year. 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;

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•the physical and futures energy commodities market, including financial derivative and hedging activity; and

•prevention of discrimination in natural gas gathering operations in favor of producers or sources of supply.

The federal and state agencies overseeing these regulations have substantial rate-setting and enforcement authority, and violation of the foregoing regulations could expose us to litigation with government authorities, counterparties, special interest groups and others.

International treaties and regulations also affect the marketing or sale of our products. For example, on January 1, 2020, the International Maritime Organization reduced the maximum sulfur content in marine fuels from 3.5% to 0.5% by weight under the International Convention for the Prevention of Pollution from Ships. Under this IMO 2020 rule, ships must either switch to low-sulfur fuels or install scrubbing facilities for emission controls, which may affect the price of and demand for varying grades of crude oil, both internationally and in California.

In addition, mandates or subsidies have been adopted or proposed by the state and certain local governments to require or promote renewable energy or electrification of transportation, appliances and equipment, or prohibit or restrict the use of petroleum products, by our customers or the public. For example, in January 2020, the California Public Utilities Commission (CPUC) commenced a rulemaking to develop a long-term natural gas planning strategy to ensure safe and reliable gas systems at just and reasonable rates during what it describes as a 25-year transition from natural gas-fueled technologies to meet the state's GHG goals. In addition, several municipalities in California enacted ordinances in 2019 that restrict the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect the retail natural gas market of our utility customers and the demand and prices we receive for the natural gas we produce. Several of these ordinances face legal challenges.

Available Information

We make available, free of charge on our website www.crc.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Definitive Proxy Statements and amendments to those reports filed or furnished, if any, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Unless otherwise provided herein, information contained on our website is not part of this report. The SEC maintains an internet site, http://www.sec.gov, that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

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ITEM 1A     RISK FACTORS

Described below are certain risks and uncertainties that could adversely affect our business, financial condition, results of operations or cash flow. These risks are not the only risks we face. Our business could also be affected materially and adversely by other risks and uncertainties that are not currently known to us or that we currently deem to be insignificant.

Summary:

Risks Related to Our 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.

•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 prices for our products.

•Our aspirations, goals and initiatives related to carbon management activities and our Full Scope Net Zero target and our public statements and disclosures regarding them expose us to numerous risks.

•Our ability to establish a large-scale carbon capture and sequestration project is subject to numerous risks and uncertainties. If we are unable to successfully execute our carbon capture and sequestration strategy, it could have a material adverse effect on our business, results of operations and financial condition and our ability to achieve our Full-Scope Net Zero goals.

•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 can involve substantial capital investments. We may be unable to fund these investments 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.

•From time to time we may engage in exploratory drilling, including drilling in new or emerging plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is unsuccessful.

•Our producing properties are located exclusively in California, making us vulnerable to economic and regulatory factors associated with having operations concentrated in this geographic area.

•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 may 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

•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.

•Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations any of which could increase costs, restrict operations and change or delay the implementation of our business plans.

•Concerns about climate change and other air quality issues may prompt governmental action that could materially affect our operations or results.

•Adverse tax law changes may affect our operations.

Risks Related to our Indebtedness

•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.

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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 prices 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.

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;

•technological advances;

•transportation and storage capacity, bottlenecks and costs in producing areas;

•the price, availability and acceptance of alternative energy sources;

•regional market conditions; and

•other matters affecting the supply and demand dynamics for these products.

Lower prices could have adverse effects on our business, financial condition, results of operations and cash flow, including:

•reducing our proved oil and natural gas reserves over time

•limiting our ability to grow or maintain future production

•causing a reduction in our borrowing base under our Revolving Credit Facility, which could affect our liquidity;

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•reducing our 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.

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 COVID-19 pandemic has adversely affected the global economy, and has resulted in, among other things, travel restrictions, business closures and the institution of quarantining and other mandated and self-imposed restrictions on movement. We do not know how long these conditions will last. The severity, magnitude and duration of COVID-19 or another pandemic, the extent of actions that have been or may be taken to contain or treat their impact, and the impacts on the economy generally and oil prices in particular, are uncertain, rapidly changing and hard to predict. This uncertainty could force us to reduce costs, including by decreasing operating expenses and lowering capital expenditures, and such actions could negatively affect future production and our reserves. We may experience labor shortages if our employees are unwilling or unable to come to work because of illness, quarantines, government actions or other restrictions in connection with the pandemic. If our suppliers cannot deliver the materials, supplies and services we need, we may need to suspend operations. In addition, we are exposed to changes in commodity prices which have been and will likely remain volatile. We cannot predict the duration and extent of the pandemic's adverse impact on our operating results.

