California Resources Annual Report 2022

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FY2022 Annual Report · California Resources

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ANNUAL REPORT 2022

$
$
$
$
$

$
$
$
$

$
$
$

4.95

6.10

6.75

7.37

2022

2021

$
$
$
$

$
$
$
$
$

690
379
311
(371)

660
194
466
(222)

FINANCIAL HIGHLIGHTS

1,889
625
13
612
506

2,707
524
0
524
384

Total Assets
Long-Term Debt, Net
Equity

Dollar amounts in millions, except share and per-share amounts, as of and for the years ended December 31,

Net Cash Provided by Operating Activities
Capital Investments
Free Cash Flow(a)
Net Cash Used in Financing Activities

Net Income (Loss) Attributable to Common
Stock per Share – Diluted
Adjusted Net Income (Loss) Attributable to Comman Stock(a)
per Share – Diluted

Total Operating Revenue
Net Income
Net Income Attributable to Noncontrolling Interests
Net Income (Loss) Attributable to Common Stock
Adjusted Net Income (Loss) Attributable to Common Stock(a)

HIGHLIGHTS

2
2FINANCIAL & OPERATIONAL
2
0
0
2

Net Mineral Acreage (in thousands):
Developed
Undeveloped
Total

Average Realized Prices:
Oil with hedge ($/Bbl)
Oil without hedge ($/Bbl)
NGLs ($/Bbl)
Natural Gas ($/Mcf)

Production:
Oil (MBbl/d)
NGLs (MBbl/d)
Natural Gas (MMcf/d)
Total (MBoe/d)(b)

Weighted-Average Shares Outstanding - Diluted
Year-End Shares

Standardized Measure of Discounted Future
Net Cash Flows (in billions)

Reserves:
Oil (MMBbl)
NGLs (MMBbl)
Natural Gas (Bcf)
Total (MMBoe)(b)

OPERATIONAL HIGHLIGHTS

PV-10 of Cash Flows (in billions)(a)

61.80
98.26
64.33
7.68

56.05
70.43
53.62
4.22

83.0
79.3

77.6
71.9

Closing Share Price

699
1,192
1,891

689
1,178
1,867

3,967
592
1,864

3,846
589
1,688

60
13
159
100

343
41
576
480

294
38
511
417

55
11
147
91

$
$
$
$

2021

2022

43.51

42.71

$
$
$

9.2

6.7

6.2

4.5

$
$
$
$

2020 Combined*

1,559
1,871
105
1,766
(257)

—

106
47
59
(58)

3,074
597
1,182

—
83.3

2020 Combined*

69
13
172
111

43.53
41.89
27.63
2.28

313
41
527
442

1.9

2.4

717
1,388
2,105

23.59

*Note: 2020 represents the combined successor and predecessor periods as defined in Note 1 - Nature of Business, Summary of Significant Accounting Policies and Other.
(a) Please see crc.com, Investor Relations for copies of CRC's earnings releases and Annual Reports filed on Form 10-K that include a discussion of these performance and non-GAAP measures, including a reconcililation to the most
closely related GAAP measure or information on the related calculations.
(b) Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
This report contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. For a discussion of these risks and
uncertainties, please refer to the “Risk Factors” and “Forward-Looking Statements” described in our Annual Report on Form 10-K. Words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “goal,” “intend,”
“likely,” “may,” “might,” “plan,” “potential,” “project,” “seek,” “should,” “target,” “will” or “would” and similar words that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any
forward-looking statement speaks only as of the date on which such statement is made and we undertake no obligation to correct or update any forward-looking statement, except as required by applicable law.

A MESSAGE TO OUR SHAREHOLDERS

Dear Shareholders,

During 2022 we demonstrated the adaptability of our teams, resilience of our assets and

optionality of our portfolio. Despite inflationary pressures and an evolving regulatory environment, we
remained focused on developing our core low-decline assets in the San Joaquin and Los Angeles
basins to deliver some of the lowest carbon intensity barrels in the United States. We generated
91,000 barrels of oil equivalent per day and delivered record operating cash flow and operating margin.

We generated $690 million of operating cash flow, $311 million of free cash flow and returned over

100% of that free cash flow to shareholders through dividends and share repurchases. Since the
inception of our share repurchase program in 2021 through year-end 2022, CRC has acquired nearly
14% of our common stock, demonstrating our commitment to shareholder returns.

We also continued to advance our carbon management business. Building off momentum created

in 2021, we filed two additional Class VI permits and now have storage applications representing a
cumulative total of approximately 140 million metric tons of carbon storage. We also created a joint
venture (JV) with Brookfield Renewable targeting sequestration of 5 million metric tons of carbon
dioxide. The unique structure of the JV, in which Brookfield may contribute $10 per ton for its 49%
share of storage assets under development, provides a marker for the value of our storage reservoirs
and is expected to de-risk capital requirements for CRC. Additionally, at the end of 2022 and beginning
of 2023, we announced our first two carbon dioxide management agreements – with Lone Cypress
Energy Services, LLC, and Grannus, LLC – a significant milestone for our Carbon TerraVault business
signifying both the demand for our storage tanks and a pathway to our first carbon capture and storage
(CCS) projects.

In addition to advancing CCS, we updated and expanded our ESG goals that build upon CRC’s
commitment to sustainability and its 2045 Full-Scope Net Zero Goal for Scope 1, 2 and 3 emissions.
The ESG goals tie 30% of executive annual incentive pay to ESG metrics; establish ethnic, racial and
gender diversity in leadership goals; and enhance our methane and freshwater reduction goals and
community giving goal. Our dedication to energy transition and our ongoing sustainability strategy
aligns with California’s climate goals under the Paris Climate Accord and further positions CRC as one
of the leading energy transition companies in the state.

Looking ahead, CRC will maintain its shareholder return mindset with a focus on delivering strong
and sustainable cash flows through disciplined capital allocation. CRC continues to adapt and evolve,
and I am excited to have Francisco at the helm going forward. I would like to thank the talented women
and men of CRC for their dedication and support as we continue to create a different kind of energy
company.

Sincerely,

Mark A. (Mac) McFarland
President and Chief Executive Officer
California Resources Corporation

[THIS PAGE INTENTIONALLY LEFT BLANK]

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K

‘

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2022
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the transition period from

Commission File Number 001-36478
California Resources Corporation
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

46-5670947
(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 Act:

Title of Each Class
Common Stock

Trading Symbol(s)
CRC

Name of Each Exchange on Which Registered
New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the
Act.

Yes ‘ No Í

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 Í No ‘

Indicate by check mark whether the registrant has submitted electronically every Interactive Date File required to be submitted pursuant
to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period as the registrant was
Yes Í No ‘
required to submit such files).

