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 JuneSeptember 30, 2023
OR
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)
Delaware46-5670947
(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 ClassTrading Symbol(s)Name of Each Exchange on Which Registered
Common StockCRCNew 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 FilerAccelerated FilerNon-Accelerated Filer
Smaller Reporting CompanyEmerging 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 JuneSeptember 30, 2023 was 68,962,220.68,619,851.



California Resources Corporation and Subsidiaries

Table of Contents
Page
Part I 
Item 1Financial Statements (unaudited)
Condensed Consolidated Balance Sheets
Condensed Consolidated Statements of Operations
Condensed Consolidated Statements of Comprehensive (Loss) Income
Condensed Consolidated Statements of Stockholders' Equity
Condensed Consolidated Statements of Cash Flows
Notes to the Condensed Consolidated Financial Statements
Item 2Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
Reorganization
Business Environment and Industry Outlook
Regulatory Updates
Supply Chain Constraints and Inflation
Production
Prices and Realizations
Statements of Operations Analysis
Liquidity and Capital Resources
Divestitures and Acquisitions
Lawsuits, Claims, Commitments and Contingencies
Critical Accounting Estimates and Significant Accounting and Disclosure Changes
Forward-Looking Statements
Item 3Quantitative and Qualitative Disclosures About Market Risk
Item 4Controls and Procedures
Part II
Item 1Legal Proceedings
Item 1ARisk Factors
Item 2Unregistered Sales of Equity Securities and Use of Proceeds
Item 5Other Disclosures
Item 6Exhibits

1


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.
2


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.
3


PART I    FINANCIAL INFORMATION
 

Item 1Financial Statements (unaudited)

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
As of JuneSeptember 30, 2023 and December 31, 2022
(in millions, except share data)

June 30,December 31,September 30,December 31,
20232022 20232022
CURRENT ASSETSCURRENT ASSETS  CURRENT ASSETS  
Cash and cash equivalentsCash and cash equivalents$448 $307 Cash and cash equivalents$479 $307 
Trade receivablesTrade receivables183 326 Trade receivables243 326 
InventoriesInventories69 60 Inventories71 60 
Assets held for saleAssets held for sale13 Assets held for sale13 
Receivable from affiliateReceivable from affiliate29 33 Receivable from affiliate26 33 
Other current assets, netOther current assets, net125 133 Other current assets, net97 133 
Total current assetsTotal current assets867 864 Total current assets929 864 
PROPERTY, PLANT AND EQUIPMENTPROPERTY, PLANT AND EQUIPMENT3,303 3,228 PROPERTY, PLANT AND EQUIPMENT3,336 3,228 
Accumulated depreciation, depletion and amortizationAccumulated depreciation, depletion and amortization(558)(442)Accumulated depreciation, depletion and amortization(614)(442)
Total property, plant and equipment, netTotal property, plant and equipment, net2,745 2,786 Total property, plant and equipment, net2,722 2,786 
INVESTMENT IN UNCONSOLIDATED SUBSIDIARYINVESTMENT IN UNCONSOLIDATED SUBSIDIARY14 13 INVESTMENT IN UNCONSOLIDATED SUBSIDIARY15 13 
DEFERRED TAX ASSET108 164 
DEFERRED INCOME TAXESDEFERRED INCOME TAXES150 164 
OTHER NONCURRENT ASSETSOTHER NONCURRENT ASSETS166 140 OTHER NONCURRENT ASSETS136 140 
TOTAL ASSETSTOTAL ASSETS$3,900 $3,967 TOTAL ASSETS$3,952 $3,967 
CURRENT LIABILITIESCURRENT LIABILITIES  CURRENT LIABILITIES  
Accounts payableAccounts payable206 345 Accounts payable224 345 
Liabilities associated with assets held for saleLiabilities associated with assets held for saleLiabilities associated with assets held for sale
Fair value of commodity derivative contractsFair value of commodity derivative contracts72 246 Fair value of commodity derivative contracts103 246 
Accrued liabilitiesAccrued liabilities299 298 Accrued liabilities362 298 
Total current liabilitiesTotal current liabilities582 894 Total current liabilities694 894 
NONCURRENT LIABILITIESNONCURRENT LIABILITIESNONCURRENT LIABILITIES
Long-term debt, netLong-term debt, net593 592 Long-term debt, net589 592 
Asset retirement obligationsAsset retirement obligations411 432 Asset retirement obligations388 432 
Other long-term liabilitiesOther long-term liabilities204 185 Other long-term liabilities231 185 
STOCKHOLDERS' EQUITYSTOCKHOLDERS' EQUITY  STOCKHOLDERS' EQUITY  
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at June 30, 2023 and December 31, 2022— — 
Common stock (200,000,000 shares authorized at $0.01 par value) (83,460,990 and 83,406,002 shares issued; 68,962,220 and 71,949,742 shares outstanding at June 30, 2023 and December 31, 2022)
Treasury stock (14,498,770 shares held at cost at June 30, 2023 and 11,456,260 shares held at cost at December 31, 2022)(584)(461)
Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at September 30, 2023 and December 31, 2022Preferred stock (20,000,000 shares authorized at $0.01 par value) no shares outstanding at September 30, 2023 and December 31, 2022— — 
Common stock (200,000,000 shares authorized at $0.01 par value) (83,483,766 and 83,406,002 shares issued; 68,619,851 and 71,949,742 shares outstanding at September 30, 2023 and December 31, 2022)Common stock (200,000,000 shares authorized at $0.01 par value) (83,483,766 and 83,406,002 shares issued; 68,619,851 and 71,949,742 shares outstanding at September 30, 2023 and December 31, 2022)
Treasury stock (14,863,915 shares held at cost at September 30, 2023 and 11,456,260 shares held at cost at December 31, 2022)Treasury stock (14,863,915 shares held at cost at September 30, 2023 and 11,456,260 shares held at cost at December 31, 2022)(604)(461)
Additional paid-in capitalAdditional paid-in capital1,317 1,305 Additional paid-in capital1,324 1,305 
Retained earningsRetained earnings1,295 938 Retained earnings1,253 938 
Accumulated other comprehensive incomeAccumulated other comprehensive income81 81 Accumulated other comprehensive income76 81 
Total stockholders' equityTotal stockholders' equity2,110 1,864 Total stockholders' equity2,050 1,864 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITYTOTAL LIABILITIES AND STOCKHOLDERS' EQUITY$3,900 $3,967 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY$3,952 $3,967 



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


4


CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Operations
For the three and sixnine months ended JuneSeptember 30, 2023 and 2022
(dollars in millions, except share and per share data)data; shares in millions)
Three months ended
June 30,
Six months ended
June 30,
Three months ended
September 30,
Nine months ended
September 30,
2023202220232022 2023202220232022
REVENUESREVENUES    REVENUES    
Oil, natural gas and NGL salesOil, natural gas and NGL sales$447 $718 $1,162 $1,346 Oil, natural gas and NGL sales$510 $680 $1,672 $2,026 
Net gain (loss) from commodity derivatives31 (100)73 (662)
Sales of purchased natural gas72 75 256 107 
Net (loss) gain from commodity derivativesNet (loss) gain from commodity derivatives(204)243 (131)(419)
Marketing of purchased natural gasMarketing of purchased natural gas78 113 334 220 
Electricity salesElectricity sales34 49 102 83 Electricity sales67 88 169 171 
Other revenueOther revenue22 26 Other revenue31 27 
Total operating revenuesTotal operating revenues591 747 1,615 900 Total operating revenues460 1,125 2,075 2,025 
OPERATING EXPENSESOPERATING EXPENSES    OPERATING EXPENSES    
Operating costsOperating costs186 190 440 372 Operating costs196 214 636 586 
General and administrative expensesGeneral and administrative expenses71 56 136 104 General and administrative expenses65 59 201 163 
Depreciation, depletion and amortizationDepreciation, depletion and amortization56 50 114 99 Depreciation, depletion and amortization56 50 170 149 
Asset impairmentAsset impairment— Asset impairment— — 
Taxes other than on incomeTaxes other than on income42 42 84 76 Taxes other than on income48 44 132 120 
Exploration expenseExploration expenseExploration expense— 
Purchased natural gas expense27 67 151 88 
Purchased natural gas marketing expensePurchased natural gas marketing expense31 98 182 186 
Electricity generation expensesElectricity generation expenses13 33 62 57 Electricity generation expenses23 42 85 99 
Transportation costsTransportation costs16 12 33 24 Transportation costs16 13 49 37 
Accretion expenseAccretion expense11 11 23 22 Accretion expense12 10 35 32 
Other operating expenses, netOther operating expenses, net21 34 23 Other operating expenses, net28 62 28 
Total operating expensesTotal operating expenses444 473 1,082 869 Total operating expenses475 536 1,557 1,405 
Net gain on asset divestituresNet gain on asset divestitures— 58 Net gain on asset divestitures— 60 
OPERATING INCOME147 278 540 89 
OPERATING (LOSS) INCOMEOPERATING (LOSS) INCOME(15)591 525 680 
NON-OPERATING (EXPENSES) INCOMENON-OPERATING (EXPENSES) INCOMENON-OPERATING (EXPENSES) INCOME
Interest and debt expenseInterest and debt expense(14)(13)(28)(26)Interest and debt expense(15)(13)(43)(39)
Loss from investment in unconsolidated subsidiaryLoss from investment in unconsolidated subsidiary(1)— (3)— Loss from investment in unconsolidated subsidiary(3)— (6)— 
Other non-operating incomeOther non-operating incomeOther non-operating income
INCOME BEFORE INCOME TAXES135 266 511 65 
Income tax provision(38)(76)(113)(50)
NET INCOME$97 $190 $398 $15 
(LOSS) INCOME BEFORE INCOME TAXES(LOSS) INCOME BEFORE INCOME TAXES(30)579 481 644 
Income tax benefit (provision)Income tax benefit (provision)(153)(105)(203)
NET (LOSS) INCOMENET (LOSS) INCOME$(22)$426 $376 $441 
Net income per share
Net (loss) income per shareNet (loss) income per share
BasicBasic$1.39 $2.48 $5.65 $0.19 Basic$(0.32)$5.75 $5.38 $5.77 
DilutedDiluted$1.35 $2.41 $5.47 $0.19 Diluted$(0.32)$5.58 $5.18 $5.62 
Weighted-average common shares outstandingWeighted-average common shares outstandingWeighted-average common shares outstanding
BasicBasic69.7 76.7 70.5 77.6 Basic68.7 74.1 69.9 76.4 
DilutedDiluted71.9 78.8 72.7 79.6 Diluted68.7 76.3 72.6 78.5 

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


5



CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Stockholders' EquityComprehensive (Loss) Income
For the three and sixnine months ended JuneSeptember 30, 2023 and 2022
(in millions)

Three months ended June 30, 2023
 Common StockTreasury StockAdditional Paid-in CapitalRetained EarningsAccumulated Other
Comprehensive
Income
Total
Equity
Balance, March 31, 2023$$(520)$1,311 $1,219 $81 $2,092 
Net income— — — 97 — 97 
Share-based compensation— — — — 
Repurchases of common stock— (64)— — — (64)
Cash dividend ($0.2825 per share)— — — (21)— (21)
Shares cancelled for taxes— — (1)— — (1)
Balance, June 30, 2023$$(584)$1,317 $1,295 $81 $2,110 
Three months ended
September 30,
Nine months ended
September 30,
 2023202220232022
Net (loss) income$(22)$426 $376 $441 
Other comprehensive income:
Amortization of prior service cost credit included in net periodic benefit cost, net of tax(a)
(5)— (5)— 
Comprehensive (loss) income attributable to common stock$(27)$426 $371 $441 

Six months ended June 30, 2023
 Common StockTreasury StockAdditional Paid-in CapitalRetained EarningsAccumulated Other
Comprehensive Income
Total
Equity
Balance, December 31, 2022$$(461)$1,305 $938 $81 $1,864 
Net income— — — 398 — 398 
Share-based compensation— — 14 — — 14 
Repurchases of common stock— (123)— — — (123)
Cash dividend ($0.2825 per share)— — — (41)— (41)
Shares cancelled for taxes(2)— — (2)
Balance, June 30, 2023$$(584)$1,317 $1,295 $81 $2,110 

(a) Amortization of prior service cost credit is net of $2 million in tax for the three and nine months ended September 30, 2023.
The accompanying notes are an integral part of these condensed consolidated financial statements.