Additionally, to the extent the COVID-19 pandemic or any resulting worsening of the global business and economic environment adversely affects our business and financial results, it may also have the effect of heightening or exacerbating many of the other risks described in the “Risk Factors” herein.

Our aspirations, goals, and initiatives related to carbon management activities and our Full Scope Net Zero target, and our public statements and disclosures regarding them, expose us to numerous risks.

We have developed, and will continue to develop and set, goals, targets, and other objectives related to sustainability matters, including our Full Scope Net Zero target and our energy transition strategy. Statements related to these goals, targets and objectives reflect our current plans and do not constitute a guarantee that they will be achieved. Our efforts to research, establish, accomplish, and accurately report on these goals, targets, and objectives expose us to numerous operational, reputational, financial, legal, and other risks. Our ability to achieve any stated goal, target, or objective, including with respect to emissions reduction, 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 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.

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Our ability to establish a large scale carbon capture and sequestration project is subject to numerous risks and uncertainties. If we are unable to successfully execute our CCS strategy, it could have a material adverse effect on our business, results of operations and financial condition and our ability to achieve our Full-Scope Net Zero goals.

We have announced a strategy to pursue various carbon emissions reduction efforts, including CCS projects such as Carbon TerraVault. To our knowledge, there are no existing large scale carbon capture projects in California of the type contemplated by Carbon TerraVault or CalCapture. 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:

•Large scale carbon capture is an emerging sector and there are not substantial precedents to gauge the likely range of structures or economic terms that will be necessary to reach agreeable terms.

•The development of a CCS project may require us to enter into long term joint ventures with large carbon emitters and operators of infrastructure for transporting CO2 (or other GHGs) and we may not be able to do so on agreeable terms or at all.

•Not all facilities produce sufficiently large quantities of pure or relatively pure streams of CO2, or have installed equipment to capture such CO2, so as to be usable in one or more of our CCS projects.

•Our CCS projects are expected to have material capital requirements and there is no certainty that we will be able to finance these projects on reasonable terms.

•To the extent CO2 transportation pipelines are not present in proposed project areas, or if they do not extend to one or more of our project sites, we may be required to convert existing pipelines, or build new CO2 pipelines or lateral connections, which will require much larger capital expenditures and may be subject to various environmental and other permitting requirements as well as third party easements that could be difficult to obtain, which may render one or more projects uneconomical or impractical. Additionally, even in areas where such pipelines are in place, our use of them may require reaching agreements on CO2 transportation with operators of the pipelines.

•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 the Internal Revenue Code Section 45Q tax credit (45Q) for carbon sequestration. Recent Internal Revenue Service guidance and regulations on this tax credit are intended to provide increased certainty for the industry by establishing processes and standards to secure geologic storage of CO2. However, additional financial incentives may be required for our CCS projects to be economical. In particular, we anticipate that CCS projects associated with carbon emission reductions for transportation fuels will generate LCFS credits and that these additional credits will improve the economics of CCS projects. If the existing legal requirements for incentives such as 45Q or LCFS are subsequently amended in a manner that such incentives no longer apply or are restricted in application to our projects, we may not be able to successfully achieve an economic return from our CCS business or, alternatively, the construction of operation of applicable projects may be substantially delayed such that one or more projects is unprofitable or otherwise infeasible.

•CCS projects will require storage of CO2 in subterranean reservoirs over long periods of time. If accidental releases or subsurface migration of CO2 from our CCS activities were to occur in the course of operating one or more of our CCS sites, there is the risk of recapture of 45Q tax credits or LCFS credits from us by the government, as well as a risk of trespass or other tort claims related to the accidental release or migration of CO2 beyond the boundaries of any anticipated project’s approved area and potential for fines and penalties for violations of environmental requirements.

•Successful development of CCS projects in the United States require that we comply with what we anticipate will be a stringent regulatory scheme requiring that we obtain certain permits applicable to subsurface injection of CO2 for geologic sequestration. Moreover, as operator of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response. There is no assurance that we will be successful in obtaining permits or adequate levels of financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition, or otherwise.