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting
company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer
Smaller Reporting Company ‘

Accelerated Filer
Emerging Growth Company ‘

‘

Non-Accelerated Filer ‘

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ‘

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness
of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered
public accounting firm that prepared or issued its audit report.

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant
included in the filing reflect the correction of an error to previously issued financial statements.

‘

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ‘

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes ‘ No Í

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price
at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the
registrant’s most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of June 30,
2022: $2,901,083,185.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the
Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes Í No ‘

At January 31, 2023, there were 71,491,602 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement to be filed within 120 days after December 31, 2022 with the Securities and Exchange
Commission in connection with the registrant’s 2023 Annual Meeting of Stockholders are incorporated by reference into Part III of this
Form 10-K.

TABLE OF CONTENTS

Part I

Items 1 & 2 BUSINESS AND PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Overview and History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil and Natural Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mineral Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production, Price and Cost History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated Proved Reserves and Future Net Cash Flows . . . . . . . . . . . . . . . . .
Drilling Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Productive Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marketing Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Carbon Management Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Human Capital Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulation of the Industries in Which We Operate . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MINE SAFETY DISCLOSURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 1A
Item 1B
Item 3
Item 4

Part II

Item 5

Item 6
Item 7

Item 7A

Item 8

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RESERVED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basis of Presentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supply Chain Constraints and Inflation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production, Prices and Realizations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and Joint Ventures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share Repurchase Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Seasonality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Operations Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uses of Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lawsuits, Claims, Commitments and Contingencies . . . . . . . . . . . . . . . . . . . . . .
Critical Accounting Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FORWARD-LOOKING STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . .
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

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Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Comprehensive Income (Loss) . . . . . . . . . . . . . . . .
Consolidated Statements of Changes in Stockholders’ Equity (Deficit) . . . . . . . .
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental Oil and Gas Information (Unaudited) . . . . . . . . . . . . . . . . . . . . . . .
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS . . . . . . . . . . . . . . . .
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . .
CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT
INSPECTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE . . . .
EXECUTIVE OFFICERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . .
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PRINCIPAL ACCOUNTANT FEES AND SERVICES . . . . . . . . . . . . . . . . . . . . . . . .

Page

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162

163
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164

166

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168

168

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168

Item 9

Item 9A
Item 9B
Item 9C

Part III

Item 10

Item 11
Item 12

Item 13

Item 14

Part IV

Item 15

EXHIBITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

169

GLOSSARY AND SELECTED ABBREVIATIONS

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

• ABR - Alternate base rate.
• ASC - Accounting Standards Codification.
• ARO - Asset retirement obligation.
• Bbl - Barrel.
• Bbl/d - Barrels per day.
• Bcf - Billion cubic feet.
• Bcfe - Billion cubic feet of natural gas equivalent using the ratio of one barrel of oil, condensate,

or NGLs converted to six thousand cubic feet of natural gas.

• Boe - We convert natural gas volumes to crude oil equivalents using a ratio of six thousand

cubic feet (Mcf) to one barrel of crude oil equivalent based on energy content. This is a widely
used conversion method in the oil and natural gas industry.

• Boe/d - Barrel of oil equivalent per day.
• Btu - British thermal unit.
• CalGEM - California Geologic Energy Management Division.
• CCS - Carbon capture and storage.
• CDMA - Carbon Dioxide Management Agreement.
• CO2 - Carbon dioxide.
• DD&A - Depletion, depreciation, and amortization.
• EOR - Enhanced oil recovery.
• EPA - United States Environmental Protection Agency.
• ESG - Environmental, social and governance.
• E&P - Exploration and production.
• Full-Scope Net Zero - Achieving permanent storage of captured or removed carbon emissions

in a volume equal to all of our scope 1, 2 and 3 emissions by 2045.

JV - Joint venture.

• GAAP - United States Generally Accepted Accounting Principles.
• G&A - General and administrative expenses.
• GHG - Greenhouse gases.
•
• LCFS - Low Carbon Fuel Standard.
• LIBOR - London Interbank Offered Rate.
• MBbl - One thousand barrels of crude oil, condensate or NGLs.
• MBbl/d - One thousand barrels per day.
• MBoe/d - One thousand barrels of oil equivalent per day.
• MBw/d - One thousand barrels of water per day
• Mcf - One thousand cubic feet of natural gas equivalent, with liquids converted to an equivalent

volume of natural gas using the ratio of one barrel of oil to six thousand cubic feet of natural gas.

• MHp - One thousand horsepower.
• MMBbl - One million barrels of crude oil, condensate or NGLs.
• MMBoe - One million barrels of oil equivalent.
• MMBtu - One million British thermal units.
• MMcf/d - One million cubic feet of natural gas per day.
• MMT - Million metric tons.
• MMTPA - Million metric tons per annum.
• MW - Megawatts of power.
• NGLs - Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity

products such as ethane, propane, isobutane and normal butane, and natural gasoline.

• NYMEX - The New York Mercantile Exchange.
• OCTG - Oil country tubular goods.

• Oil spill prevention rate - Calculated as total Boe less net barrels lost divided by total Boe.
• OPEC - Organization of the Petroleum Exporting Countries.
• OPEC+ - OPEC together with Russia and certain other producing countries.
• PHMSA - Pipeline and Hazardous Materials Safety Administration.
• Proved developed reserves - Reserves that can be expected to be recovered through existing

wells with existing equipment and operating methods.

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

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

• PSCs - Production-sharing contracts.
• PV-10 - Non-GAAP financial measure and represents the year-end present value of estimated

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

• Scope 1 emissions - Our direct emissions.
• Scope 2 emissions - Indirect emissions from energy that we use (e.g., electricity, heat, steam,

cooling) that is produced by others.

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

our products.

• SDWA - Safe Drinking Water Act.
• SEC - United States Securities and Exchange Commission.
• SEC Prices - The unweighted arithmetic average of the first day-of-the-month price for each
month within the year used to determine estimated volumes and cash flows for our proved
reserves.

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

York.

• Standardized measure - The year-end present value of after-tax estimated future cash flows

from proved oil and natural gas reserves, less future development and operating costs,
discounted at 10% per annum and using SEC Prices. Standardized measure is prescribed by
the SEC as an industry standard asset value measure to compare reserves with consistent
pricing, costs and discount assumptions.

• TRIR - Total Recordable Incident Rate calculated as recordable incidents per 200,000 hours for

all workers (employees and contractors).

• Working interest - The right granted to a lessee of a property to explore for and to produce and

own oil, natural gas or other minerals in-place. A working interest owner bears the cost of
development and operations of the property.

• WTI - West Texas Intermediate.