6



CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Stockholders' Equity
For the three and sixnine months ended JuneSeptember 30, 20222023
(in millions)

Three months ended June 30, 2022
 Common StockTreasury StockAdditional Paid-in CapitalRetained EarningsAccumulated Other
Comprehensive
Income
Total
Equity
Balance, March 31, 2022$$(219)$1,293 $286 $72 $1,433 
Net income— — — 190 — 190 
Share-based compensation— — — — 
Repurchases of common stock— (96)— — — (96)
Cash dividend ($0.17 per share)— — — (13)— (13)
Balance, June 30, 2022$$(315)$1,296 $463 $72 $1,517 
Three months ended September 30, 2023
 Common StockTreasury StockAdditional Paid-in CapitalRetained EarningsAccumulated Other
Comprehensive
Income
Total
Equity
Balance, June 30, 2023$$(584)$1,317 $1,295 $81 $2,110 
Net loss— — — (22)— (22)
Share-based compensation— — — — 
Repurchases of common stock— (20)— — — (20)
Cash dividend ($0.2825 per share)— — — (20)— (20)
Shares cancelled for taxes— — (1)— — (1)
Other comprehensive income, net of tax— — — — (5)(5)
Balance, September 30, 2023$$(604)$1,324 $1,253 $76 $2,050 

Six months ended June 30, 2022Nine months ended September 30, 2023
Common StockTreasury StockAdditional Paid-in CapitalRetained EarningsAccumulated Other
Comprehensive Income
Total
Equity
Common StockTreasury StockAdditional Paid-in CapitalRetained EarningsAccumulated Other
Comprehensive Income
Total
Equity
Balance, December 31, 2021$$(148)$1,288 $475 $72 $1,688 
Balance, December 31, 2022Balance, December 31, 2022$$(461)$1,305 $938 $81 $1,864 
Net incomeNet income— — — 15 — 15 Net income— — — 376 — 376 
Share-based compensationShare-based compensation— — — — Share-based compensation— — 22 — — 22 
Repurchases of common stockRepurchases of common stock— (167)— — — (167)Repurchases of common stock— (143)— — — (143)
Cash dividend ($0.17 per share)— — — (27)— (27)
Balance, June 30, 2022$$(315)$1,296 $463 $72 $1,517 
Cash dividend ($0.2825 per share)Cash dividend ($0.2825 per share)— — — (61)— (61)
Shares cancelled for taxesShares cancelled for taxes(3)— — (3)
Other comprehensive income, net of taxOther comprehensive income, net of tax— — — — (5)(5)
Balance, September 30, 2023Balance, September 30, 2023$$(604)$1,324 $1,253 $76 $2,050 

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


7



CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Cash FlowsStockholders' Equity
For the three and six ninemonths ended JuneSeptember 30, 2023 and 2022
(in millions)
Three months ended June 30,Six months ended June 30,
 2023202220232022
CASH FLOW FROM OPERATING ACTIVITIES
Net income$97 $190 $398 $15 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization56 50 114 99 
Deferred income tax provision62 56 29 
Asset impairment— 
Net (gain) loss from commodity derivatives(31)100 (73)662 
Net payments on settled commodity derivatives(63)(241)(128)(422)
Net gain on asset divestitures— (4)(7)(58)
Other non-cash charges to income, net30 19 51 27 
Changes in operating assets and liabilities, net10 (13)
Net cash provided by operating activities108 181 418 341 
CASH FLOW FROM INVESTING ACTIVITIES
Capital investments(39)(98)(86)(197)
Changes in accrued capital investments(2)(15)
Proceeds from asset divestitures, net— 16 — 76 
Acquisitions(1)— (1)(17)
Other, net(2)— (3)— 
Net cash used in investing activities(44)(76)(105)(129)
CASH FLOW FROM FINANCING ACTIVITIES
Repurchases of common stock(64)(96)(123)(167)
Common stock dividends(20)(13)(40)(26)
Issuance of common stock— — — 
Debt amendment costs(8)— (8)— 
Shares cancelled for taxes(1)— (2)— 
Net cash used in financing activities(93)(109)(172)(193)
(Decrease) increase in cash and cash equivalents(29)(4)141 19 
Cash and cash equivalents—beginning of period477 328 307 305 
Cash and cash equivalents—end of period$448 $324 $448 $324 

Three months ended September 30, 2022
 Common StockTreasury StockAdditional Paid-in CapitalRetained EarningsAccumulated Other
Comprehensive
Income
Total
Equity
Balance, June 30, 2022$$(315)$1,296 $463 $72 $1,517 
Net income— — — 426 — 426 
Share-based compensation— — — — 
Repurchases of common stock— (80)— — — (80)
Cash dividend ($0.17 per share)— — — (13)— (13)
Other— — (1)— — (1)
Balance, September 30, 2022$$(395)$1,301 $876 $72 $1,855 

Nine months ended September 30, 2022
 Common StockTreasury StockAdditional Paid-in CapitalRetained EarningsAccumulated Other
Comprehensive Income
Total
Equity
Balance, December 31, 2021$$(148)$1,288 $475 $72 $1,688 
Net income— — — 441 — 441 
Share-based compensation— — 14 — — 14 
Repurchases of common stock— (247)— — — (247)
Cash dividend ($0.17 per share)— — — (40)— (40)
Other— — (1)— — (1)
Balance, September 30, 2022$$(395)$1,301 $876 $72 $1,855 

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


8



CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
For the three and nine months ended September 30, 2023 and 2022
(in millions)
Three months ended September 30,Nine months ended September 30,
 2023202220232022
CASH FLOW FROM OPERATING ACTIVITIES
Net (loss) income$(22)$426 $376 $441 
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization56 50 170 149 
Deferred income tax (benefit) provision(40)137 16 166 
Asset impairment— — 
Net loss (gain) from commodity derivatives204 (243)131 419 
Net payments on settled commodity derivatives(95)(182)(223)(604)
Net gain on asset divestitures— (2)(7)(60)
Other non-cash charges to income, net26 15 77 42 
Changes in operating assets and liabilities, net(25)34 (21)21 
Net cash provided by operating activities104 235 522 576 
CASH FLOW FROM INVESTING ACTIVITIES
Capital investments(33)(107)(119)(304)
Changes in accrued capital investments(4)(10)
Proceeds from asset divestitures, net— — 79 
Acquisitions— — (1)(17)
Distribution related to the Carbon TerraVault JV— 12 — 12 
Capitalized joint venture transaction costs— (12)— (12)
Other, net— (1)(3)(1)
Net cash used in investing activities(28)(109)(133)(238)
CASH FLOW FROM FINANCING ACTIVITIES
Repurchases of common stock(20)(80)(143)(247)
Common stock dividends(19)(13)(59)(39)
Issuance of common stock— 
Debt amendment costs— — (8)— 
Shares cancelled for taxes(1)— (3)— 
Debt repurchases(5)— (5)— 
Net cash used in financing activities(45)(92)(217)(285)
Increase in cash and cash equivalents31 34 172 53 
Cash and cash equivalents—beginning of period448 324 307 305 
Cash and cash equivalents—end of period$479 $358 $479 $358 

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


9



CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements
JuneSeptember 30, 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 according to a joint report by Ceres and the Clean Air Task Force and weForce. We are focused on maximizing the value of our land, minerals and technical resources for oil and gas extraction and decarbonization efforts. We are in the early stages of developing several carbon capture and storage (CCS) projects and other emissions reducing projects in California. 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, our investment in an unconsolidated subsidiary (Carbon TerraVault JV HoldCo, LLC) was initially recognized at cost and then adjusted for our proportionate share of income or loss in addition to 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.

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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 variable interest entity (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, we used $4approximately $7 million to satisfy a capital call. The remaining amount of the initial contribution by Brookfield which is 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 included in other long-term liabilities on our condensed consolidated balance sheets.

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.

June 30,December 31,September 30,December 31,
2023202220232022
(in millions)(in millions)
Investment in unconsolidated subsidiary(a)
Investment in unconsolidated subsidiary(a)
$14 $13 
Investment in unconsolidated subsidiary(a)
$15 $13 
Receivable from affiliate(b)
Receivable from affiliate(b)
$29 $33 
Receivable from affiliate(b)
$26 $33 
Property, plant and equipment(c)
Property, plant and equipment(c)
$$— 
Property, plant and equipment(c)
$$— 
Other long-term liabilities - Contingent liability (related to Carbon TerraVault JV put and call rights)(d)
Other long-term liabilities - Contingent liability (related to Carbon TerraVault JV put and call rights)(d)
$50 $48 
Other long-term liabilities - Contingent liability (related to Carbon TerraVault JV put and call rights)(d)
$51 $48 
(a)Reflects our investment less losses allocated to us of $3$6 million and $1 million for the sixnine months ended JuneSeptember 30, 2023 and the year ended December 31, 2022, respectively.
(b)At JuneSeptember 30, 2023, the amount of $29$26 million includes $28$25 million which may be distributedremaining of Brookfield's initial contribution available 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 distributedremaining of Brookfield's initial contribution available 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 to us 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 due to repurchase features related to the 26R reservoir includes $4$5 million and $2 million of accrued interest at JuneSeptember 30, 2023 and December 31, 2022, respectively.

Three months ended June 30,Six months ended June 30,Three months ended September 30,Nine months ended September 30,
20232022202320222023202220232022
(in millions)(in millions)(in millions)(in millions)
Loss from investment in unconsolidated subsidiaryLoss from investment in unconsolidated subsidiary$$— $$— Loss from investment in unconsolidated subsidiary$$— $$— 
General and administrative expenses(a)
General and administrative expenses(a)
$$— $$— 
General and administrative expenses(a)
$$— $$— 
(a)Includes amounts recognizedGeneral and administrative expenses on our condensed consolidated statement of operations are net of this amount invoiced by us under the MSA for administrative,back-office operational and commercial services.

1011



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 JuneSeptember 30, 2023 and December 31, 2022, our long-term debt consisted of the following:

June 30,December 31,September 30,December 31,
20232022Interest RateMaturity20232022Interest RateMaturity
(in millions)(in millions)
Revolving Credit FacilityRevolving Credit Facility$— $— 
SOFR plus 2.50%-3.50%
ABR plus 1.50%-2.50%(a)
July 31, 2027(b)
Revolving Credit Facility$— $— 
SOFR plus 2.50%-3.50%
ABR plus 1.50%-2.50%(a)
July 31, 2027(b)
Senior NotesSenior Notes600 600 7.125%February 1, 2026Senior Notes595 600 7.125%February 1, 2026
Principal amountPrincipal amount$600 $600 Principal amount$595 $600 
Unamortized debt issuance costsUnamortized debt issuance costs(7)(8)Unamortized debt issuance costs(6)(8)
Long-term debt, netLong-term debt, net$593 $592 Long-term debt, net$589 $592 
(a)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%.
(b)The Revolving Credit Facility is subject to a springing maturity to August 4, 2025 if any of our Senior Notes are outstanding on that date.

On April 26, 2023, we entered into an Amended and Restated Credit Agreement (Revolving Credit Facility) with Citibank, N.A., as administrative agent, and certain other lenders, which amendsamended and restatesrestated in its entirety the prior credit agreement dated October 27, 2020. As of JuneSeptember 30, 2023, our Revolving Credit Facility consisted of a senior revolving loan facility with an aggregate commitment of $627 million, which includes a net $25 million increase that occurred during the second quarter of 2023.million. Our Revolving Credit Facility also included a sub-limit of $250 million for the issuance of letters of credit. As of JuneSeptember 30, 2023, $148 million letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

The recent amendments to our Revolving Credit Facility included, among other things:

extendingextended the maturity date to July 31, 2027;
increasingincreased our ability to make certain restricted payments (such as dividends and share repurchases) and certain investments (including in our carbon management business);
releasingreleased liens on certain assets securing the loans made under the Revolving Credit Facility, including our Elk Hills power plant;
permittingpermitted 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;
extendingextended the period for which we can enter into hedges on our production from 48 months to 60 months; and
increasingincreased 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. 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.

On October 30, 2023, we further amended our Revolving Credit Facility. See Note 13 Subsequent Events for additional information regarding this amendment.

The borrowing base is redetermined semi-annually and was reaffirmed at $1.2 billion on April 26, 2023 as part of our amendment.October 30, 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.

1112



At JuneSeptember 30, 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.

Repurchases

In the three and nine months ended September 30, 2023, we repurchased $5 million in face value of our Senior Notes at par resulting in an insignificant extinguishment loss for the write-off of unamortized debt issuance costs. See Note 13 Subsequent Events for additional information on debt repurchases.

Fair Value

The fair value of our fixed-rate debt at JuneSeptember 30, 2023 and December 31, 2022 was approximately $604$598 million and $574 million, respectively. We estimate fair value based on known prices 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 JuneSeptember 30, 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. Upon execution of a cost sharing agreement with former lessees, we will share in on-going maintenance costs during the pendency of the challenge to the BSEE order.order and have recognized a liability of $12 million included in accrued liabilities at September 30, 2023.

NOTE 5    DERIVATIVES

We maintain a commodity hedging program primarily focused on crude oil, and to a lesser extent natural gas, to help protect our cash flows from the volatility of commodity prices and to optimize margins for our marketing and trading activities. We did not have any derivative instruments designated as accounting hedges as of and for the three and sixnine months ended JuneSeptember 30, 2023 and 2022. Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to implement our hedging strategy.

1213


Summary of open derivative contracts on oil — We held the following Brent-based contracts as of JuneSeptember 30, 2023:

Q3
2023
Q4
2023
Q1
2024
Q2
2024
2H
2024
2025Q4
2023
Q1
2024
Q2
2024
Q3
2024
Q4
2024
2025
Sold CallsSold CallsSold Calls
Barrels per dayBarrels per day17,363 5,747 7,750 10,500 10,375 14,811 Barrels per day5,747 23,650 30,000 30,000 29,000 19,748 
Weighted-average price per barrelWeighted-average price per barrel$57.06 $57.06 $90.00 $90.20 $90.20 $85.83 Weighted-average price per barrel$57.06 $90.00 $90.07 $90.07 $90.07 $85.63 
SwapsSwapsSwaps
Barrels per dayBarrels per day19,697 27,094 6,000 1,000 1,000 1,687 Barrels per day27,094 9,000 7,750 7,750 5,500 3,374 
Weighted-average price per barrelWeighted-average price per barrel$70.73 $70.73 $79.06 $77.20 $77.20 $70.32 Weighted-average price per barrel$70.73 $79.37 $79.65 $79.64 $77.45 $72.66 
Net Purchased Puts(a)
Net Purchased Puts(a)
Net Purchased Puts(a)
Barrels per dayBarrels per day17,363 5,747 14,684 10,500 10,375 14,811 Barrels per day5,747 30,584 30,000 30,000 29,000 19,748 
Weighted-average price per barrelWeighted-average price per barrel$76.25 $76.25 $69.72 $65.48 $65.48 $60.00 Weighted-average price per barrel$76.25 $67.27 $65.17 $65.17 $65.17 $60.00 
(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.

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 JuneSeptember 30, 2023 and December 31, 2022:
June 30, 2023
ClassificationGross Amounts at Fair ValueNettingNet Fair Value
(in millions)
  Other current assets, net(a)
$46 $(9)$37 
  Other noncurrent assets54 (37)17 
Current liabilities(a)
(81)(72)
Noncurrent liabilities(37)37 — 
$(18)$— $(18)
(a)In addition to our Brent based derivative contracts in the table above, we held swaps as of June 30, 2023 for 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 $1 million included in other current assets, net and $2 million included in current liabilities at June 30, 2023.
September 30, 2023
ClassificationGross Amounts at Fair ValueNettingNet Fair Value
(in millions)
  Other current assets, net$19 $(17)$
  Other noncurrent assets44 (44)— 
Current liabilities(120)17 (103)
Noncurrent liabilities(81)44 (37)
$(138)$— $(138)

13


December 31, 2022
ClassificationGross Amounts at Fair ValueNettingNet Fair Value
(in millions)
  Other current assets, net(a)
$51 $(12)$39 
  Other noncurrent assets— 
Current liabilities(a)
(258)12 (246)
$(200)$— $(200)
(a)In addition to our Brent based derivative contracts in the table above, we held swaps as of December 31, 2022 for 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. There were no natural gas hedges at September 30, 2023.