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•Separately, permitting CCS projects requires obtaining a number of other permits and approvals unrelated to subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility. We cannot guarantee that we will be able to obtain all applicable permits for CCS activities on a timely basis or on favorable terms.

•As CCS and carbon management represent an emerging sector, regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects. To the extent regulatory requirements are imposed, are amended, or more stringently enforced, we may incur additional costs in the pursuit of one or more of our carbon capture projects, which costs may be material or may render any one or more of our projects uneconomical.

•We may not own the pore space at all of our CCS project sites, which may require us to enter into agreements with a group of owners for the real estate covering the extent of the project.

•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, notwithstanding that CO2 emissions are intended to be captured, there may be organized opposition to carbon capture, including our projects, from certain environmental groups.

There can be no assurances that we will successfully develop our CCS projects, including Carbon Terravault and CalCapture, and such failure could have a material adverse effect on our liquidity, financial condition and results of operations. If we are not able to successfully develop these projects, our ability to achieve our 2045 Full-Scope Net Zero goal for Scope 1, 2 and 3 emissions would also be materially and adversely affected.

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.

The exploration and development of oil and natural gas properties depend in part on our analysis of geophysical, geologic, engineering, production and other technical data and processes, including the interpretation of 3D seismic data. This analysis is often inconclusive or subject to varying interpretations. We also bear the risks of equipment failures, accidents, environmental hazards, unusual geological formations or unexpected pressure or irregularities within formations, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes, disappointing drilling results or reservoir performance (including lack of production response to workovers or improved and enhanced recovery efforts) and other associated risks.

Our decisions and ultimate profitability are also affected by commodity prices, the availability of capital, regulatory approvals, available transportation and storage capacity, the political environment and other factors. Our cost of drilling, completing, stimulating, equipping, operating, inspecting, maintaining and abandoning wells is also often uncertain.

Any of the forgoing operational or financial risks could cause actual results to differ materially from the expected payback or cause a well or project to become uneconomic or less profitable than forecast.

We have specifically identified locations for drilling over the next several years, which represent a significant part of our long-term growth strategy. Our actual drilling activities may materially differ from those presently identified. If future drilling results in these projects do not establish sufficient production and reserves to achieve an economic return, we may curtail drilling or development of these projects. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate. We cannot guarantee that our identified drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these drilling locations. In addition, some of our leases could expire if we do not establish production in the leased acreage. The combined net acreage covered by leases expiring in the next three years represented 13% of our total net undeveloped acreage at December 31, 2021.

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Our business involves substantial capital investments, which may include acquisitions, partnerships or joint venture arrangements with other oil and gas exploration and production companies or financial investors. 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.

Our exploration, development and acquisition activities can involve substantial capital investments. We intend to fund our 2022 capital program using cash flow from operations. Accordingly, a reduction in projected operating cash flow could cause us to reduce our future capital investments. In general, the ability to execute our capital plan depends on a number of factors, including:

•the amount of oil, natural gas and NGLs we are able to produce;

•commodity prices;

•regulatory and third-party approvals;

•our ability to timely drill, complete and stimulate wells;

•our ability to secure equipment, services and personnel; and

•the availability under our Revolving Credit Facility and external sources of financing.

Access to future capital may be limited by our lenders, capital markets constraints, activist funds or investors, or poor stock price performance. Because of these and other potential variables, we may be unable to deploy capital in the manner planned, which may negatively impact our production levels and development activities and limit our ability to make acquisitions or enter into partnerships and farmout arrangements.

Unless we make sufficient capital investments and conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our ability to make the necessary long-term capital investments or acquisitions needed to maintain or expand our reserves may be impaired to the extent we have insufficient cash flow from operations or liquidity to fund those activities. Over the long term, a continuing decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing our cash flow from operations and the value of our assets.

From time to time we may engage in exploratory drilling, including drilling in new or emerging plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is unsuccessful.

The risk profile for our exploration drilling locations is higher than for other locations because we have less geologic and production data and drilling history, in particular for those exploration drilling locations in unconventional reservoirs, which are in unproven geologic plays. Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, capital availability, costs, drilling results, regulatory approvals, available transportation capacity and other factors. We may not find commercial amounts of oil or natural gas or the costs of drilling, completing, stimulating and operating wells in these locations may be higher than initially expected. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. In either case, the value of our undeveloped acreage may decline and could be impaired.