PART I

ITEMS 1 & 2 BUSINESS AND PROPERTIES

Business Overview and History

We are an independent oil and natural gas exploration and production company operating
properties exclusively within California. We provide affordable and reliable energy in a safe and
responsible manner, to support and enhance the quality of life of Californians and the local
communities in which we operate. We do this through the development of our broad portfolio of assets
while adhering to our commitment to create shareholder value. We also have some of the lowest
carbon intensity production in the United States. We are committed to energy transition and
decarbonization through our carbon management business that we refer to as Carbon TerraVault. We
are in the early stages of developing several carbon capture and storage projects in California. In
August 2022, Carbon TerraVault entered into a joint venture with BGTF Sierra Aggregator (Brookfield)
to pursue certain of these opportunities (Carbon TerraVault JV). Over time, we intend to conduct our
carbon management business on a stand-alone basis. We expect that this will provide greater flexibility
to consider strategic options, including the potential separation from our E&P business. See Part II,
Item 8 – Financial Statements and Supplementary Data, Note 8 Investment in Unconsolidated
Subsidiary and Related Party Transactions for more information on the Carbon TerraVault JV.

We qualified for and adopted fresh start accounting in connection with our emergence from
bankruptcy on October 27, 2020, at which point we became a new entity for financial reporting
purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh
start accounting. As a result of the application of fresh start accounting and the effects of the
implementation of our joint plan of reorganization (the Plan), the financial statements after October 31,
2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line”
financial statements are presented to distinguish between Predecessor and Successor companies.
References to “Predecessor” refer to the Company for periods ending on or prior to October 31, 2020
and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 15 Chapter 11

Proceedings and Note 16 Fresh Start Accounting for additional information on the terms of the Plan,
our emergence from bankruptcy and application of fresh start accounting.

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’

the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its consolidated
subsidiaries.

Business Strategy

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

• Adjust our corporate structure. We intend to manage our carbon management business on a

stand-alone basis over time. We expect that this will provide greater flexibility to consider
strategic options, including the potential separation from our E&P business. We also recently
installed a board of directors at Carbon TerraVault Holdings, LLC that will focus on growing and
developing our carbon management business on a stand-alone basis.

• Advance our carbon management business. We intend to continue to build our carbon

management business through Carbon TerraVault. Our efforts will build on the progress made
in 2022, including the formation of the Carbon TerraVault JV with Brookfield. We also executed
two carbon management service agreements with Lone Cypress Energy Services, LLC and
Grannus, LLC to provide permanent carbon storage. We are focused on signing up additional
emitter projects and submitting additional Class VI permit applications with the EPA for
permanent carbon capture and sequestration. We are also evaluating our Elk Hills power plant
as a potential emissions source for carbon capture and sequestration, and are working with a
consortium of industry participants to advance the development of a direct air capture hub to be
located in Kern County.

• Execute on a core E&P development plan. In light of recent regulatory changes in California, we
will reduce our average rig count to 1.5 rigs in 2023 (down from approximately 4 rigs in 2022) with
a drilling program focused on executing projects where we have permits in hand. We also intend
to increase our workover activity in 2023 to help minimize production decline. We further plan to
develop field level EIRs for the CEQA review process which we expect will reduce uncertainty in
obtaining permits for the majority of our proved undeveloped resources in future years.

• Focus on cost reductions and portfolio optimization. In light of the changing regulatory

environment in California, we will adjust our capital program in 2023 to optimize near term cash flow.
We intend to focus on cost reduction initiatives and expect to reduce our non-energy operating costs
and general and administrative costs by the end of the year. We also plan to continue to pursue the
sale of our Huntington Beach surface acreage as well as other non-core real estate assets.

•

Improve our financial flexibility and maintain a strong balance sheet. We are pursuing
options to amend and extend or replace our Revolving Credit Facility, as well as refinancing
options for our $600 million of Senior Notes. We expect that these steps will allow us to extend our
debt maturities and provide us with greater financial flexibility to increase shareholder returns. We
also intend to pursue financing options for our carbon management business that are separate
from the rest of our business. We remain committed to maintaining our strong liquidity position.

• Focus on increasing shareholder returns. CRC intends to optimize capital allocation and

focus on cost reduction opportunities in 2023 to drive cash flow generation. We expect that the
combination of these efforts will allow us to continue to increase shareholder returns. To that
end, our Board has authorized a 30% increase to its shareholder repurchase program for a total
of $1.1 billion, with approximately $640 million remaining on its authorization as of
December 31, 2022 after taking into account this increase.

• Maintain our commitment to safety and sustainability and demonstrate leadership on

ESG practices in the E&P space. We are committed to exceptional environmental and safety
performance and achieved a 99.9999% oil spill prevention rate in 2022 and registered a
workforce TRIR of 0.62. We have some of the lowest carbon intensity production among oil and
natural gas producers in the United States and established a Full-Scope Net Zero goal to
permanently store captured or removed carbon emissions equal to our Scope 1, 2 and 3
emissions by 2045, which aligns us with the State of California’s 2045 net zero ambitions and
puts us ahead of the net zero goals in the Paris Agreement. We intend to achieve this goal
through our existing and future decarbonization projects, including those projects that will be
developed by the Carbon TerraVault JV. Our ESG goals focus not only on lowering greenhouse
gas emissions, but also decreasing methane emissions, reducing freshwater consumption,
expanding leadership diversity, enhancing community engagement. We have increased
accountability by linking executive compensation to ESG performance. For 2023, 30% of our
management team’s annual incentive related to company performance is tied to safety and ESG
related metrics, including the advancement of our carbon management business.

Oil and Natural Gas Operations

As of December 31, 2022, our proved reserves totaled an estimated 417 MMBoe, of which 294
MMBbl were crude oil and condensate reserves, 38 MMBbl were NGL reserves and 511 BcF, or 85
MMBoe, were natural gas reserves.

As of December 31, 2022, we held approximately 1.9 million net mineral acres, the largest

non-governmental mineral acreage position in California. Our operated asset base spans 97 distinct
fields with approximately 10,000 operated wells. We had average net production of approximately 91
MBoe/d (60% oil) for the year ended December 31, 2022.

The following table highlights key information about our operations as of and for the year ended

December 31, 2022:

Mineral Acreage
Net mineral acreage
(thousands) . . . . . . . . . . . .
Average net mineral
acreage held in fee (%)
Number of producing
fields we operate . . . . . . .
Average drilling rigs . . . .
Net wells drilled and
completed . . . . . . . . . . . . .

. .

Proved reserves
Oil (MMBbl) . . . . . . . . . . . .
NGLs (MMBbl) . . . . . . . . . .
Natural gas (Bcf) . . . . . . . .
Total (MMBoe) . . . . . . . . . .