14


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 and sixnine months ended JuneSeptember 30, 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 tables presenttable presents the components of our total income tax provision and a reconciliation of the U.S. federal statutory rate to our effective tax rate:provision:

 Three months ended June 30,Six months ended June 30,
 2023202220232022
(in millions)(in millions)
Income before income taxes$135 $266 $511 $65 
Current income tax provision29 14 57 21 
Deferred income tax provision62 56 29 
Total income tax provision$38 $76 $113 $50 

 Three months ended June 30,Six months ended June 30,
 2023202220232022
U.S. federal statutory tax rate21 %21 %21 %21 %
State income taxes, net
Change in the valuation allowance— — (6)49 
Other— — — 
Effective tax rate28 %29 %22 %77 %
 Three months ended September 30,Nine months ended September 30,
 2023202220232022
(in millions)(in millions)
(Loss) income before income taxes$(30)$579 $481 $644 
Current income tax provision32 16 89 37 
Deferred income tax (benefit) provision(40)137 16 166 
Total income tax (benefit) provision$(8)$153 $105 $203 

During the sixnine months ended JuneSeptember 30, 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. During the sixnine months ended JuneSeptember 30, 2023, we recognized the benefit of this tax loss by releasing the valuation allowance after we jointly agreed to amend the original tax treatment with the buyer. See Note 7 Divestitures and Acquisitions for more information on our Lost Hills transaction.

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.

14


NOTE 7    DIVESTITURES AND ACQUISITIONS

Divestitures

Ventura Basin Transactions

In the three and sixnine months ended JuneSeptember 30, 2022, we recorded a gain of $4$2 million and $10$12 million, respectively, 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 receivecould occur in the second halffourth quarter 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 JuneSeptember 30, 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 first quarter of 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 until January 1, 2026. We also retained 100% of the deep rights and related seismic data.

Other

During the sixnine months ended JuneSeptember 30, 2023, we sold a non-producing asset in exchange for the assumption of liabilities recognizing a $7 million gain. During the sixnine months ended JuneSeptember 30, 2022, we sold non-core assets recognizing an insignificant loss.

15


Acquisitions

During the sixnine months ended JuneSeptember 30, 2022, we acquired properties for carbon management activities for approximately $17 million. We are evaluating the saleintend to divest a portion of certain unwantedthese 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 during the first quarter of 2023 due to market conditions including(including inflation and rising interest rates. These unwantedrates). The assets are classified as held for sale as of JuneSeptember 30, 2023 on our condensed consolidated balance sheet.

15


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 PurchasedTotal Value of Shares PurchasedAverage Price Paid per Share
(number of shares)(in millions)($ per share)
Three months ended June 30, 20222,255,445 $96 $42.57 
Three months ended June 30, 20231,618,746 $64 $39.12 
Six months ended June 30, 20223,923,901 $167 $42.55 
Six months ended June 30, 20233,042,510 $123 $40.12 
Inception of Program (May 2021) through June 30, 202314,498,770 $584 $40.18 
Total Number of Shares PurchasedTotal Value of Shares PurchasedAverage Price Paid per Share
(number of shares)(in millions)($ per share)
Three months ended September 30, 20221,921,181 $80 $41.78 
Three months ended September 30, 2023365,145 $20 $54.75 
Nine months ended September 30, 20225,845,082 $247 $42.29 
Nine months ended September 30, 20233,407,655 $143 $41.69 
Inception of Program (May 2021) through September 30, 202314,863,915 $604 $40.53 
Note: The total value of shares purchased includes approximately $1 million in the sixnine months ended JuneSeptember 30, 2023 related to excise taxes on share repurchases, which was effective beginning in 2023. Commissions paid were not significant in all periods presented.

Dividends

On February 23, 2023, ourOur Board of Directors declared a quarterlythe following cash dividenddividends for each of $0.2825 per share of common stock which 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 which amounted to $20 million in the aggregate. The dividend was payable to shareholders of record at the close of business on June 1, 2023 and was paid on June 16, 2023.periods presented.

Total DividendRate Per Share
(in millions)($ per share)
2023
Three months ended March 31, 2023$20 $0.2825 
Three months ended June 30, 202320 $0.2825 
Three months ended September 30, 202319 $0.2825 
Nine months ended September 30, 2023$59 
2022
Three months ended March 31, 2022$13 $0.1700 
Three months ended June 30, 202213 $0.1700 
Three months ended September 30, 202213 $0.1700 
Nine months ended September 30, 2022$39 

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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 13 Subsequent EventEvents 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 JuneSeptember 30, 2023, we had outstanding warrants exercisable into 4,295,1574,289,825 shares of our common stock (subject to adjustments pursuant to the terms of the warrants). During the three and sixnine months ended JuneSeptember 30, 2023, we issued 1,958 and 2,179 shares of our common stock, respectively, in exchange for warrants. During the three and nine months ended September 30, 2022, we issued an insignificant amountnumber 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 and sixnine months ended JuneSeptember 30, 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.

16


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 and sixnine months ended JuneSeptember 30, 2023 and 2022:

Three months ended June 30,Six months ended June 30,Three months ended September 30,Nine months ended September 30,
20232022202320222023202220232022
(in millions, except per-share amounts)(in millions, except per-share amounts)
Numerator for Basic and Diluted EPSNumerator for Basic and Diluted EPSNumerator for Basic and Diluted EPS
Net income$97 $190 $398 $15 
Net (loss) incomeNet (loss) income$(22)$426 $376 $441 
Denominator for Basic EPSDenominator for Basic EPSDenominator for Basic EPS
Weighted-average sharesWeighted-average shares69.7 76.7 70.5 77.6 Weighted-average shares68.7 74.1 69.9 76.4 
Potential Common Shares, if dilutive:Potential Common Shares, if dilutive:Potential Common Shares, if dilutive:
WarrantsWarrants0.5 0.7 0.5 0.7 Warrants— 0.7 0.8 0.7 
Restricted Stock UnitsRestricted Stock Units0.9 0.7 0.9 0.7 Restricted Stock Units— 0.8 1.0 0.7 
Performance Stock UnitsPerformance Stock Units0.8 0.7 0.8 0.6 Performance Stock Units— 0.7 0.9 0.7 
Denominator for Diluted EPSDenominator for Diluted EPSDenominator for Diluted EPS
Weighted-average sharesWeighted-average shares71.9 78.8 72.7 79.6 Weighted-average shares68.7 76.3 72.6 78.5 
EPSEPSEPS
BasicBasic$1.39 $2.48 $5.65 $0.19 Basic$(0.32)$5.75 $5.38 $5.77 
DilutedDiluted$1.35 $2.41 $5.47 $0.19 Diluted$(0.32)$5.58 $5.18 $5.62 

17


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

Three months ended September 30,Nine months ended September 30,
2023202220232022
(in millions)
Shares issuable upon exercise of warrants4.3 — — — 
Shares issuable upon settlement of RSUs1.3 — — — 
Shares issuable upon settlement of PSUs1.6 — — — 
Total antidilutive shares7.2 — — — 

NOTE 10    SUPPLEMENTAL ACCOUNT BALANCES

Revenues — We derive most of our revenue from sales of oil, natural gas and natural gas liquids (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 June 30,Six months ended June 30,
2023202220232022
(in millions)
Oil$362 $547 $752 $1,033 
Natural gas43 94 306 174 
NGLs42 77 104 139 
Oil, natural gas and NGL sales$447 $718 $1,162 $1,346 
17


Three months ended September 30,Nine months ended September 30,
2023202220232022
(in millions)
Oil$402 $494 $1,154 $1,527 
Natural gas61 120 367 294 
NGLs47 66 151 205 
Oil, natural gas and NGL sales$510 $680 $1,672 $2,026 

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:
June 30,December 31,September 30,December 31,
2023202220232022
(in millions)(in millions)
Materials and suppliesMaterials and supplies$65 $56 Materials and supplies$67 $56 
Finished goodsFinished goodsFinished goods
InventoriesInventories$69 $60 Inventories$71 $60 

Other current assets, net — Other current assets, net include the following:
June 30,December 31,September 30,December 31,
2023202220232022
(in millions)(in millions)
Net amounts due from joint interest partners(a)
Net amounts due from joint interest partners(a)
$32 $39 
Net amounts due from joint interest partners(a)
$43 $39 
Fair value of commodity derivative contractsFair value of commodity derivative contracts37 39 Fair value of commodity derivative contracts39 
Prepaid expensesPrepaid expenses21 17 Prepaid expenses16 17 
Greenhouse gas allowancesGreenhouse gas allowances16 — Greenhouse gas allowances14 — 
Natural gas margin depositsNatural gas margin deposits16 Natural gas margin deposits16 
Income tax receivableIncome tax receivable10 Income tax receivable10 
OtherOther12 12 Other17 12 
Other current assets, netOther current assets, net$125 $133 Other current assets, net$97 $133 
(a)Included in the JuneSeptember 30, 2023 and December 31, 2022 net amounts due from joint interest partners are allowances of $1 million.

18


Other noncurrent assets — Other noncurrent assets include the following:
June 30,December 31,September 30,December 31,
2023202220232022
(in millions)(in millions)
Operating lease right-of-use assetsOperating lease right-of-use assets$83 $73 Operating lease right-of-use assets$68 $73 
Deferred financing costs - Revolving Credit FacilityDeferred financing costs - Revolving Credit Facility12 Deferred financing costs - Revolving Credit Facility12 
Emission reduction creditsEmission reduction credits11 11 Emission reduction credits11 11 
Prepaid power plant maintenancePrepaid power plant maintenance31 28 Prepaid power plant maintenance33 28 
Fair value of commodity derivative contractsFair value of commodity derivative contracts17 Fair value of commodity derivative contracts— 
Deposits and otherDeposits and other12 15 Deposits and other12 15 
Other noncurrent assetsOther noncurrent assets$166 $140 Other noncurrent assets$136 $140 

18


Accrued liabilities — Accrued liabilities include the following:
June 30,December 31,September 30,December 31,
2023202220232022
(in millions)(in millions)
Employee-related costsEmployee-related costs$65 $49 Employee-related costs$78 $49 
Taxes other than on incomeTaxes other than on income31 32 Taxes other than on income49 32 
Asset retirement obligationsAsset retirement obligations72 59 Asset retirement obligations91 59 
InterestInterest19 19 Interest19 
Operating lease liabilityOperating lease liability16 18 Operating lease liability13 18 
Premiums due on commodity derivative contractsPremiums due on commodity derivative contracts35 58 Premiums due on commodity derivative contracts24 58 
Liability for settlement payments on commodity derivative contractsLiability for settlement payments on commodity derivative contracts15 33 Liability for settlement payments on commodity derivative contracts37 33 
Amounts due under production-sharing contractsAmounts due under production-sharing contracts— Amounts due under production-sharing contracts15 — 
Signal Hill maintenanceSignal Hill maintenance11 Signal Hill maintenance12 
OtherOther28 22 Other35 22 
Accrued liabilities Accrued liabilities$299 $298  Accrued liabilities$362 $298 

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

June 30,December 31,September 30,December 31,
2023202220232022
(in millions)(in millions)
Compensation-related liabilitiesCompensation-related liabilities$40 $36 Compensation-related liabilities$37 $36 
Postretirement benefit planPostretirement benefit plan29 33 Postretirement benefit plan32 33 
Operating lease liabilityOperating lease liability64 52 Operating lease liability53 52 
Fair value of commodity derivative contractsFair value of commodity derivative contracts37 — 
Premiums due on commodity derivative contractsPremiums due on commodity derivative contracts13 Premiums due on commodity derivative contracts13 
Contingent liability (related to Carbon TerraVault JV put and call rights)Contingent liability (related to Carbon TerraVault JV put and call rights)50 48 Contingent liability (related to Carbon TerraVault JV put and call rights)51 48 
OtherOtherOther
Other long-term liabilitiesOther long-term liabilities$204 $185 Other long-term liabilities$231 $185 

19


General and administrative expenses — The table below shows G&A expenses for our exploration and production business (including unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business are net of amounts invoiced by us under the MSA to the Carbon TerraVault JV. See Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV.

G&A expenses were $71 million for the three months ended June 30, 2023, which was an increase of $15 million from $56 million for the three months ended June 30, 2022. G&A expenses were $136 million for the six months ended June 30, 2023, which was an increase of $32 million from $104 million for the six months ended June 30, 2022. The increase in G&A expenses for the three and six month periods was primarily attributable to compensation-related expenses, including accelerated vesting for certain departing employees and stock-based compensation awards granted in 2023, and higher spending on information technology infrastructure.
Three months ended September 30,Nine months ended September 30,
2023202220232022
(in millions)(in millions)
Exploration and production, corporate and other$61 $54 $191 $153 
Carbon management business10 10 
Total general and administrative expenses$65 $59 $201 $163 

Three months ended June 30,Six months ended June 30,
2023202220232022
(in millions)(in millions)
Exploration and production, corporate and other$68 $52 $130 $99 
Carbon management business
Total general and administrative expenses$71 $56 $136 $104 

19


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

Three months ended June 30,Six months ended June 30,
2023202220232022
(in millions)(in millions)
Exploration and production, corporate and other$13 $$22 $23 
Carbon management business— 12 — 
Total other operating expenses, net$21 $$34 $23 
In August 2023, we implemented organizational changes that resulted in a headcount reduction of 75 employees. As a result, we recognized a charge of $7 million in other operating expenses, net on the condensed consolidated statement of operations for the three months ended September 30, 2023, primarily related to severance benefits. For the nine months ended September 30, 2023, we recognized a severance charge of $10 million.