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 include local price fluctuations, changes in state or regional laws and regulations affecting our operations 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 and earthquakes. 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.

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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.

We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases, obtaining goods and services and hiring and retaining employees needed to operate and manage our business and marketing natural gas, NGLs or oil. Competitors include multinational oil companies, independent production companies and individual producers and operators. In California, our competitors are few and large, which may limit available acquisition opportunities. Many of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address such competitive factors more effectively than we can or withstand industry downturns more easily than we can.

Our hedging activities limit our ability to realize the full benefits of increases in commodity prices.

We enter into hedges to mitigate our economic exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. Our Revolving Credit Facility also includes covenants that require us to maintain a certain level of hedges and we currently have entered into incremental hedges above these requirements for certain time periods. These hedges expose us to the risk of financial losses depending on commodity price movements and may prevent us from realizing the full benefits of price increases. Our ability to realize the benefits of our hedges also depends in part upon the counterparties to these contracts honoring their financial obligations. If any of our counterparties are unable to perform their obligations in the future, we could be exposed to increased cash flow volatility that could affect our liquidity.

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.

U.S. financial regulations can impact both our level of hedging activity as well as the potential cost of entering into hedges. In particular, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), enacted in 2010, established federal oversight and regulation of the over-the-counter (OTC) derivatives market and entities, like us, that participate in that market. Among other things, the Dodd-Frank Act required the U.S. Commodity Futures Trading Commission to promulgate a range of rules and regulations applicable to OTC derivatives transactions. These regulations can affect both the size of positions that we may enter and the ability or willingness of counterparties to trade opposite us.

In addition, U.S. regulators adopted a final rule in November 2019 implementing a new approach for calculating the exposure amount of derivative contracts under the applicable agencies’ regulatory capital rules, referred to as the standardized approach for counterparty credit risk (SA-CCR). Certain financial institutions are required to comply with the new SA-CCR rules beginning on January 1, 2022. The new rules could significantly increase the capital requirements for some of our hedge counterparties in the OTC derivatives market. These increased capital requirements could result in significant additional costs being passed through to end users like us or reduce the number of participants or products available to us in the OTC derivatives market.

The European Union and other non-U.S. jurisdictions may implement regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may become subject to or otherwise impacted by such regulations, which could also adversely affect our hedging opportunities.

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.

Many uncertainties exist in estimating quantities of proved reserves and related future net cash flows. Our estimates are based on various assumptions that require significant judgment in the evaluation of available information. Our assumptions may ultimately prove to be inaccurate. Additionally, reservoir data may change over time as more information becomes available from development and appraisal activities.

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Our ability to add reserves, other than through acquisitions, depends on the success of improved recovery, extension and discovery projects, each of which depends on reservoir characteristics, technology improvements and oil and natural gas prices, as well as capital and operating costs. Many of these factors are outside management’s control and will affect whether the historical sources of proved reserves additions continue to provide reserves at similar levels.

Generally, lower prices adversely affect the quantity of our reserves as those reserves expected to be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. In addition, a portion of our proved undeveloped reserves may no longer meet the economic producibility criteria under the applicable rules or may be removed due to a lower amount of capital available to develop these projects within the SEC-mandated five-year limit.

In addition, our reserves information represents estimates prepared by internal engineers. Although over 80% of our estimated proved reserve volumes as of December 31, 2021 were audited by our independent petroleum engineers, Ryder Scott and NSAI, we cannot guarantee that the estimates are accurate.

Reserves estimation is a partially subjective process of estimating accumulations of oil and natural gas. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows from those reserves depend upon a number of variables and assumptions, including:

•historical production from the area compared with production from similar areas;

•the quality, quantity and interpretation of available relevant data;

•commodity prices;

•production and operating costs;

•ad valorem, excise and income taxes;

•development costs;

•the effects of government regulations; and

•future workover and facilities costs.

Changes in these variables and assumptions could require us to make significant negative reserves revisions, which could affect our liquidity by reducing the borrowing base under our Revolving Credit Facility. In addition, factors such as the availability of capital, geology, government regulations and permits, the effectiveness of development plans and other factors could affect the source or quantity of future reserves additions.

Risks Related to 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.