Oil percentage of proved
reserves . . . . . . . . . . . . . . .

Production
Total net production
(MMBoe) . . . . . . . . . . . . . .
Average daily net
production (MBoe/d) . . . . .

San
Joaquin
Basin

Los
Angeles
Basin

Ventura
Basin(a)

Sacramento
Basin

Other

Total
Operations

1,248

81 %

42
2

47 %

5
2

114.3

35.0

182
38
451
295

112
—
7
113

— %

466

41 %

118

1,867

97 %

71 %

—
—

—

—
—
—
—

50
—

—

—
—
53
9

—
—

—

—
—
—
—

97
4

149.3

294
38
511
417

62 %

99 %

— %

71 %

—

(a) Reflects one non-operated field in the Ventura basin included in assets held for sale. See Part II, Item 8 – Financial

Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more information on our Ventura Basin
divestiture.

For a discussion of the regulatory issues affecting the development of our oil and natural gas
properties, see Regulation of the Industries in Which We Operate, Regulation of Exploration and
Production Activities.

San Joaquin Basin

Commercial petroleum development in the San Joaquin basin began in the 1800s. The basin

contains multiple stacked formations throughout its areal extent, and we believe that this basin
provides appealing opportunities for re-development of existing wells, as well as new discoveries and
unconventional play potential. The geology of the San Joaquin basin continues to yield stratigraphic
and structural trap discoveries.

We hold substantially all the working, surface and mineral interests in the Elk Hills field, which is our

largest producing asset in the San Joaquin Basin and have a large ownership interest in several other
oil fields located in the San Joaquin basin including Buena Vista and Coles Levee. We have also been
successfully developing steamfloods in our Kern Front operations.

At Elk Hills we operate efficient natural gas processing facilities, including a cryogenic gas plant,
with a combined gas processing capacity of over 520 MMcf/d. Additionally, our Elk Hills power plant
generates sufficient electricity to operate the field, and sells excess power to the wholesale market and
a utility. Our operations at Elk Hills also include an advanced central control facility and remote
automation control on over 95% of the producing wells.

We believe our extensive 3D seismic library, which covers over 700,000 acres in the San Joaquin

basin, or approximately 50% of our gross mineral acreage in this basin, gives us a competitive
advantage in field development.

Los Angeles Basin

This basin is a northwest-trending plain about 50 miles long and 20 miles wide. Most of the
significant discoveries in the Los Angeles basin date back to the 1920s. The Los Angeles basin has
one of the highest concentrations per acre of crude oil in the world. Large active oil fields in this basin
include the Wilmington and Huntington Beach fields, where we have significant operations. Most of our
Wilmington production is subject to a set of contracts similar to production-sharing contracts (PSCs)
under which we first recover the capital and operating costs we incur on behalf of the state and the city
of Long Beach and then receive our share of profits. See Production, Price and Cost History below for
more information on our PSCs.

We are pursuing the potential divestiture of certain real estate properties, including two properties in

Huntington Beach. One of these properties is a one-acre parcel at Fort Apache and the other is an
approximately 90 acre surface property at our Huntington Beach field. At the Huntington Beach field,
we have begun the plugging and abandonment of approximately 30 existing wells and are working
towards the longer-term remediation of the larger property to provide flexibility for real estate sales in
the future.

Sacramento Basin

The Sacramento basin is a deep, thick sequence of sedimentary deposits of natural gas within an

elongated northwest-trending structural feature covering about 7.7 million acres. Exploration and
development in the basin began in 1918. Our significant mineral acreage position in the Sacramento
basin gives us the option for future development and rapid production growth in an attractive natural
gas price environment.

Ventura Basin

We divested a vast majority of our assets in the Ventura basin other than a de minimis

non-operated asset, during the fourth quarter of 2021 and the first quarter of 2022. Our remaining
Ventura basin asset is expected to be sold in the first half of 2023.

Other

Other than the basins described above, we also have mineral interests in undeveloped acreage

throughout California including in the Salinas basin and the Santa Maria basin.

Mineral Acreage

The following table summarizes our gross and net developed and undeveloped mineral acreage as

of December 31, 2022.

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Other(a)

Total

Developed(b)

Gross(c) . . . .
Net(d) . . . . . .
Undeveloped(e)
Gross(c) . . . .
Net(d) . . . . . .

Total

460
421

1,008
827

(in thousands)

6
6

—
—

259
246

265
220

20
15

17
14

2
1

142
117

747
689

1,432
1,178

1,468
1,248

2,179
Gross(c) . . . .
Net(d) . . . . . .
1,867
(a) Reflects remaining mineral acreage to be retained in the Ventura Basin and nearby areas. See Part II, Item 8 – Financial
Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more information on our Ventura Basin
divestiture.

144
118

524
466

37
29

6
6

(b) Mineral acres spaced or assigned to productive wells.
(c) Total number of mineral acres in which interests are owned.
(d) Net mineral acreage includes acreage reduced to our fractional ownership interest and interests under our PSCs.
(e) Mineral acres on which wells have not been drilled or completed to a point that would permit the production of commercial

quantities of oil and natural gas, regardless of whether the mineral acreage contains proved reserves.

At December 31, 2022, 71% of our total net mineral interest position was held in fee and the
remainder was leased. Of our leased acreage, approximately 63% is held by production and the
remainder is subject to lease expiration if initial wells are not drilled within a specified period of time.
The primary terms of our leases range from one to twenty years. The terms of these leases are
typically extended upon achieving commercial production for so long as such production is maintained.
Work programs are designed to ensure that the economic potential of any leased property is evaluated
before expiration. In some instances, we may relinquish leased acreage in advance of the contractual
expiration date if the evaluation process is complete and there is no longer a commercial reason for
leasing that acreage. In cases where we determine we want to take the additional time required to fully
evaluate undeveloped acreage, we have generally been successful in obtaining extensions.

If we are not able to establish production or otherwise extend lease terms, approximately 41,000

net mineral acres will expire in 2023, 35,000 net mineral acres will expire in 2024 and 14,000 net
mineral acres will expire in 2025. These leases represent 8% of our total net undeveloped acreage and
5% of our total net acreage as of December 31, 2022 and these expirations, should they occur, would
not have a material adverse impact on us. Historically, we have not dedicated any significant portion of
our capital program to prevent lease expirations and do not expect to do so in the future.

Production, Price and Cost History

The following table sets forth information regarding our production volumes, average realized and

benchmark prices and operating costs per Boe for the periods presented. See Part II, Item 7 –
Management’s Discussion and Analysis of Financial Condition and Results of Operations for more
information on our production activity as well as the impact of commodity price increases and inflation
on our operating costs per Boe, among other factors.