Three months ended September 30,Nine months ended September 30,
2023202220232022
(in millions)(in millions)
Exploration and production, corporate and other$19 $$41 $25 
Carbon management business21 
Total other operating expenses, net$28 $$62 $28 

NOTE 11    SUPPLEMENTAL CASH FLOW INFORMATION

We paid $51$29 million and $80 million of U.S. federal and state income tax payments during the three and sixnine months ended JuneSeptember 30, 2023.2023, respectively. We paid $20 million of U.S. federal income tax payments during the three and sixnine months ended JuneSeptember 30, 2022. No state income tax payments were made in the three and sixnine months ended JuneSeptember 30, 2022.

Interest paid, net of capitalized amounts, was insignificant$22 million for the three months ended JuneSeptember 30, 2023 and $22$44 million for the sixnine months ended JuneSeptember 30, 2023. Interest paid, net of capitalized amounts, was insignificant$21 million for the three months ended JuneSeptember 30, 2022 and $22$43 million for the sixnine months ended JuneSeptember 30, 2022. Interest income was $5 million and $14 million for the three and nine months ended September 30, 2023, respectively.

Non-cash investing activities in the three and sixnine months ended JuneSeptember 30, 2023 included $2$4 million and $4$7 million, respectively, related to our share of capital calls by the Carbon TerraVault JV. For the three and nine months ended September 30, 2022, we made a non-cash contribution of $2 million to the Carbon TerraVault JV to satisfy a capital call. See Note 2 Investment in Unconsolidated Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV.

20


Non-cash investingfinancing activities in the three and sixnine months ended JuneSeptember 30, 20222023 included $1 million of additional earn-out considerationand $2 million, respectively, for dividends accrued for stock-based compensation. For the three and nine months ended September 30, 2022 dividends accrued for stock-based compensation awards was $1 million. Non-cash financing activities in the nine months ended September 30, 2023 also included approximately $1 million related to our Ventura basin asset divestiture.an excise tax on share repurchases that we expect will be paid in 2024.

NOTE 12    CONDENSED CONSOLIDATING FINANCIAL INFORMATION

We have designated certain of our subsidiaries as Unrestricted Subsidiaries under the indenture governing our Senior Notes (Senior Notes Indenture). Unrestricted Subsidiaries (as defined in the Senior Notes Indenture) are subject to fewer restrictions under the Senior Notes Indenture. We are required under the Senior Notes indenture to present the financial condition and results of operations of CRC and its Restricted Subsidiaries (as defined in the Senior Notes Indenture) separate from the financial condition and results of operations of its Unrestricted Subsidiaries. The following condensed consolidating balance sheets as of JuneSeptember 30, 2023 and December 31, 2022 and the condensed consolidating statements of operations for the three and sixnine months ended JuneSeptember 30, 2023 and 2022, as applicable, reflect the condensed consolidating financial information of our parent company, CRC (Parent), our combined Unrestricted Subsidiaries, our combined Restricted Subsidiaries and the elimination entries necessary to arrive at the information for the Company on a consolidated basis. The financial information may not necessarily be indicative of the financial condition and results of operations had the Unrestricted Subsidiaries operated as independent entities.

20


Condensed Consolidating Balance Sheets
As of JuneSeptember 30, 2023 and December 31, 2022

As of June 30, 2023
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)
Total current assets$467 $30 $370 $— $867 
Total property, plant and equipment, net12 2,726 — 2,745 
Investments in consolidated subsidiaries2,736 (9)1,530 (4,257)— 
Deferred tax asset108 — — — 108 
Investment in unconsolidated subsidiary— 14 — — 14 
Other assets14 42 110 — 166 
TOTAL ASSETS$3,337 $84 $4,736 $(4,257)$3,900 
Total current liabilities95 478 — $582 
Long-term debt593 — — — 593 
Asset retirement obligations— — 411 — 411 
Other long-term liabilities77 76 51 — 204 
Amounts due to (from) affiliates462 21 (483)— — 
Total equity2,110 (22)4,279 (4,257)2,110 
TOTAL LIABILITIES AND EQUITY$3,337 $84 $4,736 $(4,257)$3,900 
As of December 31, 2022
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)
Total current assets$329 $33 $502 $— $864 
Total property, plant and equipment, net13 2,767 — 2,786 
Investments in consolidated subsidiaries2,096 — 1,512 (3,608)— 
Deferred tax asset164 — — — 164 
Investment in unconsolidated subsidiary— 13 — — 13 
Other assets33 99 — 140 
TOTAL ASSETS$2,610 $85 $4,880 $(3,608)$3,967 
Total current liabilities76 811 — $894 
Long-term debt592 — — — 592 
Asset retirement obligations— — 432 — 432 
Other long-term liabilities78 67 40 — 185 
Total equity1,864 11 3,597 (3,608)1,864 
TOTAL LIABILITIES AND EQUITY$2,610 $85 $4,880 $(3,608)$3,967 

As of September 30, 2023
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)
Total current assets$488 $27 $414 $— $929 
Total property, plant and equipment, net13 2,702 — 2,722 
Investments in consolidated subsidiaries2,315 (12)1,434 (3,737)— 
Deferred tax asset150 — — — 150 
Investment in unconsolidated subsidiary— 15 — — 15 
Other assets13 30 93 — 136 
TOTAL ASSETS$2,979 $67 $4,643 $(3,737)$3,952 
Total current liabilities109 577 — $694 
Long-term debt589 — — — 589 
Asset retirement obligations— — 388 — 388 
Other long-term liabilities75 68 88 — 231 
Amounts due to (from) affiliates156 12 (168)— — 
Total equity2,050 (21)3,758 (3,737)2,050 
TOTAL LIABILITIES AND EQUITY$2,979 $67 $4,643 $(3,737)$3,952 
21


As of December 31, 2022
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)
Total current assets$329 $33 $502 $— $864 
Total property, plant and equipment, net13 2,767 — 2,786 
Investments in consolidated subsidiaries2,096 — 1,512 (3,608)— 
Deferred tax asset164 — — — 164 
Investment in unconsolidated subsidiary— 13 — — 13 
Other assets33 99 — 140 
TOTAL ASSETS$2,610 $85 $4,880 $(3,608)$3,967 
Total current liabilities76 811 — $894 
Long-term debt592 — — — 592 
Asset retirement obligations— — 432 — 432 
Other long-term liabilities78 67 40 — 185 
Total equity1,864 11 3,597 (3,608)1,864 
TOTAL LIABILITIES AND EQUITY$2,610 $85 $4,880 $(3,608)$3,967 

Condensed Consolidating Statement of Operations
For the three and sixnine months ended JuneSeptember 30, 2023 and 2022

Three months ended June 30, 2023Three months ended September 30, 2023
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidatedParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)(in millions)
Total revenuesTotal revenues$$— $586 $— $591 Total revenues$$— $454 $— $460 
Total costs and otherTotal costs and other62 11 371 — 444 Total costs and other66 12 397 — 475 
Non-operating (loss) incomeNon-operating (loss) income(11)(2)— (12)Non-operating (loss) income(12)(4)— (15)
(LOSS) INCOME BEFORE INCOME TAXES(LOSS) INCOME BEFORE INCOME TAXES(68)(13)216 — 135 (LOSS) INCOME BEFORE INCOME TAXES(72)(16)58 — (30)
Income tax provision(38)— — — (38)
Income tax benefitIncome tax benefit— — — 
NET (LOSS) INCOMENET (LOSS) INCOME$(106)$(13)$216 $— $97 NET (LOSS) INCOME$(64)$(16)$58 $— $(22)

Three months ended June 30, 2022
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)
Total revenues$— $— $747 $— $747 
Total costs and other43 425 — 473 
Gain on asset divestitures— — — 
Non-operating (loss) income(13)— — (12)
(LOSS) INCOME BEFORE INCOME TAXES(56)(5)327 — 266 
Income tax provision(76)— — — (76)
NET (LOSS) INCOME$(132)$(5)$327 $— $190 

Six months ended June 30, 2023
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)
Total revenues$$— $1,606 $— $1,615 
Total costs and other112 19 951 — 1,082 
Gain on asset divestitures— — — 
Non-operating (loss) income(27)(5)— (29)
(LOSS) INCOME BEFORE INCOME TAXES(130)(24)665 — 511 
Income tax provision(113)— — — (113)
NET (LOSS) INCOME$(243)$(24)$665 $— $398 
22


Six months ended June 30, 2022Three months ended September 30, 2022
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidatedParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)(in millions)
Total revenuesTotal revenues$— $— $900 $— $900 Total revenues$$— $1,124 $— $1,125 
Total costs and otherTotal costs and other81 781 — 869 Total costs and other43 14 479 — 536 
Gain on asset divestituresGain on asset divestitures— — 58 — 58 Gain on asset divestitures— — — 
Non-operating (loss) incomeNon-operating (loss) income(27)— — (24)Non-operating (loss) income(14)— — (12)
(LOSS) INCOME BEFORE INCOME TAXES(LOSS) INCOME BEFORE INCOME TAXES(108)(7)180 — 65 (LOSS) INCOME BEFORE INCOME TAXES(56)(14)649 — 579 
Income tax provisionIncome tax provision(50)— — — (50)Income tax provision(153)— — — (153)
NET (LOSS) INCOMENET (LOSS) INCOME$(158)$(7)$180 $— $15 NET (LOSS) INCOME$(209)$(14)$649 $— $426 

Nine months ended September 30, 2023
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)
Total revenues$14 $— $2,061 $— $2,075 
Total costs and other177 31 1,349 — 1,557 
Gain on asset divestitures— — — 
Non-operating (loss) income(39)(9)— (44)
(LOSS) INCOME BEFORE INCOME TAXES(202)(40)723 — 481 
Income tax provision(105)— — — (105)
NET (LOSS) INCOME$(307)$(40)$723 $— $376 
Nine months ended September 30, 2022
ParentCombined Unrestricted SubsidiariesCombined Restricted SubsidiariesEliminationsConsolidated
(in millions)
Total revenues$$— $2,024 $— $2,025 
Total costs and other125 21 1,259 — 1,405 
Gain on asset divestitures— — 60 — 60 
Non-operating (loss) income(41)— — (36)
(LOSS) INCOME BEFORE INCOME TAXES(165)(21)830 — 644 
Income tax provision(203)— — — (203)
NET (LOSS) INCOME$(368)$(21)$830 $— $441 

NOTE 13    SUBSEQUENT EVENTEVENTS

Revolving Credit Facility Amendment

On July 28,October 30, 2023 we amended our Revolving Credit Facility to increase our flexibility to incur new indebtedness in the form of term loans. In addition, the aggregate commitment amount of the Revolving Credit Facility was increased by $3 million to $630 million.

23


Dividend

On November 1, 2023, our Board of Directors increased the cash dividend policy to anticipate a total annual dividend of $1.24, payable to shareholders in quarterly increments of $0.31 per share of common stock. 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. Also on November 1, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825$0.31 per share of common stock. The dividend is payable to shareholders of record at the close of business on SeptemberDecember 1, 2023 and is expected to be paid on SeptemberDecember 15, 2023.

Debt Repurchases

In October 2023, we repurchased $30 million in face value of our Senior Notes. After the write-off of a portion of the unamortized debt issuance costs, the extinguishment loss was insignificant.

23
24


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 weForce. We are focused on maximizing the value of our land, minerals and technical resources for oil and gas extraction and decarbonization efforts. We are in the early stages of developing several carbon capture and storage (CCS) projects and other emissions reducing projects in California. 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.

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its consolidated subsidiaries.

Reorganization

In August 2023, we implemented organizational changes that resulted in a headcount reduction of 75 employees. These actions were taken to better align our resources to our strategic priorities and improve our operational efficiency. As a result, we recognized a charge of $7 million in other operating expenses, net for the three months ended September 30, 2023, primarily related to severance benefits. For the nine months ended September 30, 2023, we recognized a severance charge of $10 million. We expect these actions, along with other initiatives taken to streamline our operations, to result in at least $55 million of savings in operating and overhead costs on an annualized basis.

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 may 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 slightly in the three months ended June 30, 2023 compared to the three months ended March 31, 2023 as global demand for oil remained generally flat. The decrease in natural gas index prices during the three months ended June 30, 2023 compared to the three months ended March 31, 2023 occurred as North American natural gas production and storage inventories remained relatively high in the second quarter. Refer to Prices and Realizations below for additional information on our realized prices.

The following table presents the average daily benchmark prices for oil and natural gas during the periods presented:
Three months endedSix months endedThree months endedNine months ended
June 30, 2023March 31, 2023June 30, 2023June 30, 2022September 30, 2023June 30, 2023September 30, 2023September 30, 2022
Brent oil ($/Bbl)Brent oil ($/Bbl)$78.01 $82.22 $80.12 $104.59 Brent oil ($/Bbl)$85.95 $78.01 $82.06 $102.33 
WTI oil ($/Bbl)WTI oil ($/Bbl)$73.78 $76.13 $74.95 $101.35 WTI oil ($/Bbl)$82.26 $73.78 $77.39 $98.09 
NYMEX Henry Hub ($/MMBtu) Average Monthly Settled PriceNYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price$2.10 $3.42 $2.76 $6.06 NYMEX Henry Hub ($/MMBtu) Average Monthly Settled Price$2.55 $2.10 $2.69 $6.77 

2425


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. Since December 2022, CalGEM has issued a limited number of permits for new production wells in California, and those permits were issued to other operators. We continue to receive permits from CalGEM for workovers, deepenings, sidetracks and plugging and abandonment operations. For more information, see Water InjectionPart I, Item 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate in our 2022 Annual Report.

Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by the City of Long Beach and CalGEM. We are currently in discussions with the City of Long Beach and CalGEM with respect to what injection well pressure gradient complies with CalGEM’s regulatory requirements for the protection of underground sources of drinking water, while at the same time mitigating subsidence risks.risk. CalGEM's local office has preliminarily indicated that the injection well pressure gradient should be reduced from the gradient that has been used for several decades. As part ofdecades, although a final determination has not yet been made and remains subject to our ongoing discussions, we and the City of Long Beach have provided CalGEM with technical information regarding how the historical injection well pressure gradient complies with CalGEM's requirements, as well as the Clean Water Act, and to inform them of the absence of risk of leakage from the injection zone. CalGEM has proposed a meeting for CRC and the City of Long Beach to present their technical findings in more detail, to occur in or around August 2023. As part of that meeting, and subject to its outcome, CalGEM has also proposed that CRC and the City of Long Beach present a work plan for the reduction of injection pressures over a six-month period to levels acceptable to CalGEM. We are in the process of preparing a response and continue to believe that existing injection pressures address subsidence risks and are protective of underground sources of drinking water.discussions. If CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient, and we were unable to reverse that decision on appeal or other legal challenge, we expect any material reduction in injection well pressure gradient for our operations in the Wilmington Oil Field would result in a decrease in production and reserves from the field. For additional information, see Part I, Item 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities and the Risk factor entitled "Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans" in our 2022 Annual Report.