In September 2020, Governor Gavin Newsom of California issued an executive order (Order) that seeks to reduce both the demand for and supply of petroleum fuels in the state. The Order establishes several goals and directs several state agencies to take certain actions with respect to reducing emissions of GHGs, including, but not limited to: phasing out the sale of new emissions-producing passenger vehicles, drayage trucks and off-road vehicles by 2035 and, to the extent feasible, medium and heavy duty trucks by 2045; developing strategies for the closure and repurposing of oil and gas facilities in California; and proposing legislation to end the issuance of new hydraulic fracturing permits in the state by 2024.

Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans.

Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products.

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To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, stimulation, operation, inspection, maintenance, transportation, storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and threatened or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection and disposal and water consumption, recycling and reuse. Failure to comply may result in the assessment of administrative, civil and/or criminal fines and penalties, liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or prohibiting certain operations or our access to property, water, minerals or other necessary resources, and may otherwise delay or restrict our operations and cause us to incur substantial costs. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties. Beginning in 2021, CalGEM ceased issuing new well stimulation permits and has slowed the approval of new drill permits even as it continues approving plugging and workovers. In addition, a group of plaintiffs challenged the EIR and on February 25, 2020, a California Court of Appeal issued a ruling that invalidates a portion of the EIR that Kern County had typically relied on to satisfy CEQA in order to issue permits in Kern County. Kern County circulated and certified a supplementary EIR. However, the trial court required that Kern County pause its local permitting system until the trial court has reviewed the supplementary EIR and confirmed that it satisfied the concerns raised by the Court of Appeal. A hearing is scheduled for April 2022. If the Kern County EIR is not reinstated or adequately modified following resolution of the litigation described above, obtaining drilling permits for our operations in areas where we do not have field or project specific CEQA coverage could be delayed or become costly as a result of compliance with CEQA.

While we have a new drill permit inventory and believe we will be able to continue to maintain oil production in 2022, we cannot guarantee that we will indefinitely continue to receive new drill permits in a sufficient number to offset oil production decline.

Changes to elected or appointed officials or their priorities and policies could result in different approaches to the regulation of the oil and natural gas industry. We cannot predict the actions the Governor of California or the California legislature may take with respect to the regulation of our business, the oil and natural gas industry or the state’s economic, fiscal or environmental policies, nor can we predict what actions may be taken at the federal level with respect to health, environmental safety, climate, labor or energy laws, regulations and policies, including those that may directly or indirectly impact our operations.

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Concerns about climate change and other air quality issues may prompt governmental action that could materially affect our operations or results.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions, and regulation of GHGs and other air quality issues, may materially affect our business in many ways, including increasing the costs to provide our products and services and reducing demand for, and consumption of, our products and services, and we may be unable to recover or pass through a significant portion of our costs. In addition, legislative and regulatory responses to such issues at the federal, state and local level may increase our capital and operating costs and render certain wells or projects uneconomic, and potentially lower the value of our reserves and other assets. Both the EPA and California have implemented laws, regulations and policies that seek to reduce GHG emissions. California’s cap-and-trade program operates under a market system and the costs of such allowances per metric ton of GHG emissions are expected to increase in the future as the CARB tightens program requirements and annually increases the minimum state auction price of allowances and reduces the state’s GHG emissions cap. As the foregoing requirements become more stringent, we may be unable to implement them in a cost-effective manner, or at all. In recent years, the regulation of methane emissions from oil and gas facilities has been subject to uncertainty. In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, 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 gas facilities. The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year. Additionally, at the 26th Conference of the Parties of the United Nations Framework Convention on Climate Change (COP26) in Glasgow in November 2021, the United States and the European Union jointly announced the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions" in the energy sector. The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon our operations.

To the extent financial markets view climate change and GHG or other emissions as an increasing financial risk, this could adversely impact our cost of, and access to, capital and the value of our stock and our assets. Current investors in oil and gas companies may elect in the future to shift some or all of their investments into other sectors, and institutional lenders may elect not to provide funding for oil and gas companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (GFANZ) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. The Federal Reserve announced in late 2020 that it has joined the Network for Greening the Financial System (NGFS), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenged most relevant to central banks and supervisory authorities. Although we cannot predict the effects of these actions, such limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the Securities and Exchange Commission announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

We believe, but cannot guarantee, that our local production of oil, NGLs and natural gas will remain essential to meeting California’s energy and feedstock needs for the foreseeable future. We have also established 2030 Sustainability Goals for water recycling, renewables integration, methane emission reduction and carbon capture and sequestration in our life-of-field planning in an attempt to align with the state’s long-term goals and support our ability to continue to efficiently implement federal, state and local laws, regulations and policies, including those relating to air quality and climate, in the future. However, there can be no assurances that we will be able to design, permit, fund and implement such projects in a timely and cost-effective manner or at all, or that we, our customers or end users of our products will be able to satisfy long-term environmental, air quality or climate goals if those are applied as enforceable mandates.