Successor

Predecessor

Year Ended
December 31,
2022

Year Ended
December 31, November 1, 2020 -
December 31, 2020

2021

January 1, 2020 -
October 31, 2020

Average daily net

production

Oil (MBbl/d)
. . . . . . . . . . . . . .
NGLs (MBbl/d) . . . . . . . . . . . .
Natural gas (MMcf/d) . . . . . . .
Total daily net production
(MBoe/d) . . . . . . . . . . . . . . . . .

Total production
(MMBoe)

. . . . . . . . . . . . . . . .

Average realized prices
. . . . . .
Oil with hedge ($/Bbl)
Oil without hedge ($/Bbl) . . . .
NGLs ($/Bbl) . . . . . . . . . . . . . .
Natural gas without hedge
($/Mcf) . . . . . . . . . . . . . . . . . . .

Average benchmark prices
Brent oil ($/Bbl)
. . . . . . . . . . .
WTI oil ($/Bbl) . . . . . . . . . . . . .
NYMEX gas ($/MMBtu) -

Contract Month Average . .

NYMEX gas ($/MMBtu) -

Average Monthly Settled
Price . . . . . . . . . . . . . . . . . .

Operating costs per Boe
Operating costs . . . . . . . . . . .

$
$
$

$
$

55
11
147

61.80
98.26
64.33

7.68

98.89
94.23

6.36

6.64

23.75

$
$
$

$
$

60
13
159

100

56.05
70.43
53.62

4.22

70.79
67.91

3.61

3.84

19.39

63
12
165

103

45.37
45.65
38.00

3.21

47.10
44.21

2.86

2.95

18.19

$
$
$

$
$

70
13
174

112

43.19
41.21
25.70

2.11

42.43
38.44

1.95

1.90

14.95

$
$
$

$
$

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

Elk Hills
2021

2022

2020

2022

Wilmington
2021

2020

Average daily net production

Oil (MBbl/d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NGLs (MBbl/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMcf/d) . . . . . . . . . . . . . . . . . . . . . . .

Total daily net production (MBoe/d) . . . . . . . . . . .

17
8
75

17
10
81

18
10
90

15
—
—

16
—
—

21
—
1

Our operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs
that typically do not vary with changes in production levels or well counts, especially in the short term. The
substantial majority of our near-term fixed costs become variable over the longer term because we manage
them based on the field’s stage of life and operating characteristics. For example, portions of labor and
material costs, energy, workovers and maintenance expenditures correlate to well count, production and
activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are
managed down as fields mature in a manner that correlates to production and commodity price levels. A
certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded
as fixed in the early phases of a program. However, as the production from a certain area matures, well
count increases and daily per well production drops, such support costs can be reduced and consolidated
over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as
property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with
commodity prices. We can quickly scale our operating costs in response to prevailing market conditions.
We believe that a significant portion of our operating costs are variable over the lifecycle of our fields.

Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is

subject to contractual arrangements similar to PSCs that are in effect through the economic life of the
assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of
production and reserves to recover a portion of such capital and operating costs and an additional share for
profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and
operating costs that we incur on their behalf, (ii) for our share of contractually defined base production, and
(iii) for our share of remaining production thereafter. We generate returns through our defined share of
production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and
reserves reported from these arrangements are based on our economic interest as defined in the contracts.
Our share of production and reserves from these contracts decreases when product prices rise and
increases when prices decline, assuming comparable capital investment and operating costs. However, our
net economic benefit is greater when product prices are higher. These PSCs represented 16% of our total
production for the year ended December 31, 2022.

In line with industry practice for reporting PSCs, we report 100% of operating costs under such contracts

in operating costs on our consolidated statements of operations as opposed to reporting only our share of
those costs. We report the proceeds from production designed to recover our partners’ share of such costs
(cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes
produced, including cost recovery, which is less than the total volumes produced under the PSCs. This
difference in reporting full operating costs but only our net share of production equally inflates our revenue
and operating costs per barrel and has no effect on our net results.

The following table presents our operating costs after adjustment for excess costs attributable to PSCs

for the periods presented:

Year ended
December 31,
2022

Successor
Year ended
December 31,
2021

Predecessor

November 1, 2020 -
December 31, 2020

January 1, 2020 -
October 31, 2020

(in millions)

($ per Boe)

(in millions)

($ per Boe)

(in millions)

($ per Boe)

(in millions)

($ per Boe)

785

23.75 $

705

19.39 $

114

18.19

511

14.95

(74)

(2.23)

(66)

(1.83)

(8)

(1.33)

(28)

(0.81)

711

21.52 $

639

17.56 $

106

16.86

483

14.14

Operating
costs . . . . . .
Excess
costs
attributable
to PSCs . . .

Operating
costs,
excluding
effects of
PSCs(a) . . . .

(a) Operating costs, excluding effects of PSCs is a non-GAAP measure. As described above, the reporting of our PSCs creates
a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net
share, inflating the per barrel operating costs. These amounts represent our operating costs after adjusting for this
difference.

The following table reconciles our average net production to our average gross production (which

includes production from the fields we operate and our share of production for fields operated by
others) for the periods presented:

Successor

Predecessor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

January 1, 2020 -
October 31, 2020

(MBoe/d)
Average Daily Net Production . . . .
Partners’ share under PSC-type

contracts . . . . . . . . . . . . . . . . . . .

Working interest and royalty

holders’ share . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . .

6
1

100

8
1

Average Daily Gross Production . .

106

117

103

9
1

119

112

11
1

129

Estimated Proved Reserves and Future Net Cash Flows

The information with respect to our estimated reserves presented below has been prepared in
accordance with the rules and regulations of the United States Securities and Exchange Commission
(SEC).

The following tables summarize our estimated proved oil (including condensate), NGLs and natural

gas reserves and PV-10 as of December 31, 2022. Our estimated volumes and cash flows were
calculated using the unweighted arithmetic average of the first-day-of-the-month price for each month
within the year (SEC Prices), unless prices were defined by contractual arrangements. For oil volumes,
the average Brent spot price of $100.25 per barrel was adjusted for gravity, quality and transportation
costs. For natural gas volumes, the average NYMEX gas price of $6.36 per MMBtu was adjusted for
energy content, transportation fees and market differentials. All prices are held constant throughout the
lives of the properties. The average realized prices for estimating our proved reserves as of
December 31, 2022 were $97.50 per barrel for oil, $67.83 per barrel for NGLs and $7.84 per Mcf for
natural gas.