Bonding Requirements and AB 1167

See Part II, Item 1A – Risk Factors for recent California legislative activity on bonding requirements associated with certain transfers of interests in oil and gas wells.

California Climate Disclosures

In October 2023, the Governor of California signed two bills that will require climate-related disclosures, both of which apply to us. Senate Bill 253 (SB-253) requires the annual disclosure of Scope 1, Scope 2 and Scope 3 GHG emissions, with certain GHG emissions data subject to third-party assurance. The bill requires disclosure beginning in 2026 (for the 2025 reporting year). Senate Bill 261 (SB-261) requires biennial disclosures posted on a company's website related to climate-related financial risks and the measures a company has adopted to reduce and adapt to such risks.

Supply Chain Constraints and Inflation

In 2023, we have experiencedWe continued to experience relatively flat pricing from our suppliers in the nine months ended September 30, 2023 compared to the same period in 2022. Labor costsWe have long term vendor relationships and national electricity prices have risen which has partially negated the benefits of supply chains opening up in 2023. Further, we have been unable to obtain price reductions from our vendors for certain purchased goods, including OCTG, wellbore tubulars and chemicals. These categories have raw material inputs such as steel and diesel fuel which have experienced intermediate price spikes throughout the first half of 2023 preventing our vendors from offering price reductions for these items.

We have taken measures to limit the effects of inflation by entering into contracts for a significant majority of our materials and services with terms of one to three years. For contracts that we anticipate renegotiatingWe have not experienced any meaningful inflation in the second half of 2023, we expect moderate price increases for certain purchased goodsconnection with recent contract renewals and services. We also continue to look at ways to improve productivity and performance fromexpect minimal inflation in our workforce and our vendors.supply chain.

2526


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 endedSix months endedThree months endedNine months ended
June 30, 2023March 31, 2023June 30, 2023June 30, 2022September 30, 2023June 30, 2023September 30, 2023September 30, 2022
Oil (MBbl/d)Oil (MBbl/d)Oil (MBbl/d)
San Joaquin Basin San Joaquin Basin34 35 35 38  San Joaquin Basin33 34 34 37 
Los Angeles Basin Los Angeles Basin19 20 19 17  Los Angeles Basin18 19 19 18 
Total Total53 55 54 55  Total51 53 53 55 
NGLs (MBbl/d)NGLs (MBbl/d)NGLs (MBbl/d)
San Joaquin Basin San Joaquin Basin11 11 11 11  San Joaquin Basin11 11 11 11 
Total Total11 11 11 11  Total11 11 11 11 
Natural gas (MMcf/d)Natural gas (MMcf/d)Natural gas (MMcf/d)
San Joaquin Basin San Joaquin Basin119 119 119 127  San Joaquin Basin122 119 120 128 
Los Angeles Basin Los Angeles Basin Los Angeles Basin
Sacramento Basin Sacramento Basin15 16 16 18  Sacramento Basin15 15 15 18 
Total Total135 136 136 146  Total138 135 136 147 
Total Net Production (MBoe/d)Total Net Production (MBoe/d)86 89 88 90 Total Net Production (MBoe/d)85 86 87 91 

Total daily net production for the three months ended JuneSeptember 30, 2023, compared to the three months ended March 31,June 30, 2023 decreased by 31 MBoe/d largely due to natural decline for oil. Our production-sharing contracts (PSCs), which are described below, did not have a significant impact on our net oil production in the three months ended September 30, 2023 compared to the three months ended June 30, 2023.

Total daily net production for the nine months ended September 30, 2023, compared to the same prior year period decreased by 4 MBoe/d largely due to natural decline and changesthe divestiture of our remaining 50% working interest in NGL storage volumes.certain zones in the Lost Hills field in February 2022. This decrease was partially offset by increased production from drilling and workover activity. Our production-sharing contracts (PSCs), which are described below, negatively impactedactivity in Long Beach and our net oil production by 1 MBoe/d in the three months ended June 30, 2023 compared to the three months ended March 31, 2023.

Total daily net production for the six months ended June 30, 2023, compared to the same prior year period decreased by 2 MBoe/d largely due to natural decline partially offset by increased production from drilling and workover activity. Our PSCs positively impacted our net production by 2 MBoe/d in the sixnine months ended JuneSeptember 30, 2023 compared to the same prior year period.

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 endedSix months endedThree months endedNine months ended
June 30, 2023March 31, 2023June 30, 2023June 30, 2022September 30, 2023June 30, 2023September 30, 2023September 30, 2022
(MBoe/d)(MBoe/d)
Total Net ProductionTotal Net Production86898890Total Net Production85868791
Partners' share under PSC-type contractsPartners' share under PSC-type contracts7667Partners' share under PSC-type contracts7768
Working interest and royalty holders' shareWorking interest and royalty holders' share8788Working interest and royalty holders' share7887
Changes in NGL inventory and otherChanges in NGL inventory and other2111Changes in NGL inventory and other2211
Total Gross ProductionTotal Gross Production103103103106Total Gross Production101103102107

2627


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 endedThree months ended
June 30, 2023March 31, 2023September 30, 2023June 30, 2023
(in millions)($ per Boe)(in millions)($ per Boe)(in millions)($ per Boe)(in millions)($ per Boe)
Operating costsOperating costs$186 $23.71 $254 $31.61 Operating costs$196 $24.96 $186 $23.71 
Excess costs attributable to PSC-type contractsExcess costs attributable to PSC-type contracts(17)$(2.15)(18)$(2.23)Excess costs attributable to PSC-type contracts(19)$(2.39)(17)$(2.15)
Operating costs, excluding effects of PSC-type contractsOperating costs, excluding effects of PSC-type contracts$169 $21.56 $236 $29.38 Operating costs, excluding effects of PSC-type contracts$177 $22.57 $169 $21.56 

Six months endedNine months ended
June 30, 2023June 30, 2022September 30, 2023September 30, 2022
(in millions)($ per Boe)(in millions)($ per Boe)(in millions)($ per Boe)(in millions)($ per Boe)
Operating costsOperating costs$440 $27.71 $372 $22.90 Operating costs$636 $26.80 $586 $23.71 
Excess costs attributable to PSC-type contractsExcess costs attributable to PSC-type contracts(35)$(2.19)(40)$(2.45)Excess costs attributable to PSC-type contracts(54)$(2.26)(58)$(2.35)
Operating costs, excluding effects of PSC-type contractsOperating costs, excluding effects of PSC-type contracts$405 $25.52 $332 $20.45 Operating costs, excluding effects of PSC-type contracts$582 $24.54 $528 $21.36 

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.

2728


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 endedThree months ended
June 30, 2023March 31, 2023September 30, 2023June 30, 2023
PriceRealizationPriceRealizationPriceRealizationPriceRealization
Oil ($ per Bbl)Oil ($ per Bbl)Oil ($ per Bbl)
BrentBrent$78.01 $82.22 Brent$85.95 $78.01 
Realized price without derivative settlementsRealized price without derivative settlements$75.77 97%$78.68 96%Realized price without derivative settlements$85.36 99%$75.77 97%
Derivative settlementsDerivative settlements(12.11)(15.64)Derivative settlements(19.24)(12.11)
Realized price with derivative settlementsRealized price with derivative settlements$63.66 82%$63.04 77%Realized price with derivative settlements$66.12 77%$63.66 82%
WTIWTI$73.78 $76.13 WTI$82.26 $73.78 
Realized price without derivative settlementsRealized price without derivative settlements$75.77 103%$78.68 103%Realized price without derivative settlements$85.36 104%$75.77 103%
Realized price with derivative settlementsRealized price with derivative settlements$63.66 86%$63.04 83%Realized price with derivative settlements$66.12 80%$63.66 86%
NGLs ($ per Bbl)NGLs ($ per Bbl)NGLs ($ per Bbl)
Realized price (% of Brent)Realized price (% of Brent)$42.48 54%$58.88 72%Realized price (% of Brent)$44.95 52%$42.48 54%
Realized price (% of WTI)Realized price (% of WTI)$42.48 58%$58.88 77%Realized price (% of WTI)$44.95 55%$42.48 58%
Natural gasNatural gasNatural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled PriceNYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price$2.10 $3.42 NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price$2.55 $2.10 
Realized price without derivative settlements ($/Mcf)$3.46 165%$21.56 630%
Derivative settlements— — 
Realized price with derivative settlements ($/Mcf)$3.46 165%$21.56 630%
Realized price ($/Mcf)Realized price ($/Mcf)$4.83 189%$3.46 165%

2829


Six months endedNine months ended
June 30, 2023June 30, 2022September 30, 2023September 30, 2022
PriceRealizationPriceRealizationPriceRealizationPriceRealization
Oil ($ per Bbl)Oil ($ per Bbl)Oil ($ per Bbl)
BrentBrent$80.12 $104.59 Brent$82.06 $102.33 
Realized price without derivative settlementsRealized price without derivative settlements$77.25 96%$104.07 100%Realized price without derivative settlements$79.90 97%$102.01 100%
Derivative settlementsDerivative settlements(13.90)(42.36)Derivative settlements(15.65)(40.05)
Realized price with derivative settlementsRealized price with derivative settlements$63.35 79%$61.71 59%Realized price with derivative settlements$64.25 78%$61.96 61%
WTIWTI$74.95 $101.35 WTI$77.39 $98.09 
Realized price without derivative settlementsRealized price without derivative settlements$77.25 103%$104.07 103%Realized price without derivative settlements$79.90 103%$102.01 104%
Realized price with derivative settlementsRealized price with derivative settlements$63.35 85%$61.71 61%Realized price with derivative settlements$64.25 83%$61.96 63%
NGLs ($ per Bbl)NGLs ($ per Bbl)NGLs ($ per Bbl)
Realized price (% of Brent)Realized price (% of Brent)$50.88 64%$72.57 69%Realized price (% of Brent)$48.89 60%$66.98 65%
Realized price (% of WTI)Realized price (% of WTI)$50.88 68%$72.57 72%Realized price (% of WTI)$48.89 63%$66.98 68%
Natural gasNatural gasNatural gas
NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled PriceNYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price$2.76 $6.06 NYMEX Henry Hub ($/MMBtu) - Average Monthly Settled Price$2.69 $6.77 
Realized price without derivative settlements ($/Mcf)Realized price without derivative settlements ($/Mcf)$12.44 451%$6.58 109%Realized price without derivative settlements ($/Mcf)$9.85 366%$7.33 108%
Derivative settlementsDerivative settlements— (0.07)Derivative settlements— (0.12)
Realized price with derivative settlements ($/Mcf)Realized price with derivative settlements ($/Mcf)$12.44 451%$6.51 107%Realized price with derivative settlements ($/Mcf)$9.85 366%$7.21 106%

Oil — Brent prices decreased slightlyincreased for the three months ended JuneSeptember 30, 2023 compared to the three months ended March 31,June 30, 2023 as global demand for crude remained generally flat.OPEC and Saudi Arabia announced extended production cuts in September 2023. Oil prices in the sixnine months ended JuneSeptember 30, 2023 were lower than the same prior year period in 2022 as global energy inventories (including crude, refined products and natural gas) stabilized and as Russian crude and refined products continuecontinued to reach markets.

NGLs — NGL prices for the three months ended JuneSeptember 30, 2023 decreasedincreased compared to the three months ended March 31,June 30, 2023 reflecting traditional seasonality in NGL pricing, as well as higher than normal levels of inventory for this time of year.concert with crude pricing. NGL prices for the sixnine months ended JuneSeptember 30, 2023 decreased compared to the same prior year period as prices for competing and complementary products (natural gas, crude oil) have declined.declined and as NGL production and inventories grew to near-record levels. For both periods, California remained a premium market compared to other North American locations.

Natural Gas — Our realized price for natural gas decreasedincreased for the three months ended JuneSeptember 30, 2023 compared to the three months ended March 31,June 30, 2023 as weather across the West Coastdriven by incremental gas-fired electrical generation and replenishment of the United States during the quarter remained moderate and as Californianatural gas storage inventories rebounded from historically low levels.inventories. Natural gas prices in the sixnine months ended JuneSeptember 30, 2023 were higher than the same period in 2022 largely reflecting the unprecedentedunusually high pricing experienced in California natural gas markets during the first quarter of 2023.

2930


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 September 30, 2023 and June 30, 2023 and March 31, 2023 and the sixnine months ended JuneSeptember 30, 2023 and 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. Purchased natural gas used to generate steam in our steamfloods was reclassified from non-energy operating costs to energy operating costs beginning in the third quarter of 2022. All prior periods have been updated to conform to this presentation.

Three months endedSix months endedThree months endedNine months ended
June 30, 2023March 31, 2023June 30, 2023June 30, 2022September 30, 2023June 30, 2023September 30, 2023September 30, 2022
($ per Boe)($ per Boe)
Energy operating costsEnergy operating costs$7.39 $15.56 $11.52 $9.24 Energy operating costs$9.42 $7.39 $10.87 $9.83 
Gas processing costsGas processing costs$0.64 $0.62 $0.63 $0.55 Gas processing costs$0.64 $0.64 $0.59 $0.53 
Non-energy operating costsNon-energy operating costs$15.68 $15.43 $15.56 $13.11 Non-energy operating costs$14.90 $15.68 $15.34 $13.35 
Operating costsOperating costs$23.71 $31.61 $27.71 $22.90 Operating costs$24.96 $23.71 $26.80 $23.71 
Field general and administrative expenses(a)
Field general and administrative expenses(a)
$1.40 $1.49 $1.45 $0.92 
Field general and administrative expenses(a)
$1.27 $1.40 $1.39 $1.01 
Field depreciation, depletion and amortization(b)
Field depreciation, depletion and amortization(b)
$6.50 $6.72 $6.61 $5.29 
Field depreciation, depletion and amortization(b)
$6.62 $6.50 $6.62 $5.30 
Field taxes other than on incomeField taxes other than on income$3.70 $3.73 $3.72 $3.20 Field taxes other than on income$4.33 $3.70 $3.92 $3.36 
a.(a)Excludes unallocated general and administrative expenses.
b.(b)Excludes depreciation, depletion and amortization related to our corporate assets and our Elk Hills power plant.

