California Resources Corp - Quarter Report: 2023 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2023

☐ 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.)

1 World Trade Center, Suite 1500

Long Beach, California 90831

(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 Exchange Act:


Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	CRC	New York Stock Exchange

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 Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☑ No

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

Indicate the number of shares outstanding for each of the issuer's classes of common stock, as of the latest practicable date.

The number of shares of common stock outstanding as of March 31, 2023 was 70,549,158.

California Resources Corporation and Subsidiaries

Table of Contents


	Page
Part I
Item 1	Financial Statements (unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Stockholders' Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to the Condensed Consolidated Financial Statements	8
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
	General	20
	Leadership Changes	20
	Business Environment and Industry Outlook	20
	Regulatory Updates	21
	Production	21
	Prices and Realizations	23
	Statements of Operations Analysis	24
	Liquidity and Capital Resources	27
	Divestitures and Acquisitions	30
	Lawsuits, Claims, Commitments and Contingencies	30
	Critical Accounting Estimates and Significant Accounting and Disclosure Changes	30
	Forward-Looking Statements	31
Item 3	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4	Controls and Procedures	33

Part II
Item 1	Legal Proceedings	34
Item 1A	Risk Factors	34
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 5	Other Disclosures	36
Item 6	Exhibits	37

GLOSSARY AND SELECTED ABBREVIATIONS

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

•ABR - Alternate base rate.

•ASC - Accounting Standards Codification.

•ARO - Asset retirement obligation.

•Bbl - Barrel.

•Bbl/d - Barrels per day.

•Bcf - Billion cubic feet.

•Bcfe - Billion cubic feet of natural gas equivalent using the ratio of one barrel of oil, condensate, or NGLs converted to six thousand cubic feet of natural gas.

•Boe - We convert natural gas volumes to crude oil equivalents using a ratio of six thousand cubic feet (Mcf) to one barrel of crude oil equivalent based on energy content. This is a widely used conversion method in the oil and natural gas industry.

•Boe/d - Barrel of oil equivalent per day.

•Btu - British thermal unit.

•CalGEM - California Geologic Energy Management Division.

•CCS - Carbon capture and storage.

•CDMA - Carbon Dioxide Management Agreement.

•CEQA - California Environmental Quality Act.

•CO2 - Carbon dioxide.

•DAC - Direct air capture.

•DD&A - Depletion, depreciation, and amortization.

•EOR - Enhanced oil recovery.

•EPA - United States Environmental Protection Agency.

•ESG - Environmental, social and governance.

•E&P - Exploration and production.

•Full-Scope Net Zero - Achieving permanent storage of captured or removed carbon emissions in a volume equal to all of our scope 1, 2 and 3 emissions by 2045.

•GAAP - United States Generally Accepted Accounting Principles.

•G&A - General and administrative expenses.

•GHG - Greenhouse gases.

•JV - Joint venture.

•LCFS - Low Carbon Fuel Standard.

•LIBOR - London Interbank Offered Rate.

•MBbl - One thousand barrels of crude oil, condensate or NGLs.

•MBbl/d - One thousand barrels per day.

•MBoe/d - One thousand barrels of oil equivalent per day.

•MBw/d - One thousand barrels of water per day

•Mcf - One thousand cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six thousand cubic feet of natural gas.

•MHp - One thousand horsepower.

•MMBbl - One million barrels of crude oil, condensate or NGLs.

•MMBoe - One million barrels of oil equivalent.

•MMBtu - One million British thermal units.

•MMcf/d - One million cubic feet of natural gas per day.

•MMT - Million metric tons.

•MMTPA - Million metric tons per annum.

•MW - Megawatts of power.

•NGLs - Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products such as ethane, propane, isobutane and normal butane, and natural gasoline.

•NYMEX - The New York Mercantile Exchange.

•OCTG - Oil country tubular goods.

•Oil spill prevention rate - Calculated as total Boe less net barrels lost divided by total Boe.

•OPEC - Organization of the Petroleum Exporting Countries.

•OPEC+ - OPEC together with Russia and certain other producing countries.

•PHMSA - Pipeline and Hazardous Materials Safety Administration.

•Proved developed reserves - Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

•Proved reserves - The estimated quantities of natural gas, NGLs, and oil that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations.

•Proved undeveloped reserves - Proved reserves that are expected to be recovered from new wells on undrilled acreage that are reasonably certain of production when drilled or from existing wells where a relatively major expenditure is required for recompletion.

•PSCs - Production-sharing contracts.

•PV-10 - Non-GAAP financial measure and represents the year-end present value of estimated future cash flows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum and using SEC Prices. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.

•Scope 1 emissions - Our direct emissions.

•Scope 2 emissions - Indirect emissions from energy that we use (e.g., electricity, heat, steam, cooling) that is produced by others.

•Scope 3 emissions - Indirect emissions from upstream and downstream processing and use of our products.

•SDWA - Safe Drinking Water Act.

•SEC - United States Securities and Exchange Commission.

•SEC Prices - The unweighted arithmetic average of the first day-of-the-month price for each month within the year used to determine estimated volumes and cash flows for our proved reserves.

•SOFR - Secured overnight financing rate as administered by the Federal Reserve Bank of New York.

•Standardized measure - The year-end present value of after-tax estimated future cash flows from proved oil and natural gas reserves, less future development and operating costs, discounted at 10% per annum and using SEC Prices. Standardized measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions.

•TRIR - Total Recordable Incident Rate calculated as recordable incidents per 200,000 hours for all workers (employees and contractors).

•Working interest - The right granted to a lessee of a property to explore for and to produce and own oil, natural gas or other minerals in-place. A working interest owner bears the cost of development and operations of the property.

•WTI - West Texas Intermediate.

PART I FINANCIAL INFORMATION

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

As of March 31, 2023 and December 31, 2022

(in millions, except share data)



	March 31,		December 31,
	2023		2022
CURRENT ASSETS
Cash and cash equivalents	$	477	$	307
Trade receivables	249		326
Inventories	64		60
Assets held for sale	13		5
Receivable from affiliate	30		33
Other current assets, net	139		133
Total current assets	972		864
PROPERTY, PLANT AND EQUIPMENT	3,266		3,228
Accumulated depreciation, depletion and amortization	(502)		(442)
Total property, plant and equipment, net	2,764		2,786
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY	14		13
DEFERRED TAX ASSET	117		164
OTHER NONCURRENT ASSETS	133		140
TOTAL ASSETS	$	4,000	$	3,967


CURRENT LIABILITIES



Accounts payable	260		345
Liabilities associated with assets held for sale	5		5
Fair value of derivative contracts	154		246
Accrued liabilities	298		298

Total current liabilities	717		894
NONCURRENT LIABILITIES
Long-term debt, net	592		592


Asset retirement obligations	424		432
Other long-term liabilities	175		185



STOCKHOLDERS' EQUITY
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at March 31, 2023 and December 31, 2022	—		—
Common stock (200,000,000 shares authorized at $0.01 par value) (83,429,182 and 83,406,002 shares issued; 70,549,158 and 71,949,742 shares outstanding at March 31, 2023 and December 31, 2022)	1		1
Treasury stock (12,880,024 shares held at cost at March 31, 2023 and 11,456,260 shares held at cost at December 31, 2022)	(520)		(461)
Additional paid-in capital	1,311		1,305
Retained earnings	1,219		938
Accumulated other comprehensive income	81		81


Total stockholders' equity	2,092		1,864
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	4,000	$	3,967

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

For the three months ended March 31, 2023 and 2022

(dollars in millions, except share and per share data)



	Three months ended March 31,
	2023		2022
REVENUES
Oil, natural gas and NGL sales	$	715	$	628
Net gain (loss) from commodity derivatives	42		(562)
Sales of purchased natural gas	184		32
Electricity sales	68		34
Other revenue	15		21
Total operating revenues	1,024		153

OPERATING EXPENSES
Operating costs	254		182
General and administrative expenses	65		48
Depreciation, depletion and amortization	58		49
Asset impairment	3		—
Taxes other than on income	42		34
Exploration expense	1		1
Purchased natural gas expense	124		21
Electricity generation expenses	49		24
Transportation costs	17		12
Accretion expense	12		11
Other operating expenses, net	13		14
Total operating expenses	638		396
Net gain on asset divestitures	7		54

OPERATING INCOME (LOSS)	393		(189)

NON-OPERATING (EXPENSES) INCOME

Interest and debt expense	(14)		(13)

Loss from investment in unconsolidated subsidiary	(2)		—
Other non-operating (expense) income	(1)		1
INCOME (LOSS) BEFORE INCOME TAXES	376		(201)
Income tax (provision) benefit	(75)		26
NET INCOME (LOSS)	$	301	$	(175)






Net income (loss) per share
Basic	$	4.22	$	(2.23)
Diluted	$	4.09	$	(2.23)

Weighted-average common shares outstanding
Basic	71.3		78.5
Diluted	73.5		78.5

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Stockholders' Equity

For the three months ended March 31, 2023 and 2022

(in millions)