Estimated reserves include our economic interests under PSCs in our Long Beach operations in the
Wilmington field. Refer to Part II, Item 8 – Financial Statements, Supplemental Oil and Gas Information
for additional information on our proved reserves.

As of December 31, 2022

San Joaquin
Basin

Los Angeles
Basin

Ventura Basin

Sacramento
Basin

Total

Proved developed reserves

Oil (MMBbl) . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .
NGLs (MMBbl)
. . . . . . . . . . . . . . . . . .
Natural Gas (Bcf)

Total (MMBoe)(a) . . . . . . . . . . . . . . . . .

Proved undeveloped reserves

Oil (MMBbl) . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .
NGLs (MMBbl)
. . . . . . . . . . . . . . . . . .
Natural Gas (Bcf)

Total (MMBoe) . . . . . . . . . . . . . . . . . . .

Total proved reserves

Oil (MMBbl) . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .
NGLs (MMBbl)
. . . . . . . . . . . . . . . . . .
Natural Gas (Bcf)

Total (MMBoe) . . . . . . . . . . . . . . . . . . .

155
36
399

257

27
2
52

182
38
451

295

96
—
6

16
—
1

112
—
7

113

—
—
—

—

—
—
—

—

—
—
—

—

—
—
53

—
—
—

—

—
—
53

251
36
458

363

43
2
53

294
38
511

417

. . . . . . . . . . . . . . . . . . . . . . . . . . .

Reserves to production ratio
13
(years)(b)
(a) As of December 31, 2022, approximately 19% of proved developed oil reserves, 7% of proved developed NGLs reserves,
10% of proved developed natural gas reserves and, overall, 16% of total proved developed reserves are non-producing. A
majority of our non-producing reserves relate to steamfloods and waterfloods where full production response has not yet
occurred due to the nature of such projects.

(b) Calculated as total proved reserves as of December 31, 2022 divided by total production for the year ended December 31,

2022.

Changes to Proved Reserves

The components of the changes to our proved reserves during the year ended December 31, 2022

were as follows:

San Joaquin
Basin

Los Angeles
Basin(a)

Ventura
Basin
(in MMBoe)

Sacramento
Basin

Total

Balance at December 31, 2021 . . . . . . . . . . . . . . .
Revisions related to price . . . . . . . . . . . . . . . . . .
Revisions related to performance . . . . . . . . . . . .
Revisions due to California regulatory changes
and court challenges . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and divestitures . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Balance at December 31, 2022 . . . . . . . . . . . . . . .

324
3
(5)

(16)
14
6
(6)
(25)

295

140
2
(7)

(17)
2
—
—
(7)

113

2
—
—

—
—
(2)
—

—

14
1
(4)

(1)
—
—
—
(1)

480
6
(16)

(34)
16
6
(8)
(33)

417

(a)

Includes proved reserves related to PSCs of 92 MMBoe and 111 MMBoe at December 31, 2022 and 2021, respectively.

Revisions related to price – We had net positive price-related revisions of 6 MMBoe primarily
resulting from a higher commodity price environment in 2022 compared to 2021. The price revision
reflects the extended economic lives of our fields, estimated using 2022 SEC pricing. Additionally, we
have experienced higher vendor-related pricing and compensation-related cost increases due to
inflation.

Revisions related to performance – We had 16 MMBoe of net negative performance-related

revisions which included negative performance-related revisions of 31 MMBoe and positive
performance-related revisions of 15 MMBoe. Our negative performance-related revisions primarily
were due to wells and incremental waterflood response that underperformed forecasts and removal of
proved undeveloped locations due to unsuccessful drilling results in certain areas. Our positive
performance-related revisions primarily related to better-than-expected well performance and addition
of proved undeveloped locations due to positive drilling results in certain areas. The majority of these
revisions were located in the San Joaquin and Los Angeles basins.

Revisions due to California regulatory changes and court challenges – We had 34 MMBoe of

negative revisions to our proved reserves due to the impact of California regulatory changes and court
challenges on our development plans. Of this amount, negative revisions of 20 MMBoe of proved
reserves were due to the uncertainty of the outcome of the referendum and potential impact of Senate
Bill No. 1137. The majority of these volumes are in the LA Basin. Negative revisions of 14 MMBoe to
our proved reserves were due to challenges to Kern County’s ability to issue well permits in reliance on
an existing EIR for CEQA purposes. The volumes affected by these court challenges are in Kern
County. See Regulation of the Industries in Which We Operate, Regulation of Exploration and
Production Activities.

Extensions and discoveries – We added 16 MMBoe from extensions and discoveries resulting from

successful drilling and workovers in the San Joaquin and Los Angeles basins.

Acquisitions and Divestitures – We had a reduction of 8 MMBoe which primarily related to our Lost

Hills divestiture. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3
Divestitures and Acquisitions for more information on these transactions.

Proved Undeveloped Reserves

The total changes to our proved undeveloped reserves during the year ended December 31, 2022

were as follows:

Balance at December 31, 2021 . . . . . . . . . . . . . . .
Revisions related to price . . . . . . . . . . . . . . . . . . .
Revisions related to performance . . . . . . . . . . . .
Revisions due to California regulatory changes
and court challenges . . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . .
Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers to proved developed reserves . . . . . . .

Balance at December 31, 2022 . . . . . . . . . . . . . . .

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin
(in MMBoe)

Sacramento
Basin

Total

45
1
(5)

(12)
10
6
(2)
(5)

30
(2)
2

(11)
1
—
—
(4)

—
—
—

—
—
—
—
—

—

—
—
—

—
—
—
—
—

—

75
(1)
(3)

(23)
11
6
(2)
(9)

Revisions related to price – We had 1 MMBoe of net negative price-related revisions. Positive price-

related revisions of 2 MMBoe were offset by 3 MMBoe of negative cost recovery barrels in our PSCs.

Revisions related to performance – We had 3 MMBoe of net negative performance-related revision

which included 4 MMBoe positive performance-related revisions and negative performance-related
revisions of 7 MMBoe. Our positive performance-related revisions of 4 MMBoe primarily related to
better-than-expected well performance and the addition of proved undeveloped locations due to
positive drilling results in certain areas. The positive revision also included proved undeveloped
reserves which were added to our five-year development plan in 2022. Our negative performance-
related revisions primarily related to unsuccessful drilling results in certain areas. The majority of these
revisions were located in the San Joaquin and Los Angeles basins.

Revisions due to California regulatory changes and court challenges – We removed 23 MMBoe
from proved undeveloped reserves due to the impact of the regulatory changes and court challenges
on our development plans as discussed above. 11 MMBoe of proved undeveloped reserves were
affected by Senate Bill No. 1137. 12 MMBoe of proved undeveloped reserves were affected by the
Kern County court challenges. These revisions are largely due to the uncertainty of near term
permitting of drilling projects and the deferral of development of certain projects beyond 5 years. The
volumes impacted are in Kern County. See Regulation of the Industries in Which We Operate,
Regulations of Exploration and Production Activities.