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The adoption and implementation of new or more stringent international, federal, state or local legislation, regulations or policies that impose more stringent standards for GHG or other emissions from our operations or otherwise restrict the areas in which we may produce oil, natural gas, NGLs or electricity or generate GHG or other emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for or the value of our products and services. Additionally, political, litigation and financial risks may result in restricting or canceling oil and natural gas production activities, incurring liability for infrastructure damages or other losses as a result of climate change, or impairing our ability to continue to operate in an economic manner. Moreover, climate change may pose increasing risks of physical impacts to our operations and those of our suppliers, transporters and customers through damage to infrastructure and resources resulting from drought, wildfires, sea level changes, flooding and other natural disasters and other physical disruptions. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.

Adverse tax law changes may affect our operations.

We are subject to taxation by various tax authorities at the federal, state and local levels where we do business. New legislation could be enacted by any of these government authorities that could adversely affect our business. Legislation has been previously proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. However, it is unclear whether any such changes will be enacted and, if enacted, how soon any such changes would be effective. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced demand for our products. The passage of any such legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development or could increase costs and any such changes could have an adverse effect on our financial condition, results of operations and cash flows.

In California, there have been numerous state and local proposals for additional income, sales, excise and property taxes, including additional taxes on oil and natural gas production. Although such proposals targeting our industry have not become law, campaigns by various interest groups could lead to additional future taxes.

Risks Related to our Indebtedness

Our existing and future indebtedness may adversely affect our business and limit our financial flexibility.

As of December 31, 2021, we had $600 million of total long-term debt, and additional borrowing capacity of $367 million under the Revolving Credit Facility (after taking into account $125 million of outstanding letters of credit). The terms of our Revolving Credit Facility and Senior Notes permit us to incur significant additional debt, some of which may be secured. Our level of future indebtedness could affect our operations in several ways, including the following:

•limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•require us to dedicate a portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities due to restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

•increase our vulnerability to downturns and adverse developments in our business and the economy generally;

•limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other expenses, or to refinance existing indebtedness;

•make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

•make us vulnerable to increases in interest rates as our indebtedness under the Revolving Credit Facility varies with prevailing interest rates

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Our ability to satisfy our obligations depends on our future operating performance and on economic, financial, competitive and other factors, many of which are beyond our control. Our business may not generate sufficient cash flow, and future financings may not be available to provide sufficient net proceeds, to meet these obligations or to successfully execute our business strategy.

We may not be able to generate sufficient cash to service all of our indebtedness, and may be forced to take other actions to satisfy the obligations under our indebtedness, which may not be successful.

Our earnings and cash flow could vary significantly from year to year due to the nature of our industry despite our commodity price risk-management activities. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments at that time. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control as discussed in this “Risk Factors” section. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

The lenders under our Revolving Credit Facility could limit our ability to borrow and restrict our use or access to capital.

Our Revolving Credit Facility is an important source of our liquidity. Our ability to borrow under our Revolving Credit Facility is limited by our borrowing base, the size of our lenders’ commitments and our ability to comply with covenants.

The borrowing base under our Revolving Credit Facility is redetermined semi-annually by our lenders who review the value of our reserves and other factors that may be deemed appropriate. Currently, our borrowing base is set at $1.2 billion and the availability under our Revolving Credit Facility is limited by the aggregate elected commitment amount of our lenders, which as of February 1, 2022 was set at $492 million.

A reduction in our borrowing base below the aggregate commitment amount of our lenders would materially and adversely affect our liquidity and may hinder our ability to execute on our business strategy.

Restrictive covenants in our Revolving Credit Facility and the indenture governing our Senior Notes may limit our financial and operating flexibility.