	Three months ended March 31, 2023
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, December 31, 2022	$	1	$	(461)	$	1,305	$	938	$	81	$	1,864
Net income	—		—		—		301		—		301

Share-based compensation	—		—		7		—		—		7



Repurchases of common stock	—		(59)		—		—		—		(59)

Cash dividend ($0.2825 per share)	—		—		—		(20)		—		(20)
Shares cancelled for taxes	—		—		(1)		—		—		(1)
Balance, March 31, 2023	$	1	$	(520)	$	1,311	$	1,219	$	81	$	2,092


	Three months ended March 31, 2022
	Common Stock		Treasury Stock		Additional Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Income		Total Equity
Balance, December 31, 2021	$	1	$	(148)	$	1,288	$	475	$	72	$	1,688
Net loss	—		—		—		(175)		—		(175)



Share-based compensation	—		—		5		—		—		5



Repurchases of common stock	—		(71)		—		—		—		(71)


Cash dividend ($0.17 per share)	—		—		—		(14)		—		(14)

Balance, March 31, 2022	$	1	$	(219)	$	1,293	$	286	$	72	$	1,433

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

For the three months ended March 31, 2023 and 2022

(in millions)



	Three months ended March 31,
	2023		2022
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss)	$	301	$	(175)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	58		49
Deferred income tax provision (benefit)	47		(33)
Asset impairment	3		—
Net (gain) loss from commodity derivatives	(42)		562
Net payments on settled commodity derivatives	(65)		(181)


Net gain on asset divestitures	(7)		(54)



Other non-cash charges to income, net	21		8
Changes in operating assets and liabilities, net	(6)		(16)
Net cash provided by operating activities	310		160

CASH FLOW FROM INVESTING ACTIVITIES
Capital investments	(47)		(99)
Changes in accrued capital investments	(13)		3
Proceeds from asset divestitures, net	—		60
Acquisitions	—		(17)


Other	(1)		—
Net cash used in investing activities	(61)		(53)

CASH FLOW FROM FINANCING ACTIVITIES













Repurchases of common stock	(59)		(71)
Common stock dividends	(20)		(13)




Issuance of common stock	1		—
Shares cancelled for taxes	(1)		—
Net cash used in financing activities	(79)		(84)
Increase in cash and cash equivalents	170		23
Cash and cash equivalents—beginning of period	307		305
Cash and cash equivalents—end of period	$	477	$	328

The accompanying notes are an integral part of these condensed consolidated financial statements.

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

March 31, 2023

NOTE 1 BASIS OF PRESENTATION

We are an independent energy and carbon management company committed to energy transition. We produce some of the lowest carbon intensity oil in the United States and are focused on maximizing the value of our land, minerals and technical resources for decarbonization efforts. We are in the early stages of developing several carbon capture and storage (CCS) projects in California and other emissions reducing projects. Our subsidiary Carbon TerraVault is expected to build, install, operate and maintain CO2 capture equipment, transportation assets and storage facilities in California. In August 2022, Carbon TerraVault entered into a joint venture with BGTF Sierra Aggregator LLC (Brookfield) to pursue certain of these opportunities (Carbon TerraVault JV). See Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV. Separately, we are evaluating the feasibility of a carbon capture system to be located at our Elk Hills power plant.

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 subsidiaries.

In the opinion of our management, the accompanying unaudited financial statements contain all adjustments necessary to fairly present our financial position, results of operations, comprehensive income, equity and cash flows for all periods presented. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas producing activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our condensed consolidated financial statements. In applying the equity method of accounting for variable interest entities that we do not control, the investment is initially recognized at cost and then adjusted for our proportionate share of income or loss, contributions and distributions.

We have prepared this report in accordance with generally accepted accounting principles (GAAP) in the United States and the rules and regulations of the U.S. Securities and Exchange Commission applicable to interim financial information which permit the omission of certain disclosures to the extent they have not changed materially since the latest annual financial statements. We believe our disclosures are adequate to make the information presented not misleading.

The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting policies and make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Actual results could differ. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of our condensed consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in our Annual Report on Form 10-K for the year ended December 31, 2022 (2022 Annual Report).

The carrying amounts of cash, cash equivalents and on-balance sheet financial instruments, other than debt, approximate fair value. Refer to Note 3 Debt for the fair value of our debt.

NOTE 2 INVESTMENT IN UNCONSOLIDATED SUBSIDIARY AND RELATED PARTY TRANSACTIONS

In August 2022, our wholly-owned subsidiary Carbon TerraVault I, LLC entered into a joint venture with Brookfield for the further development of a carbon management business in California. We hold a 51% interest in the Carbon TerraVault JV and Brookfield holds a 49% interest. We determined that the Carbon TerraVault JV is a VIE; however, we share decision-making power with Brookfield on all matters that most significantly impact the economic performance of the joint venture. Therefore, we account for our investment in the Carbon TerraVault JV under the equity method of accounting. Transactions between us and the Carbon TerraVault JV are related party transactions.

Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved through the Carbon TerraVault JV. As part of the formation of the Carbon TerraVault JV, we contributed rights to inject CO2 into the 26R reservoir in our Elk Hills field for permanent CO2 storage (26R reservoir) and Brookfield committed to make an initial investment of $137 million, payable in three equal installments with the last two installments subject to the achievement of certain milestones. Brookfield contributed the first $46 million installment of their initial investment to the Carbon TerraVault JV in 2022. This amount may, at our sole discretion, be distributed to us or used to satisfy future capital contributions, among other items. During 2022, $12 million was distributed to us (and used to pay transaction costs related to the formation of the joint venture) and $2 million was used to satisfy a capital call. During 2023, $2 million was used to satisfy a capital call. The remaining amount of the initial contribution by Brookfield available to us was reported as a receivable from affiliate on our condensed consolidated balance sheet. Because the parties have certain put and call rights (repurchase features) with respect to the 26R reservoir if certain milestones are not met, the initial investment by Brookfield is reflected as a contingent liability in other long-term liabilities on our condensed consolidated balance.

We entered into a Management Services Agreement (MSA) with the Carbon TerraVault JV whereby we provide administrative, operational and commercial services under a cost-plus arrangement. Services may be supplemented by using third parties and payments to us under the MSA are limited to the amount in an approved budget. The MSA may be terminated by mutual agreement of the parties, among other events.

The tables below present the summarized financial information related to our equity method investment and related party transactions for the periods presented.



	March 31,		December 31,
	2023		2022
	(in millions)
Investment in unconsolidated subsidiary(a)	$	14	$	13
Receivable from affiliate(b)	$	30	$	33
Property, plant and equipment(c)	$	1	$	—
Contingent liability related to Carbon TerraVault JV put and call rights(d)	$	49	$	48

(a)Reflects our investment less losses allocated to us of $2 million and $1 million for the three months ended March 31, 2023 and the year ended December 31, 2022, respectively.

(b)At March 31, 2023, the amount of $30 million includes $29 million which may be distributed to us or used to satisfy future capital calls and $1 million related to the MSA and vendor reimbursements. At December 31, 2022, the amount of $33 million includes $32 million which may be distributed to us or used to satisfy future capital calls and $1 million related to the MSA and vendor reimbursements.

(c)This amount includes the reimbursement for plugging and abandonment activities at the 26R reservoir.

(d)These amounts were included in other long-term liabilities on our condensed consolidated balance sheet. Our obligation includes $3 million and $2 million of accrued interest at March 31, 2023 and December 31, 2022, respectively, that we would be required to pay should Brookfield exercise its put right.


	Three months ended March 31,
	2023		2022
	(in millions)
Loss from investment in unconsolidated subsidiary	$	(2)	$	—
General and administrative expense(a)	$	1	$	—

(a)Includes amounts recognized by us under the MSA for administrative, operational and commercial services.

The Carbon TerraVault JV has an option to participate in certain projects that involve the capture, transportation and storage of CO2 in California. This option expires upon the earlier of (1) August 2027, (2) when a final investment decision has been approved by the Carbon TerraVault JV for storage projects representing in excess of 5 million metric tons per annum (MMTPA) in the aggregate, or (3) when Brookfield has made contributions to the joint venture in excess of $500 million (unless Brookfield elects to increase its commitment).

NOTE 3 DEBT

As of March 31, 2023 and December 31, 2022, our long-term debt consisted of the following:



	March 31,		December 31,
	2023		2022		Interest Rate	Maturity
	(in millions)

Revolving Credit Facility	$	—	$	—	SOFR plus 3%-4% ABR plus 2%-3%	April 29, 2024

Senior Notes	600		600		7.125%	February 1, 2026
Principal amount	$	600	$	600
Unamortized debt issuance costs	(8)		(8)
Long-term debt, net	$	592	$	592

On October 27, 2020, we entered into a Credit Agreement with Citibank, N.A., as administrative agent, and certain other lenders. As of March 31, 2023, this credit agreement consisted of a senior revolving loan facility (Revolving Credit Facility) with an aggregate commitment of $602 million. Our Revolving Credit Facility also included a sub-limit of $200 million for the issuance of letters of credit as of March 31, 2023. Letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

The borrowing base is redetermined semi-annually and was reaffirmed at $1.2 billion on April 26, 2023. The borrowing base takes into account the estimated value of our proved reserves, total indebtedness and other relevant factors consistent with customary reserves-based lending criteria. The amount we are able to borrow under our Revolving Credit Facility is limited to the amount of the commitment described above.