Extensions and discoveries – We added 11 MMBoe of proved undeveloped reserves through

extensions and discoveries, as a result of successful drilling and workover programs in the San
Joaquin and Los Angeles basins.

Transfers to proved developed reserves – We converted 9 MMBoe of proved undeveloped reserves

to proved developed reserves in the San Joaquin and Los Angeles basins. This resulted in a
conversion rate of approximately 12% of our beginning-of-year proved undeveloped reserves, with an
investment of approximately $127 million of drilling and completion capital. We believe we will have
sufficient capital to develop all year end 2022 proved undeveloped reserves within five years of their
original booking date.

PV-10 and Standardized Measure

PV-10 of cash flows is a non-GAAP financial measure and represents the year-end present value of

estimated future cash inflows from proved oil and natural gas reserves, less future development and
operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC
Prices. Calculation of PV-10 does not give effect to derivative transactions. Our PV-10 is computed on the
same basis as our standardized measures of future net cash flows, the most comparable measure under
GAAP, but does not include the effects of future income taxes on future net cash flows. Neither PV-10 nor
Standardized Measure should be construed as the fair value of our oil and natural gas reserves.
Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare
reserves with consistent pricing, costs and discount assumptions. PV-10 facilitates the comparisons to other
companies as it is not dependent on the tax-paying status of the entity.

As of December 31, 2022
(in millions)

Standardized measure of discounted future net cash flows . . . . . . . . . . . . .
Present value of future income taxes discounted at 10% . . . . . . . . . . . . . . .

PV-10 of cash flows(a)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

6,726
2,493

9,219

(a) The average realized prices for estimating our PV-10 of cash flow as of December 31, 2022 were $97.50 per barrel for oil,

$67.83 per barrel for NGLs and $7.84 per Mcf for natural gas.

Reserves Evaluation and Review Process

Our estimates of proved reserves and related discounted future net cash flows as of December 31,
2022 were made by our technical personnel, comprised of reservoir engineers and geoscientists, with
the assistance of operational and financial personnel and are the responsibility of management. The
estimation of proved reserves is based on the requirement of reasonable certainty of economic
producibility and management’s funding commitments to develop the reserves. Reserves volumes are
estimated by forecasts of production rates, operating costs and capital investments. Price differentials
between specified benchmark prices and realized prices and specifics of each operating agreement
are then applied against the SEC Price to estimate the net reserves. Operating and capital costs are
forecast using the current cost environment applied to expectations of future operating and
development activities related to the proved reserves. See Part II, Item 7 – Management’s Discussion
and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates for further
discussion of uncertainties inherent in the reserve estimates.

Proved developed reserves are those volumes that are expected to be recovered through existing
wells with existing equipment and operating methods, for which the incremental cost of any additional
required investment is relatively minor. Proved undeveloped reserves are those volumes that are
expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required.

Our Vice President of Reserves has primary responsibility for overseeing the preparation of our

reserves estimates. With over 25 years of technical and leadership experience in the oil and gas
industry, she has been involved with all stages of petroleum exploration and development from
appraisal of new discoveries to enhanced recovery methods in mature fields. She holds a Master of
Business Administration from Pepperdine University, as well as bachelor’s and master’s degrees in
Geology from the University of California, Santa Barbara.

We have an Oil and Gas Reserves Review Committee (Reserves Committee), consisting of senior

corporate officers, which reviewed and approved our oil and natural gas reserves for 2022. The
Reserves Committee annually reports its findings to the Audit Committee.

Audits of Reserves Estimates

Ryder Scott and Netherland, Sewell & Associates, Inc. (NSAI) were engaged to provide

independent audits of our reserves estimates for our fields. For the year ended December 31, 2022,
Ryder Scott audited 49% of our total proved reserves. NSAI audited 36% of our total proved reserves.
Collectively, 85% of our proved reserves were audited in 2022.

Our independent reserve engineers examined the assumptions underlying our reserves estimates,

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

In the conduct of the reserves audits, our independent reserve engineers did not independently

verify the accuracy and completeness of information and data furnished by us with respect to
ownership interests, crude oil and natural gas production, well test data, historical costs of operation
and development, product prices, or any agreements relating to current and future operations of the
fields and sales of production. However, if anything came to the attention of our independent auditors
that brought into question the validity or sufficiency of any such information or data, they would not rely
on such information or data until it had resolved its questions relating thereto or had independently
verified such information or data. Our independent reserve engineers determined that our estimates of
reserves have been prepared in accordance with the definitions and regulations of the SEC as well as
the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the SPE, including the criteria of “reasonable certainty,” as it pertains to expectations
about the recoverability of reserves in future years, under existing economic and operating conditions.
Both of our independent reserve engineers issued an unqualified audit opinion on the applicable
portions of our proved reserves as of December 31, 2022, which are attached as Exhibit 99.1 and 99.2,
respectively, to this Form 10-K and incorporated herein by reference.

Ryder Scott qualifications – The primary technical engineer responsible for our audit has more than

45 years of petroleum engineering experience, the majority of which has been in the estimation and
evaluation of reserves. He serves on the Ryder Scott Executive Committee and the Board of Directors
and is a registered Professional Engineer in the state of Texas.

NSAI qualifications – The primary technical engineer responsible for our audit has more than 21
years of petroleum engineering experience, with the majority spent evaluating California properties,
and is a registered Professional Engineer in the state of Texas. The primary geoscientist for the audit
has more than 25 years of experience practicing petroleum geoscience and is a Licensed Professional
Geoscientist in the state of Texas.

Drilling Statistics

The following table sets forth information on our net exploration and development wells drilled and

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

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total Net
Wells

2022
Productive

Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Development

—
114.3

Dry

Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Development

—
—

2021
Productive

Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Development

—
109.4

Dry

Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Development

2020
Productive

Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Development

Dry

Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .
Development

—
—

—
4.0

—
—

—
35.0

—
—

—
6.5

—
—

—
4.5

—
—

—
0.4

—
—

—
149.3

—
—

—
115.9

—
—

—
8.9

—
—

The following table sets forth information on our development wells where drilling was either in

progress or pending completion as of December 31, 2022.

Gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net

3.0
3.0

3.0
2.8

—
—

6.0
5.8

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total Net
Wells

Productive Wells

Productive wells are those that produce, or are capable of producing, commercial quantities of
hydrocarbons, regardless of whether they produce at a reasonable rate of return. Our average working
interest in our producing wells was 92% as of December 31, 2022. Wells are categorized based on the
primary product they produce.