Both our Revolving Credit Facility and the indenture governing our Senior Notes contain certain restrictions, which may have adverse effects on our business, financial condition, cash flows or results of operations, limiting our ability, among other things, to:

•incur additional indebtedness;

•incur additional liens;

•pay dividends or make other distributions;

•make investments, loans or advances;

•sell or discount receivables;

•enter into mergers;

•sell properties;

•enter into or terminate hedge agreements;

•enter into transactions with affiliates;

•maintain gas imbalances;

•enter into take-or-pay contracts or make other prepayments;

•enter into sale and leaseback agreements;

•prepay or modify the terms of junior debt;

•enter into negative pledge agreements;

•enter into production sharing contracts;

•amend our organizational documents; and

•make capital investments.

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The Revolving Credit Agreement also requires us to comply with certain financial maintenance covenants, including a leverage ratio and current ratio.

A breach of any of these restrictive covenants could result in a default under the Revolving Credit Facility and/or the Senior Notes. If a default occurs under the Revolving Credit Facility, the lenders may elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to be immediately due and payable. If we are unable to repay our indebtedness when due or declared due, the lenders under the Revolving Credit Facility will also have the right to proceed against the collateral pledged to them to secure the indebtedness. An event of default under the Senior Notes may cause all outstanding Senior Notes to become due and payable immediately or give the trustee and the holders the right to declare all outstanding Senior Notes to become due and payable immediately.

Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Revolving Credit Facility are at variable rates of interest and expose us to interest rate risk. As such, our results of operations are sensitive to movements in interest rates. There are many economic factors outside our control that have in the past and may, in the future, impact rates of interest including publicly announced indices that underlie the interest obligations related to a certain portion of our debt. Factors that impact interest rates include governmental monetary policies, inflation, economic conditions, changes in unemployment rates, international disorder and instability in domestic and foreign financial markets. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our results of operations would be adversely impacted. Such increases in interest rates could have a material adverse effect on our financial condition and results of operations.

Risks Related to Our Common Stock

Our ability to pay dividends and repurchase shares of our common stock is subject to certain risks.

We have adopted a cash dividend policy which anticipates a total annual dividend of $0.68, payable to shareholders in quarterly increments of $0.17 per share of common stock, subject to board authorization and declaration each quarter. In addition, as of December 31, 2021, we had remaining authorization under our Share Repurchase Program to repurchase up to $102 million of shares of our common stock. Any payment of future dividends or repurchasing shares of our common stock will be at the discretion of our Board of Directors and will depend upon, among other things, our earnings, liquidity, capital requirements, financial condition and other factors deemed relevant. Our Revolving Credit Facility and Senior Notes both limit our ability to pay dividends and repurchase shares of our common stock. In addition, cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. We can provide no assurances that we will continue to pay dividends at the anticipated rate or repurchase shares of our common stock within the authorized amount or at all.

The trading price of our common stock may decline, and you may not be able to resell shares of our common stock at prices equal to or greater than the price you paid or at all.

The trading price of our common stock may decline for many reasons, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. Numerous factors, including those referred to in this “Risk Factors” section could affect our stock price. These factors include, among other things, changes in our results of operations and financial condition; changes in commodity prices; changes in the national and global economic outlook; changes in applicable laws and regulations; variations in our capital plan; changes in financial estimates by securities analysts or ratings agencies; changes in market valuations of comparable companies; and additions or departures of key personnel.

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Future issuances of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public or private offerings. We may also issue additional shares of common stock or convertible securities. As of December 31, 2021, we had 79,299,222 outstanding shares of common stock and 4,296,055 shares of common stock issuable upon exercise of outstanding warrants. We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

There is an increased potential for short sales of our common stock due to the sales of shares issued upon exercise of warrants, which could materially affect the market price of the stock.

Downward pressure on the market price of our common stock that likely will result from sales of our common stock issued in connection with the exercise of warrants could encourage short sales of our common stock by market participants. Generally, short selling means selling a security, contract or commodity not owned by the seller. The seller is committed to eventually purchase the financial instrument previously sold. Short sales are used to capitalize on an expected decline in the security’s price. Such sales of our common stock could have a tendency to depress the price of the stock, which could increase the potential for short sales.

The ownership position of certain of our stockholders limits other stockholders’ ability to influence corporate matters and could affect the price of our common stock.

As of January 31, 2022, four of our shareholders owned at least 10% and collectively approximately 46% of our common stock. As a result, each of these stockholders, or any entity to which such stockholders sell their stock, may be able to exercise significant control over matters requiring stockholder approval. Further, because of this large ownership position, if these stockholders sell their stock, the sales could depress our share price.

General Risk Factors

Increasing attention to ESG matters may adversely impact