At March 31, 2023, we were in compliance with all financial and other debt covenants under our Revolving Credit Facility and Senior Notes. For more information on our Senior Notes, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2022 Annual Report. See Note 14 Subsequent Events for information regarding a recent amendment to our Revolving Credit Facility.

Fair Value

The estimated fair value of our fixed-rate debt at March 31, 2023 and December 31, 2022 was approximately $607 million and $574 million, respectively. We estimate fair value based on prices known from market transactions (using Level 1 inputs on the fair value hierarchy).

NOTE 4 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

We are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief.

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances for these items at March 31, 2023 and December 31, 2022 were not material to our condensed consolidated balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.

In October 2020, Signal Hill Services, Inc. defaulted on its decommissioning obligations associated with two offshore platforms. The Bureau of Safety and Environmental Enforcement (BSEE) determined that former lessees, including our former parent, Occidental Petroleum Corporation (Oxy) with a 37.5% share, are responsible for accrued decommissioning obligations associated with these offshore platforms. Oxy sold its interest in the platforms approximately 30 years ago and it is our understanding that Oxy has not had any connection to the operations since that time and was challenging BSEE's order. Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution Agreement between us and Oxy. In September 2021, we accepted the indemnification claim from Oxy and are challenging the order from BSEE.

NOTE 5 DERIVATIVES

We maintain a commodity hedging program primarily focused on crude oil to help protect our cash flows, margins and capital program from the volatility of commodity prices. We did not have any derivative instruments designated as accounting hedges as of and for the three months ended March 31, 2023 and 2022. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging requirements and program goals.

From time to time, we may enter into derivative contracts on natural gas to either protect our cash flows from commodity price movements or optimize margins for our marketing and trading activities.

Summary of open derivative contracts — We held the following Brent-based crude oil contracts as of March 31, 2023:


	Q2 2023		Q3 2023		Q4 2023		1H 2024		2H 2024
Sold Calls
Barrels per day	17,837		17,363		5,747		2,000		4,000
Weighted-average price per barrel	$	60.00	$	57.06	$	57.06	$	90.53	$	90.53

Swaps
Barrels per day	19,475		17,697		27,094		3,500		1,000
Weighted-average price per barrel	$	70.48	$	69.27	$	70.73	$	78.79	$	77.20

Net Purchased Puts(a)
Barrels per day	17,837		17,363		5,747		5,467		4,000
Weighted-average price per barrel	$	76.25	$	76.25	$	76.25	$	71.80	$	66.25

(a)Purchased puts and sold puts with the same strike price have been presented on a net basis.

The outcomes of the derivative positions are as follows:

•Sold calls – we make settlement payments for prices above the indicated weighted-average price per barrel.

•Swaps – we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel.

•Net purchased puts – we receive settlement payments for prices below the indicated weighted-average price per barrel.

We use combinations of these positions to increase the efficacy of our hedging program and, subject to certain conditions, meet the requirements of our Revolving Credit Facility. The majority of our derivative positions for the remainder of 2023 were entered into subsequent to our emergence from bankruptcy to comply with the hedging requirements of our Revolving Credit Facility that were applicable at the time.

Fair value of derivatives — The following tables present the fair values on a recurring basis (at gross and net) of our outstanding commodity derivatives as of March 31, 2023 and December 31, 2022:


March 31, 2023
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets - Fair value of derivative contracts	$	48	$	(8)	$	40
Other noncurrent assets - Fair value of derivative contracts	10		(7)		3

Liabilities
Current - Fair value of derivative contracts(a)	(162)		8		(154)
Noncurrent - Fair value of derivative contracts	(7)		7		—
	$	(111)	$	—	$	(111)

(a)In addition to our Brent based derivative contracts, we held swaps as of March 31, 2023 for offsetting notional volumes of natural gas to secure a margin for future physical sales of natural gas related to our marketing and trading activities. The fair value of these natural gas hedges was $15 million included in current liabilities at March 31, 2023.


December 31, 2022
Classification	Gross Amounts at Fair Value		Netting		Net Fair Value
Assets	(in millions)
Other current assets - Fair value of derivative contracts	$	51	$	(12)	$	39
Other noncurrent assets - Fair value of derivative contracts	7		—		7

Liabilities
Current - Fair value of derivative contracts(a)	(258)		12		(246)
Noncurrent - Fair value of derivative contracts	—		—		—
	$	(200)	$	—	$	(200)

(a)In addition to our Brent based derivative contracts, we held swaps as of December 31, 2022 for offsetting notional volumes of natural gas to secure a margin for future physical sales of natural gas related to our marketing and trading activities. The fair value of these natural gas hedges was $4 million included in current liabilities at December 31, 2022.

Our derivative contracts are measured at fair value using industry-standard models with various inputs, including quoted forward prices, and are classified as Level 2 in the required fair value hierarchy for the periods presented. We recognized fair value changes on derivative instruments each reporting period in net gain (loss) from commodity derivatives on our condensed consolidated statements of operations for the three months ended March 31, 2023 and 2022. The changes in fair value result from the relationship between our existing positions, volatility, time to expiration, contract prices and the associated forward curves.

NOTE 6 INCOME TAXES

The following table present the components of our total income tax provision and a reconciliation of the U.S. federal statutory rate to our effective tax rate:


	Three months ended March 31,
	2023		2022
	(in millions)
Net income (loss) before income taxes	$	376	$	(201)

Current income tax provision	28		7
Deferred income tax provision (benefit)	47		(33)
Total income tax provision (benefit)	$	75	$	(26)


	Three months ended March 31,
	2023		2022
U.S. federal statutory tax rate	21	%	21	%
State income taxes, net	7		7


Change in the valuation allowance	(8)		(15)

Effective tax rate	20	%	13	%

In the first quarter of 2022, we recognized a valuation allowance of $35 million for a portion of the tax loss on the sale of our Lost Hills assets, the deductibility of which was limited. We recognized the benefit of this tax loss in the first quarter of 2023 by releasing the valuation allowance after we jointly agreed to amend the original tax treatment with the buyer. Realization of our deferred tax assets is subjective and remains dependent on a number of factors including our ability to generate sufficient taxable income in future periods.

NOTE 7 DIVESTITURES AND ACQUISITIONS

Divestitures

Ventura Basin Transactions

In the three months ended March 31, 2022, we recorded a gain of $6 million related to the sale of certain Ventura basin assets. The closing of the sale of our remaining assets in the Ventura basin is subject to final approval from the State Lands Commission, which we expect to receive in the second half of 2023. These remaining assets, consisting of property, plant and equipment and associated asset retirement obligations, are classified as held for sale on our condensed consolidated balance sheets at March 31, 2023 and December 31, 2022. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions in our 2022 Annual Report for additional information on the Ventura basin transactions.

Lost Hills Transaction

During the three months ended March 31, 2022, we sold our 50% non-operated working interest in certain horizons within our Lost Hills field, located in the San Joaquin basin, recognizing a gain of $49 million. We retained an option to capture, transport and store 100% of the CO2 from steam generators across the Lost Hills field for future carbon management projects. We also retained 100% of the deep rights and related seismic data.

Other

During the three months ended March 31, 2023, we sold a non-core asset in exchange for the assumption of plugging and abandonment liabilities recognizing a $7 million gain. During the three months ended March 31, 2022, we sold non-core assets recognizing a $1 million loss.

Acquisitions

During the three months ended March 31, 2022, we acquired properties for carbon management activities for approximately $17 million. We are evaluating the sale of certain unwanted assets that were part of this acquisition and recognized an impairment of $3 million in the first quarter of 2023. The fair value of these assets, using Level 3 inputs in the fair value hierarchy, declined due to market conditions including inflation and rising interest rates. These assets are classified as held for sale as of March 31, 2023 on our condensed consolidated balance sheet.

NOTE 8 STOCKHOLDERS' EQUITY

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.1 billion of our common stock through June 30, 2024. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. The following is a summary of our share repurchases, held as treasury stock for the periods presented:


	Total Number of Shares Purchased	Dollar Value of Shares Purchased		Average Price Paid per Share
	(number of shares)	(in millions)		($ per share)
Three months ended March 31, 2022	1,668,456	$	71	$	42.52
Three months ended March 31, 2023	1,423,764	$	59	$	41.25

Inception of Program (May 2021) through March 31, 2023	12,880,024	$	519	$	40.31

Note: The dollar value of shares purchased does not include commissions and excise taxes on share repurchases.

Dividends

Future cash dividends, and the establishment of record and payment dates, are subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position. See Note 14 Subsequent Events for information on future cash dividends.

Warrants

In October 2020, we reserved an aggregate 4,384,182 shares of our common stock for warrants which are exercisable at $36 per share through October 26, 2024.