Operating costs decreasedincreased during the three months ended JuneSeptember 30, 2023 compared to the three months ended March 31,June 30, 2023 primarily due to lowerhigher energy operating costs as electricity and natural gas prices in California markets declinedincreased between quarters. Operating costs were higher in the sixnine months ended JuneSeptember 30, 2023 compared to the same prior year period primarily due to increased energy operating costs as natural gas priceswell as increased downhole maintenance activity in California experienced unprecedented highs during the first quarter of 2023. Lower production volumes also contributed to the increase on a per Boe basis.

Field depreciation, depletion and amortization decreased slightly during the three months ended June 30, 2023 compared to the three months ended March 31, 2023 due to lower production volumes. Field depreciation, depletion and amortization increased during the sixnine months ended JuneSeptember 30, 2023 compared to the same prior year period primarily due to a change in our depreciation, depletion and amortization rates which are periodically adjusted to reflect current reserve estimates. This increase was partially offset by lower production volumes in the six months ended June 30, 2023 compared to the six months ended June 30, 2022. Lower production volumes also contributed to the increase on a per Boe basis.

Field taxes other than on income increased during the three months ended September 30, 2023 compared to the three months ended June 30, 2023, and the nine months ended September 30, 2023 compared to the same prior year period primarily due to higher ad valorem taxes in the second half of 2023, which in California are heavily influenced by commodity prices.

Consolidated Results of Operations

For financial information related to our subsidiaries designated as Unrestricted Subsidiaries under the Senior Notes Indenture, see Part I, Item 1 – Financial Statements, Note 12 Condensed Consolidated Financial Information.
3031



Three months ended JuneSeptember 30, 2023 compared to March 31,June 30, 2023

The following table presents our operating revenues for the three months ended JuneSeptember 30, 2023 and March 31,June 30, 2023:
Three months endedThree months ended
June 30, 2023March 31, 2023September 30, 2023June 30, 2023
(in millions)(in millions)
Oil, natural gas and NGL salesOil, natural gas and NGL sales$447 $715 Oil, natural gas and NGL sales$510 $447 
Net gain from commodity derivatives31 42 
Sales of purchased natural gas72 184 
Net (loss) gain from commodity derivativesNet (loss) gain from commodity derivatives(204)31 
Marketing of purchased natural gasMarketing of purchased natural gas78 72 
Electricity salesElectricity sales34 68 Electricity sales67 34 
Other revenueOther revenue15 Other revenue
Total operating revenuesTotal operating revenues$591 $1,024 Total operating revenues$460 $591 

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $510 million for the three months ended September 30, 2023, which is an increase of $63 million compared to $447 million for the three months ended June 30, 2023, which is a decrease of $268 million compared to $715 million for the three months ended March 31, 2023. This decreaseincrease was primarily due to lowerhigher realized prices for the secondthird quarter of 2023, partially offset by lower oil production volumes as shown in the table below. The effect of cash settlements on our commodity derivative contracts is not included in the table below.
OilNGLsNatural GasTotalOilNGLsNatural GasTotal
(in millions)(in millions)
Three months ended March 31, 2023$390 $62 $263 $715 
Three months ended June 30, 2023Three months ended June 30, 2023$362 $42 $43 $447 
Changes in realized pricesChanges in realized prices(15)(18)(221)(254)Changes in realized prices49 17 69 
Changes in productionChanges in production(13)(2)(14)Changes in production(9)(6)
Three months ended June 30, 2023$362 $42 $43 $447 
Three months ended September 30, 2023Three months ended September 30, 2023$402 $47 $61 $510 
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 ourNet (loss) gain from commodity derivative contracts is not included in the table above. Payments onderivatives— Net loss from commodity derivatives were $63was $204 million for the three months ended JuneSeptember 30, 2023 compared to $65 million for the three months ended March 31, 2023. Including the effectnet gain of settlement payments for commodity derivatives, our oil, natural gas and NGL sales decreased by $266 million compared to the three months ended March 31, 2023.

Net gain from commodity derivatives — Net gain from commodity derivatives was $31 million for the three months ended June 30, 2023 compared to $42 million for the three months ended March 31, 2023. The changenet loss from commodity derivatives 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:curves at the end of each measurement period.
Three months ended
June 30, 2023March 31, 2023
(in millions)
Non-cash commodity derivative gain$94 $107 
Net cash payments on settled commodity derivatives(63)(65)
     Net gain from commodity derivatives$31 $42 

Sales of purchased natural gas — Sales of purchased natural gas relatesPayments on commodity derivatives were $95 million for the three months ended September 30, 2023 compared 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 $72$63 million for the three months ended June 30, 2023, a decrease2023. Including the effect of $112settlement payments for commodity derivatives, the price received for our oil, natural gas and NGL sales decreased by $31 million from $184 million duringcompared to the three months ended March 31,June 30, 2023. The decrease was primarily the result of lower market prices for natural gas. Our natural gas
Three months ended
September 30, 2023June 30, 2023
(in millions)
Non-cash commodity derivative (loss) gain$(109)$94 
Net cash payments on settled commodity derivatives(95)(63)
     Net (loss) gain from commodity derivatives$(204)$31 

Electricity sales net of related purchased natural gas expense were $45— Electricity sales increased by $33 million to $67 million for the three months ended JuneSeptember 30, 2023 compared to $60 million for the three months ended March 31, 2023.

31


Electricity sales — Electricity sales decreased by $34 million to $34 million for the three months ended June 30, 2023 compared to $68 million for the three months ended March 31, 2023 predominately due to higher power prices during the firstthird quarter of 2023.

32


The following table presents our operating and non-operating expenses and income for the three months ended JuneSeptember 30, 2023 and March 31,June 30, 2023:

Three months endedThree months ended
June 30, 2023March 31, 2023September 30, 2023June 30, 2023
(in millions)(in millions)
Operating expensesOperating expensesOperating expenses
Energy operating costsEnergy operating costs$58 $125 Energy operating costs$74 $58 
Gas processing costsGas processing costsGas processing costs
Non-energy operating costsNon-energy operating costs123 124 Non-energy operating costs117 123 
General and administrative expensesGeneral and administrative expenses71 65 General and administrative expenses65 71 
Depreciation, depletion and amortizationDepreciation, depletion and amortization56 58 Depreciation, depletion and amortization56 56 
Asset impairment— 
Taxes other than on incomeTaxes other than on income42 42 Taxes other than on income48 42 
Exploration expenseExploration expenseExploration expense— 
Purchased natural gas expense27 124 
Purchased natural gas marketing expensePurchased natural gas marketing expense31 27 
Electricity generation expensesElectricity generation expenses13 49 Electricity generation expenses23 13 
Transportation costsTransportation costs16 17 Transportation costs16 16 
Accretion expenseAccretion expense11 12 Accretion expense12 11 
Other operating expenses, netOther operating expenses, net21 13 Other operating expenses, net28 21 
Total operating expensesTotal operating expenses444 638 Total operating expenses475 444 
Gain on asset divestituresGain on asset divestitures— Gain on asset divestitures— — 
Operating income147 393 
Operating (loss) incomeOperating (loss) income(15)147 
Non-operating (expenses) incomeNon-operating (expenses) incomeNon-operating (expenses) income
Interest and debt expenseInterest and debt expense(14)(14)Interest and debt expense(15)(14)
Loss from investment in unconsolidated subsidiaryLoss from investment in unconsolidated subsidiary(1)(2)Loss from investment in unconsolidated subsidiary(3)(1)
Other non-operating (expense) income(1)
Income before income taxes135 376 
Income tax provision(38)(75)
Net income$97 $301 
Other non-operating incomeOther non-operating income
(Loss) income before income taxes(Loss) income before income taxes(30)135 
Income tax benefit (provision)Income tax benefit (provision)(38)
Net (loss) incomeNet (loss) income$(22)$97 

Energy operating costs — Energy operating costs for the three months ended JuneSeptember 30, 2023 were $58$74 million, which was a decreasean increase of $67$16 million from $125$58 million for the three months ended March 31,June 30, 2023. This decreaseincrease was a result of lowerhigher natural gas prices in the secondthird quarter of 2023. For more information on our natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs includes $3for the three months ended September 30, 2023 were $117 million compared to $123 million for the three months ended June 30, 2023, which is a decrease of $6 million primarily due to a reduction in downhole maintenance activity. Non-energy operating costs include $2 million and $1$3 million of stock-based compensation expense related to our cash-settled awards for the three months ended JuneSeptember 30, 2023 and March 31,June 30, 2023, respectively. See General and administrative expenses below for additional information on our stock-based compensation awards.

3233


General and administrative expenses — General and administrative (G&A) expenses were $65 million for the three months ended September 30, 2023, which was a decrease of $6 million from $71 million for the three months ended June 30, 2023, which was an increase of $6 million from $65 million for the three months ended March 31, 2023. The increasedecrease in G&A expenses was primarily attributable to a reduction in compensation-related expenses including accelerated vesting for certain departing employees and new stock-based compensation awards granted. Stock-based compensation awards are discussed further below.following a headcount reduction in August 2023.

The table below shows G&A expenses for our exploration and production business (including unallocated corporate overhead and other) separately from our carbon management business. The amounts shown for our carbon management business do not include expenses borne by the Carbon TerraVault JV.

Three months endedThree months ended
June 30, 2023March 31, 2023September 30, 2023June 30, 2023
(in millions)(in millions)
Exploration and production, corporate and otherExploration and production, corporate and other$68 $62 Exploration and production, corporate and other$61 $68 
Carbon management businessCarbon management businessCarbon management business
Total general and administrative expensesTotal general and administrative expenses$71 $65 Total general and administrative expenses$65 $71 

Stock-based compensation awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period. Grants of equity-settled awards in 2021 contemplated that no corresponding grants would be made in 2022. Additional grants were made in 2023.

Changes in our stock price introduce volatility in our results of operations because we pay half of our cash-settled awards based on our stock price performance and we adjust our obligation for unvested cash-settled awards at the end of each reporting period. Equity-settled awards are not similarly adjusted for changes in our stock price.

Stock-based compensation included in G&A expense is shown in the table below:

Three months ended
September 30, 2023June 30, 2023
(in millions)
Cash-settled awards$$
Stock-settled awards
Total included in general and administrative expenses$10 $13 

Electricity generation expenses— Electricity generation expenses for the three months ended September 30, 2023 were $23 million, which was an increase of $10 million from $13 million for the three months ended June 30, 2023. This increase was primarily due to higher prices for natural gas.

Income taxes– The income tax benefit for the three months ended September 30, 2023 was $8 million (representing an effective tax rate of 27%), compared to a provision of $38 million (representing an effective tax rate of 28%) for the three months ended June 30, 2023.
34



Nine months ended September 30, 2023 compared to September 30, 2022

The following table presents our operating revenues for the nine months ended September 30, 2023 and 2022:
Nine months ended
September 30, 2023September 30, 2022
(in millions)
Oil, natural gas and NGL sales$1,672 $2,026 
Net loss from commodity derivatives(131)(419)
Marketing of purchased natural gas334 220 
Electricity sales169 171 
Other revenue31 27 
Total operating revenues$2,075 $2,025 

Oil, natural gas and NGL sales— Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,672 million for the nine months ended September 30, 2023, which is a decrease of $354 million compared to $2,026 million for the nine months ended September 30, 2022. This decrease was primarily due to changes in realized prices as shown in the table below, including lower realized prices for oil and NGLs, partially offset by higher realized prices for natural gas. The effect of cash settlements on our commodity derivative contracts is not included in the table below.
OilNGLsNatural GasTotal
(in millions)
Nine months ended September 30, 2022$1,527 $205 $294 $2,026 
Changes in realized prices(331)(55)101 (285)
Changes in production(42)(28)(69)
Nine months ended September 30, 2023$1,154 $151 $367 $1,672 
Note: See Production for volumes by commodity type and Prices and Realizations for index and realized prices for comparative periods.

Net loss from commodity derivatives— Net loss from commodity derivatives was $131 million for the nine months ended September 30, 2023 compared to a net loss of $419 million for the nine months ended September 30, 2022. The net loss from commodity derivatives primarily resulted from changes in the fair value of our outstanding commodity derivatives from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each measurement period.

Payments on commodity derivatives were $223 million for the nine months ended September 30, 2023 compared to payments of $604 million for the nine months ended September 30, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $27 million compared to the nine months ended September 30, 2022.
Nine months ended
September 30, 2023September 30, 2022
(in millions)
Non-cash commodity derivative gain$92 $185 
Net cash payments on settled commodity derivatives(223)(604)
     Net loss from commodity derivatives$(131)$(419)

Marketing of purchased natural gas— Marketing of purchased natural gas relates to natural gas acquired from third parties which is subsequently sold in connection with certain of our marketing activities. Marketing of purchased natural gas were $334 million for the nine months ended September 30, 2023, an increase of $114 million from $220 million during the nine months ended September 30, 2022. The increase was primarily the result of higher prices during 2023, which peaked in January 2023. Revenues from marketing of purchased natural gas net of related purchased natural gas marketing expense were $152 million for the nine months ended September 30, 2023 compared to $34 million for the nine months ended September 30, 2022.