As of March 31, 2023, we had outstanding warrants exercisable into 4,295,321 shares of our common stock (subject to adjustments pursuant to the terms of the warrants). During the three months ended March 31, 2023 and 2022, we issued an insignificant amount of shares of our common stock in exchange for warrants.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 11 Stockholders' Equity in our 2022 Annual Report for additional information on the terms of our warrants.

NOTE 9 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the three months ended March 31, 2023 and 2022. Our restricted stock unit (RSU) and performance stock unit (PSU) awards are not considered participating securities since the dividend rights on unvested shares are forfeitable.

For basic EPS, the weighted-average number of common shares outstanding excludes shares underlying our equity-settled awards and warrants. For diluted EPS, the basic shares outstanding are adjusted by adding potential common shares, if dilutive.

The following table presents the calculation of basic and diluted EPS, for the three months ended March 31, 2023 and 2022:



	Three months ended March 31,
	2023		2022
	(in millions, except per-share amounts)
Numerator for Basic and Diluted EPS
Net income (loss)	$	301	$	(175)





Denominator for Basic EPS
Weighted-average shares	71.3		78.5

Potential Common Shares, if dilutive:
Warrants	0.5		—
Restricted Stock Units	0.9		—
Performance Stock Units	0.8		—

Denominator for Diluted EPS
Weighted-average shares	73.5		78.5

EPS
Basic	$	4.22	$	(2.23)
Diluted	$	4.09	$	(2.23)

The following table presents potentially dilutive weighted-average common shares which were excluded from the denominator for diluted EPS in the periods presented:



	Three months ended March 31,
	2023	2022
	(in millions)
Shares issuable upon exercise of warrants	—	4.3

Shares issuable upon settlement of RSUs	—	1.1
Shares issuable upon settlement of PSUs	—	1.0

Total antidilutive shares	—	6.4

NOTE 10 PENSION AND POSTRETIREMENT BENEFIT PLANS

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three months ended March 31, 2023 and 2022:



	Three months ended March 31,				Three months ended March 31,
	2023				2022
	Pension Benefit		Postretirement Benefit		Pension Benefit		Postretirement Benefit
	(in millions)				(in millions)
Service cost - benefits earned during the period	$	—	$	—	$	—	$	1





Amortization of prior service cost credit	—		(1)		—		(1)
Net periodic benefit costs	$	—	$	(1)	$	—	$	—

We did not make contributions to our defined benefit plans during the three months ended March 31, 2023 and do not expect to make any additional contributions during the remainder of the year. During the three months ended March 31, 2022, we made contributions of approximately $1 million to our defined benefit plans.

NOTE 11 REVENUE

We derive most of our revenue from sales of oil, natural gas and NGLs, with the remaining revenue primarily generated from sales of electricity and marketing activities related to storage and managing excess pipeline capacity.

The following table provides disaggregated revenue for sales of produced oil, natural gas and NGLs to customers:



	Three months ended March 31,
	2023		2022
	(in millions)
Oil	$	390	$	486
Natural gas	263		80
NGLs	62		62
Oil, natural gas and NGL sales	$	715	$	628

NOTE 12 SUPPLEMENTAL ACCOUNT BALANCES

Inventories — Materials and supplies, which primarily consist of well equipment and tubular goods used in our oil and natural gas operations, are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods include produced oil and NGLs in storage, which are valued at the lower of cost or net realizable value. Inventories, by category, are as follows:



	March 31,		December 31,
	2023		2022
	(in millions)
Materials and supplies	$	61	$	56
Finished goods	3		4
Inventories	$	64	$	60

Other current assets, net — Other current assets, net includes the following:



	March 31,		December 31,
	2023		2022
	(in millions)
Net amounts due from joint interest partners(a)	$	39	$	39

Fair value of derivative contracts	40		39
Prepaid expenses	16		17
Greenhouse gas allowances	19		—
Natural gas margin deposits	16		16
Income tax receivable	—		10
Other	9		12
Other current assets, net	$	139	$	133

(a)Included in the March 31, 2023 and December 31, 2022 net amounts due from joint interest partners are allowances of $1 million.

Other noncurrent assets — Other noncurrent assets includes the following:



	March 31,		December 31,
	2023		2022
	(in millions)
Operating lease right-of-use assets	$	68	$	73
Deferred financing costs - Revolving Credit Facility	5		6
Emission reduction credits	11		11
Prepaid power plant maintenance	29		28
Fair value of derivative contracts	3		7
Deposits and other	17		15
Other noncurrent assets	$	133	$	140

Accrued liabilities — Accrued liabilities includes the following:


	March 31,		December 31,
	2023		2022
	(in millions)
Accrued employee-related costs	$	40	$	49
Accrued taxes other than on income	38		32
Asset retirement obligations	62		59
Accrued interest	9		19
Operating lease liability	14		18

Premiums due on derivative contracts	49		58
Liability for settlement payments on derivative contracts	23		33
Amounts due under production-sharing contracts	7		—
Income taxes payable	19		1

Other	37		29
Accrued liabilities	$	298	$	298

Other long-term liabilities — Other long-term liabilities includes the following:



	March 31,		December 31,
	2023		2022
	(in millions)
Compensation-related liabilities	$	38	$	36
Postretirement and pension benefit plans	31		33
Operating lease liability	50		52

Premiums due on derivative contracts	—		8
Contingent liability related to Carbon TerraVault JV put and call rights	49		48
Other	7		8
Other long-term liabilities	$	175	$	185

General and administrative expenses — The table below shows G&A expenses for our exploration and production business (in addition to unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business are net of amounts reimbursable to us under the MSA with the Carbon TerraVault JV.


	Three months ended March 31,
	2023		2022
	(in millions)
Exploration and production, corporate and other	$	62	$	47
Carbon management business	3		1
Total general and administrative expenses	$	65	$	48

Other operating expenses, net — The table below shows other operating expenses, net for our exploration and production business (in addition to unallocated corporate overhead and other) separately from our carbon management business. Carbon management expenses includes lease cost for sequestration easements, advocacy, and other startup related costs.


	Three months ended March 31,
	2023		2022
	(in millions)
Exploration and production, corporate and other	$	9	$	14
Carbon management business	4		—
Total other operating expenses, net	$	13	$	14

NOTE 13 SUPPLEMENTAL CASH FLOW INFORMATION

We did not make U.S. federal or state income tax payments during the three months ended March 31, 2023 or the three months ended March 31, 2022.

Interest paid, net of capitalized amounts was $21 million and $22 million for the three months ended March 31, 2023 and 2022, respectively.

Non-cash investing activities in the three months ended March 31, 2023 included $2 million related to a capital call for the Carbon TerraVault JV.

Non-cash financing activities in the three months ended March 31, 2023 included an insignificant amount for dividends accrued for stock-based compensation awards. For the three months ended March 31, 2022 dividends accrued for stock-based compensation awards was $1 million. Non-cash financing activities in the three months ended March 31, 2023 also included $1 million related to an excise tax on share repurchases that we expect will be paid in 2024.

NOTE 14 SUBSEQUENT EVENTS

Amendment to our Revolving Credit Facility

On April 26, 2023, we amended our existing Revolving Credit Facility. The amended Revolving Credit Facility provides for an initial aggregate commitment of $592 million and a borrowing base of $1.2 billion. The amendments included, among other things:

•extending the maturity date to July 31, 2027 (subject to a springing maturity to August 4, 2025 if any of our Senior Notes are outstanding on that date);

•increasing our ability to make certain restricted payments (such as dividends and share repurchases) and certain investments (including in our carbon management business);

•releasing liens on certain assets securing the loans made under the Revolving Credit Facility, including our Elk Hills power plant;

•permitting us to designate the entities that hold certain of our assets, including our Elk Hills power plant, as unrestricted subsidiaries subject to meeting certain conditions;

•extending the period for which we can enter into hedges on our production from 48 months to 60 months; and

•increasing our capacity to issue letters of credit from $200 million to $250 million.

We also amended the interest rates and fees we pay under our Revolving Credit Facility. At our election, borrowings under the amended Revolving Credit Facility may be alternate base rate (ABR) loans or term SOFR loans, plus an applicable margin. ABR loans bear interest at a rate equal to the highest of (i) the federal funds effective rate plus 0.50%, (ii) the administrative agent prime rate and (iii) the one-month SOFR rate plus 1%. Term SOFR loans bear interest at term SOFR, plus an additional 10 basis points per annum credit spread adjustment. The applicable margin is adjusted based on the commitment utilization percentage and will vary from (i) in the case of ABR loans, 1.50% to 2.50% and (ii) in the case of term SOFR loans, 2.50% to 3.50%. We also pay customary fees and expenses. Interest is payable quarterly for ABR loans and at the end of the applicable interest period for term SOFR loans, but not less than quarterly. We also pay a commitment fee on unused capacity ranging from 37.5 to 50 basis points per annum, depending on the percentage of the commitment utilized.

Dividends

On April 28, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record at the close of business on June 1, 2023 and is expected to be paid on June 16, 2023.

Item 2Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an independent energy and carbon management company committed to energy transition. We produce some of the lowest carbon intensity oil in the United States according to a joint report by Ceres and the Clean Air Task Force and are focused on maximizing the value of our land, minerals and technical resources for decarbonization efforts. We are in the early stages of developing several carbon capture and storage (CCS) projects in California and other emissions reducing projects. We intend to pursue some or all of these projects through our Carbon TerraVault JV that we formed with BGTF Sierra Aggregator LLC (Brookfield). While all of these projects are in early stages, 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 carbon management. For more information about the risks involved in our carbon capture projects, see Part I, Item 1A – Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2022 (2022 Annual Report) and for more information on the Carbon TerraVault JV, see Part I, Item 1 – Financial Statements, Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions.

Leadership Changes

On February 24, 2023, we announced that Francisco J. Leon, our current Executive Vice President and Chief Financial Officer, will succeed Mark A. (Mac) McFarland as our President and Chief Executive Officer, and joined our Board of Directors. Mr. McFarland will continue to serve as a non-executive member of our Board of Directors and Chair of the Board of our Carbon TerraVault subsidiary. Manuela (Nelly) Molina has been appointed Executive Vice President and Chief Financial Officer, effective May 8, 2023.

Business Environment and Industry Outlook

Commodity Prices

Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can economically produce over the longer term.

Global oil prices declined in the three months ended March 31, 2023 compared to the three months ended December 31, 2022 due to economic uncertainty and recession concerns amid the banking crisis. Natural gas index prices decreased in the three months ended March 31, 2023 compared to the three months ended December 31, 2022 as a result of generally warmer-than-normal weather across most of North America, the slow pace of storage draw-downs and increased natural gas production in the United States. However, local natural gas prices in California experienced significant volatility resulting in an increase in our average realized prices between these periods as discussed below in Prices and Realizations.

The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:


	Three months ended
	March 31, 2023		December 31, 2022
Brent oil ($/Bbl)	$	82.22	$	88.60
WTI oil ($/Bbl)	$	76.13	$	82.64
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price	$	3.42	$	6.26

Regulatory Updates

CalGEM is California's primary regulator of the oil and natural gas production industry on private and state lands, with additional oversight from the State Lands Commission’s administration of state surface and mineral interests. From time to time we have experienced significant delays with respect to obtaining drilling permits from CalGEM for our operations. A variety of factors outside of our control can lead to such delays. CalGEM has not issued any permits for new production wells to any operators since December 2022. However, other than in the Wilmington Field as described below, CalGEM is generally issuing permits for workovers and plugging and abandonment throughout California, including Kern County.

Commencing in February 2023, CalGEM began returning our applications for permits in the Wilmington Oil Field, including permits for new production wells, workovers and plugging and abandonment operations. CalGEM cited concerns regarding the adequacy of the related environmental impact report for purposes of meeting CEQA requirements. We are working together with the City of Long Beach to address CalGEM’s concerns regarding conducting future re-drills, workover and plugging and abandonment activities. Barring any additional or subsequent changes in our issued permits from CalGEM, our existing permit inventory will allow us to execute our previously announced capital program in the Wilmington Field for 2023.

Production

The following table sets forth our average net production of oil, NGLs and natural gas per day in each of the California oil and natural gas basins in which we operated for the periods presented.


	Three months ended
	March 31, 2023	December 31, 2022
Oil (MBbl/d)
San Joaquin Basin	35	36
Los Angeles Basin	20	19


Total	55	55
NGLs (MBbl/d)
San Joaquin Basin	11	11



Total	11	11
Natural gas (MMcf/d)
San Joaquin Basin	119	129
Los Angeles Basin	1	1

Sacramento Basin	16	17
Total	136	147

Total Net Production (MBoe/d)	89	91

Total daily net production for the three months ended March 31, 2023, compared to the three months ended December 31, 2022 decreased by 2 MBoe/d, or 2% largely due to higher amounts of rain and colder seasonal temperatures than normal in California which increased downtime in our operations. Our production-sharing contracts (PSCs), which are described below, did not have an impact on our net oil production in the three months ended March 31, 2023 compared to the three months ended December 31, 2022.

The following table reconciles our average net production to our average gross production (which includes production from the fields we operate and our share of production from fields operated by others) for the periods presented:


	Three months ended
	March 31, 2023	December 31, 2022
	(MBoe/d)
Total Net Production	89	91
Partners' share under PSC-type contracts	6	6
Working interest and royalty holders' share	7	7
Other	1	1
Total Gross Production	103	105

Production-Sharing Contracts (PSCs)

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. The reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. Operating costs, excluding effects of PSC-type contracts is a non-GAAP measure which adjusts for excess costs attributable to PSC-type contracts for the periods presented in the tables below:


	Three months ended
	March 31, 2023				December 31, 2022
	(in millions)		($ per Boe)		(in millions)		($ per Boe)
Operating costs	$	254	$	31.61	$	199	$	23.86
Excess costs attributable to PSC-type contracts	(18)		$	(2.23)	(16)		$	(1.90)
Operating costs, excluding effects of PSC-type contracts	$	236	$	29.38	$	183	$	21.96

For further information on our production-sharing contracts, see Part I, Item 1 & 2 Business and Properties, Oil and Natural Gas Operations, Production, Price and Cost History in our 2022 Annual Report.

Prices and Realizations

The following tables set forth the average realized prices and price realizations as a percentage of average Brent, WTI and NYMEX indexes for our products for the periods presented:


	Three months ended
	March 31, 2023			December 31, 2022
	Price		Realization	Price		Realization
Oil ($ per Bbl)
Brent	$	82.22		$	88.60

Realized price without derivative settlements	$	78.68	96%	$	87.15	98%
Effects of derivative settlements	(15.64)			(25.82)
Realized price with derivative settlements	$	63.04	77%	$	61.33	69%

WTI	$	76.13		$	82.64

Realized price without derivative settlements	$	78.68	103%	$	87.15	105%
Realized price with derivative settlements	$	63.04	83%	$	61.33	74%

NGLs ($ per Bbl)
Realized price (% of Brent)	$	58.88	72%	$	56.55	64%
Realized price (% of WTI)	$	58.88	77%	$	56.55	68%

Natural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price	$	3.42		$	6.26

Realized price without derivative settlements ($/Mcf)	$	21.56	630%	$	8.73	139%
Effects of derivative settlements	—			(0.22)
Realized price with derivative settlements ($/Mcf)	$	21.56	630%	$	8.51	136%

Oil — Brent prices decreased for the three months ended March 31, 2023 compared to the three months ended December 31, 2022 due to recession concerns across Western economies and disappointment at the pace and scale of the post-COVID-19 reopening in China. Our realizations without derivative settlements also declined to 96% in the three months ended March 31, 2023 compared to 98% in the three months ended December 31, 2022, as a result of lower local posting prices relative to Brent pricing.

NGLs — NGL prices for the three months ended March 31, 2023 increased compared to the three months ended December 31, 2022 as a result of cooler-than-normal weather in California, which led to higher prices for NGL products including propane which is generally used for heating, among other things.

Natural Gas — Our realized price for natural gas increased for the three months ended March 31, 2023 as compared to the three months ended December 31, 2022 due to higher demand as a result of colder weather across the West Coast of the United States. In addition, inventory levels of natural gas in California were lower than typical for this time of year which further contributed to this increase.

Statements of Operations Analysis

Results of Oil and Gas Operations

The following table includes key operating data for our oil and gas operations, excluding certain corporate expenses, on a per Boe basis for the three months ended March 31, 2023 and December 31, 2022. Energy operating costs consist of purchased natural gas used to generate electricity for our operations and steam for our steamfloods, purchased electricity and internal costs to generate electricity used in our operations. Gas processing costs include costs associated with compression, maintenance and other activities needed to run our gas processing facilities at Elk Hills. Non-energy operating costs equal total operating costs less energy operating costs and gas processing costs.


	Three months ended
	March 31, 2023		December 31, 2022
	($ per Boe)
Energy operating costs	$	15.56	$	9.56
Gas processing costs	$	0.62	$	0.48
Non-energy operating costs	$	15.43	$	13.82
Operating costs	$	31.61	$	23.86


Field general and administrative expenses(a)	$	1.49	$	1.32
Field depreciation, depletion and amortization(b)	$	6.72	$	5.27
Field taxes other than on income	$	3.73	$	3.36

a.Excludes unallocated general and administrative expenses.

b.Excludes depreciation, depletion and amortization related to our corporate assets, carbon management assets and our Elk Hills power plant.

Operating costs increased during the three months ended March 31, 2023 compared to the three months ended December 31, 2022 primarily due to higher natural gas prices in California. Lower production volumes also contributed to the increase on a per Boe basis.

Field depreciation, depletion and amortization increased during the three months ended March 31, 2023 compared to the three months ended December 31, 2022 due to a change in our depreciation, depletion and amortization rate for the current year.