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The following table presents our operating and non-operating expenses and income for the nine months ended September 30, 2023 and 2022:

Nine months ended
September 30, 2023September 30, 2022
(in millions)
Operating expenses
Energy operating costs$258 $243 
Gas processing costs14 13 
Non-energy operating costs364 330 
General and administrative expenses201 163 
Depreciation, depletion and amortization170 149 
Asset impairment
Taxes other than on income132 120 
Exploration expense
Purchased natural gas marketing expense182 186 
Electricity generation expenses85 99 
Transportation costs49 37 
Accretion expense35 32 
Other operating expenses, net62 28 
Total operating expenses1,557 1,405 
Gain on asset divestitures60 
Operating income525 680 
Non-operating (expenses) income
Interest and debt expense(43)(39)
Loss from investment in unconsolidated subsidiary(6)— 
Other non-operating income
Income before income taxes481 644 
Income tax provision(105)(203)
Net income$376 $441 

Energy operating costs — Energy operating costs for the nine months ended September 30, 2023 were $258 million, which was an increase of $15 million from $243 million for the nine months ended September 30, 2022. This increase was a result of higher prices in the nine months of 2023 compared to the same prior year period. For more information on our natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs were $364 million for the nine months ended September 30, 2023, which was an increase of $34 million from $330 million for the nine months ended September 30, 2022. The increase was predominately a result of higher downhole maintenance activity. Non-energy operating costs also includes $6 million and $3 million of stock-based compensation expense related to our cash-settled awards for the nine months ended September 30, 2023 and 2022, respectively. See General and administrative expenses below for additional information on our stock-based compensation awards.

General and administrative expenses — General and administrative (G&A) expenses were $201 million for the nine months ended September 30, 2023, which was an increase of $38 million from $163 million for the nine months ended September 30, 2022. The increase in G&A expenses was primarily attributable to compensation-related expenses, related to stock-based compensation awards granted in 2023 that had not been granted in 2022. Grants of equity-settled awards in 2021 following our emergence from bankruptcy contemplated that no corresponding grants would be made in 2022. G&A expenses also increased to a lesser extent due to increased headcount in our carbon management business, and higher spending to streamline our information technology infrastructure. Stock-based compensation awards are discussed further below.

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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 do not include expenses borne by the Carbon TerraVault JV.

Nine months ended
September 30, 2023September 30, 2022
(in millions)
Exploration and production, corporate and other$191 $153 
Carbon management business10 10 
Total general and administrative expenses$201 $163 

Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.

Changes in our stock price introduce volatility in our results of operations because we pay half of our cash-settled awards based on our stock price performance and we adjust our obligation for unvested cash-settled awards at the end of each reporting period. Equity-settled awards are not similarly adjusted for changes in our stock price.

Stock-based compensation included in G&A expense is shown in the table below:

Three months ended
June 30, 2023March 31, 2023
(in millions)
Cash-settled awards$$
Stock-settled awards
Total included in general and administrative expenses$13 $

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 $27 million of natural gas for marketing activities during the three months ended June 30, 2023, which was a decrease of $97 million from $124 million for the three months ended March 31, 2023. The decrease was predominantly the result of a decline in marketing activity and lower market prices in the three months ended June 30, 2023 compared to the three months ended March 31, 2023. 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 June 30, 2023 were $13 million, which was a decrease of $36 million from $49 million for the three months ended March 31, 2023. This decrease was primarily due to lower prices for natural gas.

Income taxes – The income tax provision for the three months ended June 30, 2023 was $38 million (effective tax rate of 28%), compared to $75 million (effective tax rate of 20%) for the three months ended March 31, 2023. Excluding the effect of the change in valuation allowance, our effective tax rate would have been 28% in the three months ended March 31, 2023. See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more information on a valuation allowance related to our Lost Hills divestiture.
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Six months ended June 30, 2023 compared to June 30, 2022

The following table presents our operating revenues for the six months ended June 30, 2023 and 2022:
Six months ended
June 30, 2023June 30, 2022
(in millions)
Oil, natural gas and NGL sales$1,162 $1,346 
Net gain (loss) from commodity derivatives73 (662)
Sales of purchased natural gas256 107 
Electricity sales102 83 
Other revenue22 26 
Total operating revenues$1,615 $900 

Oil, natural gas and NGL sales — Oil, natural gas and NGL sales, excluding the effects of cash settlements on our commodity derivative contracts, were $1,162 million for the six months ended June 30, 2023, which is a decrease of $184 million compared to $1,346 million for the six months ended June 30, 2022. This decrease was primarily due to changes in realized prices as shown in the table below, including lower realized prices for oil and NGLs partially offset by higher realized prices for natural gas.
OilNGLsNatural GasTotal
(in millions)
Six months ended June 30, 2022$1,033 $139 $174 $1,346 
Changes in realized prices(266)(42)155 (153)
Changes in production(15)(23)(31)
Six months ended June 30, 2023$752 $104 $306 $1,162 
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 $128 million for the six months ended June 30, 2023 compared to payments of $422 million for the six months ended June 30, 2022. Including the effect of settlement payments for commodity derivatives, our oil, natural gas and NGL sales increased by $110 million compared to the six months ended June 30, 2022.

Net gain (loss) from commodity derivatives — Net gain from commodity derivatives was $73 million for the six months ended June 30, 2023 compared to a net loss of $662 million for the six months ended June 30, 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:
Six months ended
June 30, 2023June 30, 2022
(in millions)
Non-cash commodity derivative gain (loss)$201 $(240)
Net cash payments on settled commodity derivatives(128)(422)
     Net gain (loss) from commodity derivatives$73 $(662)

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 $256 million for the six months ended June 30, 2023, an increase of $149 million from $107 million during the six months ended June 30, 2022. The increase was primarily the result of higher marketing activity and higher market prices in 2023. Our natural gas sales net of related purchased natural gas expense were $105 million for the six months ended June 30, 2023 compared to $19 million for the six months ended June 30, 2022.

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Electricity sales — Electricity sales increased by $19 million to $102 million for the six months ended June 30, 2023 compared to $83 million for the six months ended June 30, 2022. The increase was predominately a result of higher power prices in the first quarter of 2023 compared to the prior year. Our electricity sales net of electricity generation expenses were $40 million for the six months ended June 30, 2023 compared to $26 million for the six months ended June 30, 2022.

The following table presents our operating and non-operating expenses and income for the six months ended June 30, 2023 and 2022:

Six months ended
June 30, 2023June 30, 2022
(in millions)
Operating expenses
Energy operating costs$183 $150 
Gas processing costs10 
Non-energy operating costs247 213 
General and administrative expenses136 104 
Depreciation, depletion and amortization114 99 
Asset impairment
Taxes other than on income84 76 
Exploration expense
Purchased natural gas expense151 88 
Electricity generation expenses62 57 
Transportation costs33 24 
Accretion expense23 22 
Other operating expenses, net34 23 
Total operating expenses1,082 869 
Gain (loss) on asset divestitures58 
Operating income540 89 
Non-operating (expenses) income
Interest and debt expense(28)(26)
Loss from investment in unconsolidated subsidiary(3)— 
Other non-operating (expense) income
Income before income taxes511 65 
Income tax provision(113)(50)
Net income$398 $15 

Energy operating costs — Energy operating costs for the six months ended June 30, 2023 were $183 million, which was an increase of $33 million from $150 million for the six months ended June 30, 2022. This increase was a result of higher prices in the first six months of 2023 compared to the same prior year period. For more information on our natural gas market prices, see Prices and Realizations above.

Non-energy operating costs — Non-energy operating costs were $247 million for the six months ended June 30, 2023, which was an increase of $34 million from $213 million for the six months ended June 30, 2022. The increase was predominately a result of higher downhole maintenance activity. Non-energy operating costs also includes $4 million and $2 million of stock-based compensation expense related to our cash-settled awards for the six months ended June 30, 2023 and 2022, respectively. See General and administrative expenses below for additional information on our stock-based compensation awards.
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General and administrative expenses — General and administrative (G&A) expenses were $136 million for the six months ended June 30, 2023, which was an increase of $32 million from $104 million for the six months ended June 30, 2022. The increase in G&A expenses was primarily attributable to compensation-related expenses, including stock-based compensation awards granted in 2023, and higher spending on information technology infrastructure. Stock-based compensation awards are discussed further below.

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 do not include expenses borne by the Carbon TerraVault JV.

Six months ended
June 30, 2023June 30, 2022
(in millions)
Exploration and production, corporate and other$130 $99 
Carbon management business
Total general and administrative expenses$136 $104 

Awards are granted under our stock-based compensation plans to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash. Our equity-settled awards granted to executives include performance stock units and restricted stock units that either cliff vest at the end of a two- or three-year period or vest ratably over a two- or three-year period. Our equity-settled awards granted to non-employee directors are restricted stock units that vest ratably over a three-year period. Our cash-settled awards granted to non-executive employees vest ratably over a three-year period.

Changes in our stock price introduce volatility in our results of operations because we pay half of our cash-settled awards based on our stock price performance and we adjust our obligation for unvested cash-settled awards at the end of each reporting period. Equity-settled awards are not similarly adjusted for changes in our stock price.

Stock-based compensation included in G&A expense is shown in the table below:

Six months endedNine months ended
June 30, 2023June 30, 2022September 30, 2023September 30, 2022
(in millions)(in millions)
Cash-settled awardsCash-settled awards$$Cash-settled awards$11 $
Stock-settled awardsStock-settled awards14 Stock-settled awards21 13 
Total included in general and administrative expensesTotal included in general and administrative expenses$22 $12 Total included in general and administrative expenses$32 $19 

Depreciation, depletion and amortization — Depreciation, depletion and amortization (DD&A) increased $15$21 million to $114$170 million for the sixnine months ended JuneSeptember 30, 2023 from $99$149 million for the sixnine months ended JuneSeptember 30, 2022. The increase was primarily due to a change in our DD&A rates which are periodically adjusted to reflect current reserve estimates.

Purchased natural gas expenseTaxes other than on incomePurchased natural gas expense relates to natural gas acquired from third parties in connection with certain of our marketing activities. We purchased $151Taxes other than on income were $132 million of natural gas for marketing activities during the sixnine months ended JuneSeptember 30, 2023, which was an increase of $63$12 million from $88$120 million for the sixnine months ended JuneSeptember 30, 2022. The increase was predominantlyprimarily related to higher ad valorem taxes in 2023.

Electricity generation expense — Electricity generation expenses for the nine months ended September 30, 2023 were $85 million, which was a decrease of $14 million from $99 million for the same prior year period. This decrease was primarily due to lower prices for natural gas.

Transportation costs— Transportation costs increased by $12 million to $49 million for the nine months ended September 30, 2023 from $37 million for the nine months ended September 30, 2022. The increase in transportation costs was a result of higher natural gas marketing activity levelsactivities.

Other operating expenses, net — Other operating expenses, net were $62 million for the nine months ended September 30, 2023, which was an increase of $34 million from $28 million during the same prior year period. The increase was primarily related to costs to implement operational efficiencies in 2023, including severance, and higher market prices inexpenses related to our carbon management.

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The table below shows other operating expenses, net for our exploration and production business (including unallocated corporate overhead and other) separately from our carbon management business. Carbon management expenses include lease cost for carbon sequestration easements, advocacy, technical evaluation of carbon storage and other startup related costs. The amounts shown for our carbon management business do not include expenses borne by the six months ended June 30, 2023 compared to the six months ended June 30, 2022. For more information on our natural gas market prices, see Carbon TerraVault JV.

Prices and Realizations above.
Nine months ended September 30,
20232022
(in millions)
Exploration and production, corporate and other$41 $25 
Carbon management business21 
Total other operating expenses, net$62 $28 

Income taxes – The income tax provision for the sixnine months ended JuneSeptember 30, 2023 was $113$105 million (effective(representing an effective tax rate of 22%), compared to $50$203 million (effective(representing an effective tax rate of 77%32%) for the sixnine months ended JuneSeptember 30, 2022. The income tax provision for the sixnine months ended JuneSeptember 30, 2022 included a valuation allowance related to our Lost Hills divestiture that was released in the sixnine months ended JuneSeptember 30, 2023. See Part I, Item 1 – Financial Statements, Note 6 Income Taxes for more information on a valuation allowance related to our Lost Hills divestiture.

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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. 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 sixnine months ended JuneSeptember 30, 2023 were for capital investments, repurchases of our common stock and dividends. Refer to Part I, Item 1 – Financial Statements, Note 3 Debt for information on repurchases of our Senior Notes. In October 2023, we repurchased an additional $30 million of our Senior Notes at an average price of 100.50% of par. Following these repurchases, the remaining principal amount of our outstanding Senior Notes is $565 million.

The following table summarizes our liquidity:
JuneSeptember 30, 2023
(in millions)
Cash and cash equivalents$448479 
Revolving Credit Facility:
Borrowing capacity(a)
627 
Outstanding letters of credit(148)
Availability$479 
Liquidity$927958 
(a)As part of the October 30, 2023 amendment to our Revolving Credit Facility, our borrowing capacity increased by $3 million to $630 million.

In April 2023 weWe recently amended our Revolving Credit Facility and our borrowing base was reaffirmed at $1.2 billion. Seeas described in Part I, Item 1 – Financial Statements, Note 3 Debt and Note 13 Subsequent Events, and continue to evaluate refinancing options for more information onour Senior Notes. We also intend to pursue financing options for our carbon management business that are separate from the amendment torest of our Revolving Credit Facility.business.

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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) repurchase outstanding indebtedness, (iv) advance carbon management activities, or (v) maintain cash and cash equivalents 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 sixnine months ended JuneSeptember 30, 2023, our operating cash flow increased $77decreased $54 million to $418$522 million from $341$576 million in the same period in 2022. The increasesdecreases in operating cash flow for the sixnine months ended JuneSeptember 30, 2023 primarily relates to higherlower average realized natural gasoil prices (increasing sales revenue from the natural gas we produce and margins on our marketing and trading activities)as well as production volumes 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:

Six months ended
June 30,
Nine months ended
September 30,
2023202220232022
(in millions)(in millions)
Capital investmentsCapital investments$(86)$(197)Capital investments$(119)$(304)
Changes in accrued capital investmentsChanges in accrued capital investments(15)Changes in accrued capital investments(10)
Proceeds from divestitures, netProceeds from divestitures, net— 76 Proceeds from divestitures, net— 79 
AcquisitionsAcquisitions(1)(17)Acquisitions(1)(17)
Distribution related to the Carbon TerraVault JVDistribution related to the Carbon TerraVault JV— 12 
Capitalized joint venture transaction costsCapitalized joint venture transaction costs— (12)
Other, netOther, net(3)— Other, net(3)(1)
Net cash used in investing activitiesNet cash used in investing activities$(105)$(129)Net cash used in investing activities$(133)$(238)

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

Six months ended
June 30,
Nine months ended
September 30,
2023202220232022
(in millions)(in millions)
Repurchases of common stockRepurchases of common stock$(123)$(167)Repurchases of common stock$(143)$(247)
Common stock dividendsCommon stock dividends(40)(26)Common stock dividends(59)(39)
Issuance of common stockIssuance of common stock$— Issuance of common stock$
Debt amendment costsDebt amendment costs(8)$— Debt amendment costs(8)$— 
Debt repurchasesDebt repurchases(5)$— 
Shares cancelled for taxesShares cancelled for taxes(2)$— Shares cancelled for taxes(3)$— 
Net cash used in financing activitiesNet cash used in financing activities$(172)$(193)Net cash used in financing activities$(217)$(285)

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$185 and $245$210 million under current conditions with heavier weighting in the second half of the year due to timing of projects and higher expectedcontinuing focus on high return workover activity and facilities projects. We expectFor the remainder of 2023, we will execute a one rig program in the Los Angeles basin. Our level of spending in the fourth quarter of 2023 includes procuring critical components for planned maintenance at our capital program relatedpower plant and a gas processing facility at Elk Hills in 2024 as well as incremental spending to oil and natural gas development to continue to be focused primarily on executing projects using existing permits outside of Kern County.advance our carbon management business.