Consolidated Results of Operations

Three months ended March 31, 2023 compared to December 31, 2022

The following table presents our operating revenues for the three months ended March 31, 2023 and December 31, 2022:


	Three months ended
	March 31, 2023		December 31, 2022
	(in millions)
Oil, natural gas and NGL sales	$	715	$	617
Net gain (loss) from commodity derivatives	42		(132)
Sales of purchased natural gas	184		94
Electricity sales	68		90
Other revenue	15		13
Total operating revenues	$	1,024	$	682

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $715 million for the three months ended March 31, 2023, which is an increase of $98 million compared to $617 million for the three months ended December 31, 2022. This increase was primarily due to changes in realized prices as shown in the table below, including higher realized prices for natural gas and NGLs partially offset by lower realized prices for oil.


	Oil		NGLs		Natural Gas		Total
	(in millions)
Three months ended December 31, 2022	$	441	$	59	$	117	$	617
Changes in realized prices	(43)		3		172		132
Changes in production	(8)		—		(26)		(34)
Three months ended March 31, 2023	$	390	$	62	$	263	$	715

Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

The effect of cash settlements on our commodity derivative contracts is not included in the table above. Payments on commodity derivatives were $65 million for the three months ended March 31, 2023 compared to payments of $134 million for the three months ended December 31, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $167 million, or 35% compared to the three months ended December 31, 2022.

Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $42 million for the three months ended March 31, 2023 compared to a net loss of $132 million for the three months ended December 31, 2022. The change primarily resulted from non-cash changes in the fair value of our outstanding commodity derivatives from the positions held at the end of each measurement period as well as the relationship between contract prices and the associated forward curves as shown in the table below:


	Three months ended
	March 31, 2023		December 31, 2022
	(in millions)
Non-cash commodity derivative gain	$	107	$	2


Net cash payments on settled commodity derivatives	(65)		(134)

Net gain (loss) from commodity derivatives	$	42	$	(132)

Sales of purchased natural gas — Sales of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Sales of purchased natural gas were $184 million for the three months ended March 31, 2023, an increase of $90 million, or 96% from $94 million during the three months ended December 31, 2022. The increase was primarily the result of higher trading activity and market prices for natural gas. Our natural gas sales net of related purchased natural gas expense were $60 million for the three months ended March 31, 2023 compared to $7 million for the three months ended December 31, 2022.

Electricity sales — Electricity sales decreased by $22 million to $68 million for the three months ended March 31, 2023 compared to $90 million for the three months ended December 31, 2022. The decrease was primarily due to lower power prices in the first quarter of 2023 compared to the fourth quarter of 2022.

The following table presents our operating and non-operating expenses and income for the three months ended March 31, 2023 and December 31, 2022:


	Three months ended
	March 31, 2023		December 31, 2022
	(in millions)
Operating expenses
Energy operating costs	$	125	$	80
Gas processing costs	5		4
Non-energy operating costs	124		115
General and administrative expenses	65		59
Depreciation, depletion and amortization	58		49
Asset impairment	3		—
Taxes other than on income	42		42
Exploration expense	1		1
Purchased natural gas expense	124		87
Electricity generation expenses	49		68
Transportation costs	17		13
Accretion expense	12		11
Other operating expenses, net	13		20
Total operating expenses	638		549
Gain (loss) on asset divestitures	7		(1)
Operating income	393		132

Non-operating (expenses) income

Interest and debt expense	(14)		(14)

Loss from investment in unconsolidated subsidiary	(2)		(1)
Other non-operating (expense) income	(1)		—
Income before income taxes	376		117
Income tax provision	(75)		(34)
Net income	$	301	$	83

Energy operating costs — Energy operating costs for the three months ended March 31, 2023 were $125 million, which was an increase of $45 million, or 56% from $80 million for the three months ended December 31, 2022. This increase includes $38 million for purchased electricity and purchased natural gas, which we use to generate electricity for our operations, and $7 million of purchased natural gas used to generate steam for our steamfloods. Natural gas used in our operations is purchased at first-of-the-month prices, which were higher than average daily prices during the period due to significant volatility in the natural gas market. For more information on our natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs for the three months ended March 31, 2023 were $124 million, which was an increase of $9 million or 8% from $115 million for the three months ended December 31, 2022. This increase was primarily a result of increased downhole maintenance activity from the prior quarter.

General and administrative expenses — General and administrative (G&A) expenses were $65 million for the three months ended March 31, 2023, which was an increase of $6 million from $59 million for the three months ended December 31, 2022. The increase in G&A expenses was primarily attributable to compensation-related expenses including stock-based compensation awards granted in the first quarter of 2023. The table below shows G&A expenses for our exploration and production business (in addition to unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business are net of amounts reimbursable to us under the MSA with the Carbon TerraVault JV.


	Three months ended
	March 31, 2023		December 31, 2022
	(in millions)
Exploration and production, corporate and other	$	62	$	57
Carbon management business	3		2
Total general and administrative expenses	$	65	$	59

Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) increased $9 million to $58 million for the three months ended March 31, 2023 from $49 million for the three months ended December 31, 2022. The increase was primarily due to a change in our DD&A rate for the current year.

Purchased natural gas expense — Purchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased $124 million of natural gas for marketing activities during the three months ended March 31, 2023, which was an increase of $37 million, or 43% from $87 million for the three months ended December 31, 2022. The increase was predominantly the result of higher trading activity levels and natural gas market prices in the three months ended March 31, 2023 compared to the three months ended December 31, 2022. For more information on our natural gas market prices, see Prices and Realizations above.

Electricity generation expenses — Electricity generation expenses for the three months ended March 31, 2023 were $49 million, which was a decrease of $19 million or 28% from $68 million for the three months ended December 31, 2022. This decrease was primarily due to volatility in the prices for natural gas. Natural gas used for electricity generation at our Elk Hills power plant is purchased on a daily basis as opposed to the first-of-the-month prices paid for gas used in our operations. There was significant volatility for natural gas prices in California that led to much lower daily prices than first-of-the-month prices.

Income taxes – The income tax provision for the three months ended March 31, 2023 was $75 million (effective tax rate of 20%), compared to $34 million (effective tax rate of 29%) for the three months ended December 31, 2022. Excluding the effect of the change in valuation allowance, our effective tax rate would be 28% in the three months ended March 31, 2023 compared to 29% in the three months ended December 31, 2022. See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more information on a valuation allowance related to our Lost Hills divestiture.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, cash and cash equivalents and available borrowing capacity under our Revolving Credit Facility. See Part I, Item 1 – Financial Statements, Note 14 Subsequent Events for more information on an April 2023 amendment to our Revolving Credit Facility. We consider our low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining. Our primary uses of operating cash flow for the three months ended March 31, 2023 were for capital investments, repurchases of our common stock and dividends.

The following table summarizes our liquidity:



	March 31, 2023
	(in millions)
Cash and cash equivalents	$	477
Revolving Credit Facility:
Borrowing capacity	602
Outstanding letters of credit	(148)
Availability	$	454

Liquidity	$	931

On April 26, 2023, the borrowing base under our Revolving Credit Facility was reaffirmed at $1.2 billion.

At current commodity prices and based upon our planned 2023 capital program described below, we expect to generate operating cash flow to support and invest in our core assets and preserve financial flexibility. We regularly review our financial position and evaluate whether to (i) adjust our drilling program, (ii) return available cash to shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit Facility and Senior Notes indenture, (iii) advance carbon management activities, or (iv) maintain cash on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.

Cash Flow Analysis

Cash flows from operating activities — For the three months ended March 31, 2023, our operating cash flow increased 94%, or $150 million, to $310 million from $160 million in the same prior period of 2022. The increases in operating cash flow for the three months ended March 31, 2023 primarily relates to higher average realized prices (including the effects of settlements on our commodity derivatives) in 2023 compared to the same prior-year period. This increase was partially offset by lower production volumes in 2023 as compared to the same period in 2022. The increase in our revenue was partially offset by an increase in operating costs primarily related to higher prices for purchased natural gas and electricity used in our operations.

Cash flows used in investing activities — The following table provides a comparative summary of net cash used in investing activities:



	Three months ended March 31,
		2023		2022
		(in millions)
Capital investments		$	(47)	$	(99)
Changes in accrued capital investments		(13)		3
Proceeds from divestitures, net		—		60
Acquisitions		—		(17)


Other		(1)		—
Net cash used in investing activities		$	(61)	$	(53)

Cash flows used in financing activities — The following table provides a comparative summary of net cash used in financing activities:


	Three months ended March 31,
		2023		2022
		(in millions)




Repurchases of common stock		$	(59)	$	(71)
Common stock dividends		(20)		(13)

Issuance of common stock		1		$	—
Shares cancelled for taxes		(1)		$	—
Net cash used in financing activities		$	(79)	$	(84)

2023 Capital Program

Our capital program is dynamic in response to commodity price volatility while focusing on oil production and maximizing our free cash flow. We expect our 2023 capital program to range between $200 and $245 million under current conditions. We expect our capital program related to oil and natural gas development to be focused primarily on executing projects using existing permits outside of Kern County.

The amounts in the table below reflect components of our capital investment for the periods indicated, excluding changes in capital investment accruals:


	2023 Full Year Estimate	Three months ended March 31, 2023
	(in millions)
Oil and natural gas operations	$165 - $195	$	40
Carbon management business	5 - 15	1
Corporate and other	30 - 35	6
Total Capital	$200 - $245	$	47

We recently amended and extended our Revolving Credit Facility as described in Part I, Item 1 – Financial Statements, Note 14 Subsequent Events, and are currently evaluating refinancing options for our Senior Notes, which we expect to provide us with greater operating and financial flexibility to bolster our ongoing shareholder return program. We also intend to pursue financing options for our carbon management business that are separate from the rest of our business.

Derivatives

Significant changes in oil and natural gas prices may have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow, and the inverse applies during periods of rising commodity prices. Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial strength and liquidity by protecting our cash flows. We will continue to evaluate our hedging strategy based on prevailing market prices and conditions.

Unless otherwise indicated, we use the term “hedge” to describe derivative instruments that are designed to achieve our hedging requirements and program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the three months ended March 31, 2023. See Part I, Item 1 – Financial Statements, Note 5 Derivatives for further information on our derivatives and a summary of our open derivative contracts as of March 31, 2023 and Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt in our 2022 Annual Report for information on the hedging requirements included in our Revolving Credit Facility.

Dividends

On February 23, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock and amounted to $20 million in the aggregate. The dividend was payable to shareholders of record at the close of business on March 6, 2023 and was paid on March 16, 2023. On April 28, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record at the close of business on June 1, 2023 and is expected to be paid on June 16, 2023. The actual declaration of future cash dividends, and the establishment of record and payment dates, is subject to final determination by our Board of Directors each quarter after reviewing our financial performance and position.

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.1 billion of our common stock through June 30, 2024. The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market conditions and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. The following is a summary of our share repurchases, held as treasury stock for the periods presented:


	Total Number of Shares Purchased	Dollar Value of Shares Purchased		Average Price Paid per Share
	(number of shares)	(in millions)		($ per share)
Three months ended March 31, 2022	1,668,456	$	71	$	42.52
Three months ended March 31, 2023	1,423,764	$	59	$	41.25

Inception of Program (May 2021) through March 31, 2023	12,880,024	$	519	$	40.31

Note: The dollar value of shares purchased does not include commissions and excise taxes on share repurchases.

Divestitures and Acquisitions

See Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions for information on our transactions during the three months ended March 31, 2023 and 2022.

Lawsuits, Claims, Commitments and Contingencies

We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at March 31, 2023 and December 31, 2022 were not material to our condensed consolidated balance sheets as of such dates. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot be accurately determined.

See Part I, Item 1 – Financial Statements, Note 4 Lawsuits, Claims, Commitments and Contingencies for further information.

Critical Accounting Estimates and Significant Accounting and Disclosure Changes

There have been no changes to our critical accounting estimates, which are summarized in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates of our 2022 Annual Report.

Forward-Looking Statements

This document contains statements that we believe to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than historical facts are forward-looking statements, and include statements regarding our future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives of management for the future. Words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy” or similar expressions are generally intended to identify forward-looking statements. Such forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, or implied by, such statements.

Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:

•fluctuations in commodity prices, including supply and demand considerations for our products and services;

•decisions as to production levels and/or pricing by OPEC or U.S. producers in future periods;

•government policy, war and political conditions and events, including the war in Ukraine and oil sanctions on Russia, Iran and others;

•regulatory actions and changes that affect the oil and gas industry generally and us in particular, including (1) the availability or timing of, or conditions imposed on, permits and approvals necessary for drilling or development activities or our carbon management business; (2) the management of energy, water, land, greenhouse gases (GHGs) or other emissions, (3) the protection of health, safety and the environment, or (4) the transportation, marketing and sale of our products;

•the impact of inflation on future expenses and changes generally in the prices of goods and services;

•changes in business strategy and our capital plan;

•lower-than-expected production or higher-than-expected production decline rates;

•changes to our estimates of reserves and related future cash flows, including changes arising from our inability to develop such reserves in a timely manner, and any inability to replace such reserves;

•the recoverability of resources and unexpected geologic conditions;

•general economic conditions and trends, including conditions in the worldwide financial, trade and credit markets;

•production-sharing contracts' effects on production and operating costs;

•the lack of available equipment, service or labor price inflation;

•limitations on transportation or storage capacity and the need to shut-in wells;

•any failure of risk management;

•results from operations and competition in the industries in which we operate;

•our ability to realize the anticipated benefits from prior or future efforts to reduce costs;

•environmental risks and liability under federal, regional, state, provincial, tribal, local and international environmental laws and regulations (including remedial actions);

• the creditworthiness and performance of our counterparties, including financial institutions, operating partners, CCS project participants and other parties;

•reorganization or restructuring of our operations;

•our ability to claim and utilize tax credits or other incentives in connection with our CCS projects;

•our ability to realize the benefits contemplated by our energy transition strategies and initiatives, including CCS projects and other renewable energy efforts;

•our ability to successfully identify, develop and finance carbon capture and storage projects and other renewable energy efforts, including those in connection with the Carbon TerraVault JV, and our ability to convert our CDMAs to definitive agreements and enter into other offtake agreements;

•our ability to maximize the value of our carbon management business and operate it on a stand alone basis;

•our ability to successfully develop infrastructure projects and enter into third party contracts on contemplated terms;

•uncertainty around the accounting of emissions and our ability to successfully

gather and verify emissions data and other environmental impacts;

•changes to our dividend policy and share repurchase program, and our ability to declare future dividends or repurchase shares under our debt agreements;

•limitations on our financial flexibility due to existing and future debt;

•insufficient cash flow to fund our capital plan and other planned investments and return capital to shareholders;

•changes in interest rates;

•our access to and the terms of credit in commercial banking and capital markets, including our ability to refinance our debt or obtain separate financing for our carbon management business;

•changes in state, federal or international tax rates, including our ability to utilize our net operating loss carryforwards to reduce our income tax obligations;

•effects of hedging transactions;

•the effect of our stock price on costs associated with incentive compensation;

•inability to enter into desirable transactions, including joint ventures, divestitures of oil and natural gas properties and real estate, and acquisitions, and our ability to achieve any expected synergies;

•disruptions due to earthquakes, forest fires, floods, extreme weather events or other natural occurrences, accidents, mechanical failures, power outages, transportation or storage constraints, labor difficulties, cybersecurity breaches or attacks or other catastrophic events;

•pandemics, epidemics, outbreaks, or other public health events, such as the COVID-19 pandemic; and

•other factors discussed in Part I, Item 1A – Risk Factors in our 2022 Annual Report.

We caution you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the filing date, and we undertake no obligation to update this information. This document may also contain information from third party sources. This data may involve a number of assumptions and limitations, and we have not independently verified them and do not warrant the accuracy or completeness of such third-party information.

Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three months ended March 31, 2023, there were no material changes to market risks from the information provided under Item 305 of Regulation S-K included under the caption Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk in the 2022 Annual Report.

Commodity Price Risk

Our financial results are sensitive to fluctuations in oil, NGL and natural gas prices. These commodity price changes also impact the volume changes under our PSC-type contracts. We maintain a commodity hedging program primarily focused on hedging crude oil sales to help protect our cash flows, margins and capital program from the volatility of crude oil prices. As of March 31, 2023, we had net liabilities of $111 million for our derivative commodity positions which are carried at fair value. For more information on our derivative positions as of March 31, 2023, refer to Part I, Item 1 – Financial Statements, Note 5 Derivatives. We have price exposure for natural gas we purchase and use in our business. We used natural gas to generate electricity for our operations and higher natural gas prices will also result in an increase to our electricity costs.

Counterparty Credit Risk

Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. Counterparty credit limits have been established based upon the financial health of our counterparties, and these limits are actively monitored. In the event counterparty credit risk is heightened, we may request collateral and accelerate payment dates. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of March 31, 2023, the majority of our credit exposure was with investment-grade counterparties. We believe exposure to counterparty credit-related losses related to our business at March 31, 2023 was not material and losses associated with counterparty credit risk have been insignificant for all periods presented.

Interest-Rate Risk

Changes in interest rate may affect the amount of interest we pay on our long-term debt. We had no variable-rate debt outstanding as of March 31, 2023. Our Senior Notes bear interest at a fixed rate of 7.125% per annum.

Item 4 Controls and Procedures

Our Chief Executive Officer (acting as both principal executive officer and principal financial officer) supervised and participated in management's evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer (acting as both principal executive officer and principal financial officer) concluded that our disclosure controls and procedures were effective as of March 31, 2023.

There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the three months ended March 31, 2023 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1Legal Proceedings

For additional information regarding legal proceedings, see Item 1 – Financial Statements, Note 4 Lawsuits, Claims, Commitments and Contingencies in the Notes to the Condensed Consolidated Financial Statements included in Part I of this Form 10-Q, Part I, Item 2 – Management's Discussion and Analysis of Financial Condition and Results of Operations, Lawsuits, Claims, Commitments and Contingencies in this Form 10-Q, and Part I, Item 3, Legal Proceedings in our 2022 Annual Report.

Item 1A Risk Factors

We are subject to various risks and uncertainties in the course of our business. A discussion of such risks and uncertainties may be found under the heading Risk Factors in our 2022 Annual Report. Except as set forth below, there were no material changes to those risk factors during the three months ended March 31, 2023.