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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 EstimateSixNine months ended JuneSeptember 30, 2023
(in millions)
Oil and natural gas operations$165 155 - $195170$75106 
Carbon management business5 - 1510
Corporate and other3025 - 35301012 
Total Capital$200 185 - $245210$86119 

We recently amended and extended our Revolving Credit Facility as described in Part I, Item 1 – Financial Statements, Note 3 Debt, and continue to evaluate refinancing options for our Senior Notes. 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 JuneSeptember 30, 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 JuneSeptember 30, 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.

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Dividends

On April 28, 2023, ourOur Board of Directors declared a quarterlythe following cash dividenddividends in each of $0.2825 per share of common stock. The dividend was payable to shareholders of record at the close of business on June 1, 2023 and was paid on June 16, 2023.periods presented.

On July 28, 2023, our Board of Directors declared a quarterly cash dividend of $0.2825 per share of common stock. The dividend is payable to shareholders of record at the close of business on September 1, 2023 and is expected to be paid on September 15, 2023.
Total DividendRate Per Share
(in millions)($ per share)
2023
Three months ended March 31, 2023$20 $0.2825 
Three months ended June 30, 202320 $0.2825 
Three months ended September 30, 202319 $0.2825 
Nine months ended September 30, 2023$59 
2022
Three months ended March 31, 2022$13 $0.1700 
Three months ended June 30, 202213 $0.1700 
Three months ended September 30, 202213 $0.1700 
Nine months ended September 30, 2022$39 

The 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. For information regarding past dividends paid, see Cash Flow Analysis, Cash Flow Used in Financing Activities above. See Note 13 Subsequent Events for information regarding a recent increase to our dividend policy.

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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 totalaggregate value of shares that may yet be purchased under the Share Repurchase Program totaled $517
$497 million, excluding commissions and excise taxes on repurchases, as of JuneSeptember 30, 2023. The following is a summary of our share repurchases, held as treasury stock for the periods presented:

Total Number of Shares PurchasedTotal Value of Shares PurchasedAverage Price Paid per Share
(number of shares)(in millions)($ per share)
Three months ended June 30, 20222,255,445 $96 $42.57 
Three months ended June 30, 20231,618,746 $64 $39.12 
Six months ended June 30, 20223,923,901 $167 $42.55 
Six months ended June 30, 20233,042,510 $123 $40.12 
Inception of Program (May 2021) through June 30, 202314,498,770 $584 $40.18 
Total Number of Shares PurchasedTotal Value of Shares PurchasedAverage Price Paid per Share
(number of shares)(in millions)($ per share)
Three months ended September 30, 20221,921,181 $80 $41.78 
Three months ended September 30, 2023365,145 $20 $54.75 
Nine months ended September 30, 20225,845,082 $247 $42.29 
Nine months ended September 30, 20233,407,655 $143 $41.69 
Inception of Program (May 2021) through September 30, 202314,863,915 $604 $40.53 
Note: The total value of shares purchased includes approximately $1 million in the sixnine months ended JuneSeptember 30, 2023 related to excise taxes on share repurchases, which was effective beginning in 2023. Commissions paid were not significant in all periods presented.

Divestitures and Acquisitions

See Part I, Item 1 – Financial Statements, Note 7 Divestitures and Acquisitions for information on our transactions during the three and sixnine months ended JuneSeptember 30, 2023 and 2022.

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 at JuneSeptember 30, 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.

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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.
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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 warwars in Ukraine and Israel 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;
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uncertainty around the accounting of emissions and our ability to successfully
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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.
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Item 3Quantitative and Qualitative Disclosures About Market Risk

For the three and sixnine months ended JuneSeptember 30, 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 JuneSeptember 30, 2023, we had a net liability of $18$138 million for our commodity derivative positions which are carried at fair value. For more information on our derivative positions as of JuneSeptember 30, 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 JuneSeptember 30, 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 JuneSeptember 30, 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 JuneSeptember 30, 2023. Our Senior Notes bear interest at a fixed rate of 7.125% per annum.

Item 4 Controls and Procedures

Our Chief Executive Officer and Chief 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 and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of JuneSeptember 30, 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 JuneSeptember 30, 2023 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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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.

On September 14, 2023, the Center for Biological Diversity filed a writ petition against the City of Long Beach and the State of California, naming us and our subsidiary, the THUMS Long Beach Company, as Real Parties in Interest. The Petition generally alleges that the City of Long Beach, the Long Beach City Council, and the California State Lands Commission violated the California Environmental Quality Act by failing to evaluate the environmental impacts of certain activities (drilling and injection) authorized under Long Beach’s 2023 Annual Plan and 2023-2028 Program Plan for the Long Beach Unit, both of which received final approval in May 2023. The Petition seeks the setting aside of the approvals of the Plans and the enjoinment of any activities described thereunder until the requirements of CEQA are met; namely that an environmental review is completed. We believe the City and the State have strong defenses and we intend to vigorously defend against the Petition as a Real Party in Interest. However, we cannot predict the ultimate outcome of this action with certainty.

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 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2023 and June 30, 2023. Except as set forth below, there were no material changes to those risk factors during the three months ended JuneSeptember 30, 2023.

Our business is highly regulatedRecent action by the State of California imposing additional financial assurance requirements related to plugging and government authorities can delayabandonment costs, decommissioning, and site restoration on those who acquire the right to operate wells and production facilities could impact our ability to sell or deny permitsacquire assets in the state of California or increase our costs in connection with the same.

On October 7, 2023, the California Governor signed into law Assembly Bill 1167 (AB 1167), which imposes more stringent financial assurance requirements on persons who acquire the right to operate a well or production facility in the state of California, requiring them to file either an individual indemnity bond for single-well or production facility acquisitions, or a blanket indemnity bond for multiple wells or production facilities. The bond imposed on the acquirer will be in an amount determined by the state to sufficiently cover plugging and approvalsabandonment costs, decommissioning, and site restoration, and AB 1167 prohibits the closing of any acquisition of a well or changeproduction facility until a determination on the appropriate bond amount has been completed by the state and the bond has been filed. We are still assessing the impact of AB 1167. In addition, although AB 1167 has been signed into law, Governor Newsom has called for further legislative changes to these new requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delayto mitigate against the potential risk of the implementation of our business plans.

Our operations are subject to complex and stringent federal, state, local and other laws and regulations relatingAB 1167 ultimately increasing the number of orphaned idle or low-producing wells in California. However, we cannot predict what form these changes may ultimately take or if the legislature will act on the Governor’s request. Implementation of this law may lead to the exploration and development of our properties, as well as the production, transportation, marketing and sale of our products.

To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local government authorities for a variety of activities including siting, drilling, completion, stimulation, operation, inspection, maintenance, transportation, storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and threateneddelay or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection and disposal and water consumption, recycling and reuse. For example, our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans. These operations are subject to regulation by both the City of Long Beach and CalGEM. We are currently in discussions with the City of Long Beach and CalGEMadditional costs with respect to what injection well pressure gradient complies with CalGEM’s requirements for the protection of underground sources of drinking water while at the same time mitigating subsidence risks. CalGEM's local office has preliminarily indicated that the injection well pressure gradient should be reduced from the gradient that has been used for several decades. As part ofacquisitions or dispositions, which could impact our ongoing discussions, we and the City of Long Beach have provided CalGEM with technical information regarding how the historical injection well pressure gradient complies with CalGEM's requirements and to inform them of the absence of risk of leakage. CalGEM has proposed a meeting for CRC and the City of Long Beach to present their technical findings in more detail, to occur in or around August 2023. As part of that meeting, and subject to its outcome, CalGEM has also proposed that CRC and the City of Long Beach present a work plan for the reduction of injection pressures over a six-month period to levels acceptable to CalGEM. We are in the process of preparing a response and continue to believe that existing injection pressures address subsidence risks and are protective of underground sources of drinking water. If CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient, and we were unable to reverse that decision on appeal or other legal challenge, we expect that any material reduction in injection well pressure gradient for our operations in the Wilmington Oil Field would result in a decrease in production and reserves from the field.

Failure to comply may result in the assessment of administrative, civil and/or criminal fines and penalties, liability for noncompliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or prohibiting certain operations or our access to property, water, minerals or other necessary resources, and may otherwise delay or restrict our operations and cause us to incur substantial costs. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.

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Our ability to timely obtain and maintain permits for our operations, including from CalGEM, has from time to time been subject to significant delays and uncertainties and is subject to factor our control. These factors include changes in agency practices,grow or explore new regulations,strategic areas – or legal challenges to existing approvals for our operations from individual citizens and non-governmental organizations. For example, beginning in 2021, CalGEM ceased issuing new well stimulation permits and has slowedexit others – within the approvalstate of new drill permits even as it continues approving plugging and workovers. In addition, in 2020 a group of plaintiffs challenged in court the ability of Kern County to issue well permits in reliance on an existing Environmental Impact Report (EIR). See Part I, Item 1 and 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities. We can also provide no assurances that we will always be able to successfully navigate these risks and timely obtain permits or obtain them on favorable terms. While we have existing permits that will allow us to run a modified drilling program in 2023, we are unlikely to be able to offset projected oil production declines over the same period.

Changes to elected or appointed officials or their priorities and policies could result in different approaches to the regulation of the oil and natural gas industry. We cannot predict the actions the Governor of California or the California legislature may take with respect to the regulation of our business, the oil and natural gas industry or the state’s economic, fiscal or environmental policies, nor can we predict what actions may be taken at the federal level with respect to health, environmental safety, climate, labor or energy laws, regulations and policies, including those that may directly or indirectly impact our operations. For additional information, see Part I, Item 1 & 2 – Business and Properties, Regulation of the Industries in Which We Operate, Regulation of Exploration and Production Activities and the Risk factor entitled "Our business is highly regulated and government authorities can delay or deny permits and approvals or change requirements governing our operations, including hydraulic fracturing and other well stimulation methods, enhanced production techniques and fluid injection or disposal, that could increase costs, restrict operations and change or delay the implementation of our business plans" in our 2022 Annual Report.California.

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.

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Our share repurchase activity for the three months ended JuneSeptember 30, 2023 was as follows:

PeriodTotal Number of Shares PurchasedAverage Price Paid per ShareTotal 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)
April 1, 2023 - April 30, 2023542,465 $39.60 542,465 $— 
May 1, 2023 - May 31, 2023449,631 $39.70 449,631— 
June 1, 2023 - June 30, 2023626,650 $38.28 626,650— 
Total1,618,746 $39.12 1,618,746$— 
PeriodTotal Number of Shares PurchasedAverage Price Paid per ShareTotal 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)
July 1, 2023 - July 31, 2023— $— — $— 
August 1, 2023 - August 31, 2023365,145 $54.75 365,145— 
September 1, 2023 - September 30, 2023— $— — — 
Total365,145 $54.75 365,145$— 
(a)The total value of shares that may yet be purchased under the Share Repurchase Program totaled $517$497 million as of JuneSeptember 30, 2023.

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Item 5     Other Disclosures

Rule 10b5-1 Trading Arrangements
As previously disclosed, on June 16,
During the three months ended September 30, 2023, Omar Hayat was appointed to the position Executive Vice President — Operations. In connection with this appointment, the Company and Mr. Hayat entered into an employment agreement, effective July 27, 2023, providing for the following: (i)none of our directors or officers adopted or terminated a base salary“Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of $400,000, (ii) an annual cash bonus with a target value equal to 100% of his annual base salary; (iii) participation in those benefit plans and programs of the Company available to similarly situated executives; (iv) reimbursement for reasonable business-related expenses, subject to the Company’s business expense reimbursement policy; and (v) annual long-term incentive awards (expected to be comprised 60% of performance stock units and 40% of restricted stock units) under the Company’s 2021 Long-Term Incentive Plan (as amended, the “LTIP”) with a target grant value of 400% of Mr. Hayat’s base salary as in effect on the applicable grant date, commencing in calendar year 2024. The performance stock unit awards are expected to vest over a three-year cliff vesting period beginning on the date of grant, and the restricted stock units are expected to vest in three equal installments over a three-year vesting period beginning on the date of grant. The terms and conditions of his LTIP awards will be governed by individual award agreements to be entered into between the Company and Mr. Hayat in connection with the grant of those LTIP awards. He will continue to be a participant in the Company’s Executive Severance Plan.Regulation S-K.

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Item 6 Exhibits
3.1
3.2
3.3
3.4
10.110.1*,**
10.2**
10.3*,**
10.4*,**
31.1*
31.2*
32.1*
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.
104Cover Page Interactive Data File (formatted in inline XBRL and contained in Exhibits 101).
* - Filed or furnished herewith
**Certain portions of this exhibit (indicated by "[*****]") have been omitted pursuant to Item 601(b)(10) of Regulation S-K
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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:August 1,November 2, 2023/s/ Noelle M. Repetti 
 Noelle M. Repetti 
 Senior Vice President and Controller 
(Principal Accounting Officer)

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