We may face material delays related to our ability to timely obtain permits necessary for our operations, or be unable to secure such permits on favorable terms or at all as a result of numerous California political, regulatory, and legal developments.

We must obtain various governmental permits to conduct exploration and production activities, as well as other aspects of our operations. Obtaining the necessary governmental permits is often a complex and time-consuming process involving numerous federal, state and local agencies. The duration and success of each permitting effort is contingent upon many variables not within our control. In the context of obtaining permits or approvals, the Company will need to comply with known standards, existing laws (such as CEQA), and regulations that may entail greater or lesser costs and delays depending on the nature of the activity to be permitted and the interpretation of the laws and regulations implemented by the permitting authority.

From time to time we have experienced significant delays with respect to obtaining drilling permits for our operations. A variety of factors outside of our control can lead to such delays. CalGEM has not issued any permits for new production wells to any operators since December 2022.

We have experienced delays obtaining permits as a result of litigation related to the Kern County EIR. On January 26, 2023, an appellate court issued a preliminary order reinstating a suspension of Kern County’s ability to rely on an existing Environmental Impact Report (EIR) to meet the County’s obligations under CEQA in connection with oil and gas permitting. The original suspension was put in place in October 2021 in response to a lawsuit challenging the adequacy of that EIR for CEQA purposes. The county subsequently issued a supplemental EIR and took other steps to address the issues raised by the original lawsuit and in November 2022 a trial court approved the sufficiency of the supplemental EIR and lifted the suspension on Kern County’s reliance on the EIR. The preliminary order of the appellate court referenced above is still pending. While we can and intend to address CEQA compliance for our oil and natural gas permitting process through alternative pathways, this would be a lengthy process and we cannot predict whether we would be able to timely obtain permits using this alternative. As a result of these issues and current lack of permits with respect to our Kern County properties, we do not currently plan to drill and complete any additional wells within Kern County until permitting is resumed in Kern County, which may be later in the 2024 calendar year. However, there is no certainty that we will obtain permits on that timeline or at all, which may further adversely affect our future development plans, proved undeveloped reserves, business, operations, cash flows, financial position, and results of operation. As of December 31, 2022, approximately 71% of our proved undeveloped reserves or 9% of our total proved reserves relate to wells to be drilled in Kern County beginning in 2024 for which we would need to obtain permits.

We have also experienced delays obtaining drilling permits from CalGEM since the passage of Senate Bill No. 1137, which established 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools and businesses open to the public (a “setback zone”). The law became effective January 1, 2023 and CalGEM issued emergency regulations implementing the requirements of the law on January 6, 2023. However, on February 3, 2023, the Secretary of State of California certified voter signatures collected in connection with a referendum for the November 2024 ballot to repeal Senate Bill No. 1137. As a result, any implementation of Senate Bill No. 1137 is stayed until it is put to a vote, although any stay could be delayed if there are legal challenges to the Secretary of State’s certification. In addition, even during the stay, CalGEM could attempt to initiate new rulemaking with respect to setbacks. There is significant uncertainty with respect to the ability to book proved undeveloped reserves and drill within the setback zone established by Senate Bill No. 1137 and, as a result, we have only booked proved undeveloped reserves for which we already have permits within the zone and intend to develop prior to the November 2024 ballot. As of December 31, 2022, changes in our development plans due to Senate Bill No. 1137 reduced the net present value of our proved undeveloped reserves by 24% and our overall proved reserves by 4%. A legislator recently introduced a bill in the California Senate providing for liability for certain adverse health conditions in a setback zone, subject to limited defenses. If the subject bill in its current preliminary form was ultimately passed by both houses of the legislature and enacted, the legislation would further impact our ability to operate in a setback zone and increase our exposure to liability.

In addition, commencing in February 2023, CalGEM began returning our applications for permits in the Wilmington Oil Field, including permits for new production wells, workovers and plugging and abandonment operations. See Part I, Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Regulatory Updates. Recent changes in CalGEM management have further lead to additional permitting delays and uncertainty with respect to our ability to timely obtain permits for our operations.

We cannot guarantee that these issues or new ones that may arise in the future will not continue to delay or otherwise impair our ability to obtain drilling permits. In the past we have generally been able to mitigate permitting risks by building up a reserve of drilling permits for use throughout the year, but as a result of the issues described above we have not been able to build our reserve of approved permits to the same level as we have in the past. If we cannot obtain new drilling permits in a timely manner, we have limited options to meet our drilling plans that may not ultimately be sufficient to achieve our business goals. Accordingly, the failure to obtain certain permits or the adoption of more stringent permitting requirements could have a material adverse effect on our business, operations, properties, results of operations, and our financial condition.

Recent and future actions by the State of California could reduce both the demand for and supply of oil and natural gas within the state and consequently have a material and adverse effect on our business, results of operations and financial condition.

In recent years, the Governor of California, the Legislature and state agencies have taken a series of actions that could materially and adversely affect the state's oil and natural gas sector. On September 16, 2022, the Governor of California signed Senate Bill No. 1137 into law, which establishes 3,200 feet as the minimum distance between new oil and natural gas production wells and certain sensitive receptors such as homes, schools or parks. Senate Bill No. 1137 is currently stayed pending the outcome of the California General Election in November 2024. A legislator recently introduced a bill in the California Senate providing for liability for certain adverse health conditions in a setback zone, subject to limited defenses. If the subject bill in its current preliminary form was ultimately passed by both houses of the legislature and enacted, the legislation would further impact our ability to operate in a setback zone and increase our exposure to liability. For additional information, see Part I, Item 1 and 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities in our 2022 Annual Report.

The trend in California is to impose increasingly stringent restrictions on oil and natural gas activities. We cannot predict what actions the Governor of California, the Legislature or state agencies may take in the future, but we could face increased compliance costs, delays in obtaining the approvals necessary for our operations, exposure to increased liability, or other limitations as a result of future actions by these parties. Moreover, new developments resulting from the current and future actions of these parties could also materially and adversely affect our ability to operate, successfully execute drilling plans, or otherwise develop our reserves. Accordingly, recent and future actions by the Governor of California, the Legislature, and state agencies could materially and adversely affect our business, results of operations, and financial condition.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $1.1 billion of our common stock through June 30, 2024. The repurchases may be affected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, derivative contracts or otherwise in compliance with Rule 10b-18, subject to market and contractual limitations in our debt agreements. The Share Repurchase Program does not obligate us to repurchase any dollar amount or number of shares and our Board of Directors may modify, suspend, or discontinue authorization of the program at any time. Shares repurchased are held as treasury stock.

Our share repurchase activity for the three months ended March 31, 2023 was as follows:


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs(a)
January 1, 2023 - January 31, 2023	467,879	$	44.30	467,879	$	—
February 1, 2023 - February 28, 2023	322,931	$	41.42	322,931	—
March 1, 2023 - March 31, 2023	632,954	$	38.92	632,954	—
Total	1,423,764	$	41.25	1,423,764	$	—

(a)The dollar value of shares that may yet be purchased under the Share Repurchase Program totaled $581 million as of March 31, 2023.

Item 5 Other Disclosures

None.

Item 6 Exhibits


3.1			Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).

3.2			Certificate of Amendment of Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant's Current Report on Form 8-K filed on May 6, 2022 and incorporated herein by reference).

3.3			Certificate of Amendment of Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant's Current Report on Form 8-K filed on May 1, 2023 and incorporated herein by reference).

3.4			Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2 to the Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).

10.1			Employment Agreement by and between Francisco J. Leon and California Resources Corporation, dated February 23, 2023 (filed as Exhibit 10.25 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2023 and incorporated herein by reference).

10.2			2023 Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit Award Term and Conditions (filed as Exhibit 10.26 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2023 and incorporated herein by reference).

10.3			2023 Form of California Resources Corporation 2021 Long Term Incentive Plan Performance Stock Unit Award Term and Conditions (filed as Exhibit 10.27 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2023 and incorporated herein by reference).

10.4			Form of Cash Retention Bonus Agreement (filed as Exhibit 10.28 to the Registrant’s Annual Report on Form 10-K filed on February 24, 2023 and incorporated herein by reference).

10.5*			Amended and Restated Credit Agreement, dated as of April 26 , 2023, by and among California Resources Corporation, as the Borrower, the several lenders from time to time parties thereto and Citibank, N.A., as Administrative Agent, Collateral Agent and an Issuing Bank.

31.1*			Certification of Princip al Executive Officer and Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*			Certifications of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*			Inline XBRL Instance Document.

101.SCH*			Inline XBRL Taxonomy Extension Schema Document.

101.CAL*			Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*			Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*			Inline XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF*			Inline XBRL Taxonomy Extension Definition Linkbase Document.

104			Cover Page Interactive Data File (formatted in inline XBRL and contained in Exhibits 101).

* - Filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


			CALIFORNIA RESOURCES CORPORATION


DATE:	May 2, 2023	/s/ Noelle M. Repetti
		Noelle M. Repetti
		Senior Vice President and Controller
		(Principal Accounting Officer)