The following table sets forth our productive oil and natural gas wells (both producing and capable
of production) as of December 31, 2022, excluding wells that have been idle for more than five years:

As of December 31, 2022

Productive Oil
Wells

Productive Natural Gas
Wells

Gross(a)

Net(b)

Gross(a)

Net(b)

7,312
1,730
20
—

9,062

126

6,802
1,640
20
—

8,462

123

158
—
—
920

156
—
—
849

1,078

1,005

San Joaquin Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Los Angeles Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ventura Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sacramento Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Multiple completion wells included in the total above . . .
(a) The total number of wells in which interests are owned.
(b) Net wells include wells reduced to our fractional interest.

Exploration Inventory

We have had minimal investment in exploration activity in recent years, and our 2023 capital plan

does not allocate any capital towards exploration drilling.

Marketing Arrangements

Crude Oil – We sell nearly all of our crude oil to California refiners. Substantially all of our crude oil

production is connected to third-party pipelines and California refining markets via our gathering
systems. We do not refine or process the crude oil we produce and do not have any significant long-
term transportation arrangements.

The prices paid by California refiners are typically based on local third-party postings that are
closely tied to Brent prices. International waterborne-based Brent prices are relevant because there is
limited crude pipeline infrastructure available to transport crude overland from other parts of the United
States into California. We believe that these limitations will continue to contribute to higher realizations
in California than most other U.S. oil markets for comparable grades.

Natural Gas – We sell all of our natural gas not used in our operations into the California market. A

majority of these sales are done on a daily basis using index based prices. Natural gas prices and
differentials are strongly affected by local market fundamentals, such as storage capacity and the
availability of transportation capacity in the market and producing areas. Transportation capacity
influences prices because California imports more than 90% of its natural gas from other states and
Canada. As a result, we typically obtain higher realizations relative to out-of-state producers due to
lower transportation costs on the delivery of our natural gas.

In addition to selling natural gas, we also use natural gas in steam generation for our steamfloods
and power generation. As a result, the positive impact of higher natural gas prices is partially offset by
higher operating costs of our steamflood projects and power generation, but higher prices still have a
net positive effect on our operating results due to net higher revenue. Conversely, lower natural gas
prices lower these operating costs but have a net negative effect on our financial results.

We currently hold transportation capacity contracts to transport all of our natural gas volumes for

multiple years.

NGLs – NGL prices vary by liquid type and realizations are closely correlated to the different

commodity prices to which they relate. Prices can also fluctuate due to the demand for certain
chemical products (for which NGLs are used as feedstock) and due to infrastructure constraints and
seasonality. Finally, our results are also affected by the performance of our natural gas-processing
plants. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry
gas to pipelines and separately sell the remaining products as NGLs. The efficiency with which we
extract liquids from the wet gas stream affects our operating results. Our natural gas-processing plants
also facilitate access to third-party delivery points near the Elk Hills field.

We currently have a ship-or-pay pipeline transportation contract for 6,500 barrels per day of NGLs
through March 2023. Our contract to transport NGLs requires us to cash settle any shortfall between
the committed quantities and volumes actually shipped. We have met all our shipping commitments
under this contract.

Electricity – A portion of the electrical output of the Elk Hills power plant is used by Elk Hills and
other nearby production fields. This provides a reliable source of power. We sell remaining electrical
output to the wholesale power market and a local utility. We also sell the remaining capacity to
community choice aggregates and other local utilities.

Delivery Commitments

We have commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs.

As of December 31, 2022, we had oil delivery commitments of 10 MMBbl in 2023, 3 MMBbl in 2024
and 1 MMBbl in 2025, NGL delivery commitments of 1 MMBbl through March 2023 and natural gas
delivery commitments of 13 Bcf through December 2023. We generally have significantly more
production than the amounts committed for delivery and have the ability to secure additional volumes
of products as needed. These commitments are typically index-based contracts with prices set at the
time of delivery.

Derivatives

We protect our operating cash flow from volatility in the commodities market through our hedging

strategy. Prior to May 2022, our Revolving Credit Facility required us to maintain certain levels of
hedges regardless of our leverage. We also entered into incremental hedges above and beyond these
requirements for certain time periods. In certain circumstances, these hedges (including hedges
entered into by us in 2020 to comply with covenants in our Revolving Credit Facility) prevent us from
realizing the full benefits of price increases. Following an amendment to our Revolving Credit Facility in
April 2022, we are only required to maintain hedges in the event the ratio of our consolidated total debt
to consolidated EBITDAX as defined in our Credit Agreement exceeds 1:1. We continuously evaluate
our hedging strategy to take into account changes in prevailing market prices and conditions.

Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives for

more information on our commodity contracts.

Our Principal Customers

We sell crude oil, natural gas and NGLs to marketers, California refineries and other purchasers
that have access to transportation and storage facilities. Our ability to sell our products can be affected
by factors that are beyond our control and cannot be accurately predicted. See Part II, Item 8 –
Financial Statements and Supplementary Data, Note 1 Nature of Business, Summary of Significant
Accounting Policies and Other for more information on our customers.

Title to Properties

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

Competition

Our competitors are primarily other exploration and production companies that produce oil, natural

gas and NGLs. We compete locally against small independent producers and major international oil
companies who operate in California. We also compete with foreign oil and gas companies because
California imports approximately 75% of the oil it consumes. We believe that our proximity to the
California refineries gives us a competitive advantage over importers due to lower transportation costs.
Further, California refineries are generally designed to process crude with similar characteristics to the
low-carbon intensity oil produced from our fields. The California natural gas market is serviced from a
network of pipelines, including interstate and intrastate pipelines. We deliver our natural gas to
customers using our firm capacity contracts.

We compete for third-party services to profitably develop our assets, to find or acquire additional
reserves, to sell our production and to find and retain qualified personnel. Higher commodity prices
could intensify competition for drilling and workover rigs, pipe, other oil field equipment and personnel.
In 2022, we experienced increased costs due to inflation. However, in the current environment, we
anticipate modest price increases for materials and services as contracts are renewed in the future.
We believe our relative size and activity levels, compared to other in-state producers, favorably
influences the pricing we receive from third-party providers in the markets in which we operate.

We also face competition in our oil and natural gas operations from other sources of energy,

including wind and solar power. These products compete directly with the electricity we generate from
our power plants and indirectly as substitutes for oil, natural gas and NGLs. We expect competition
from these sources to intensify in the future due to technological advances and as California continues
to develop renewable energy and implements climate-related policies.

In our carbon management business, we compete with other potential storage providers to acquire

and develop storage reservoirs and enter into agreements with existing and future emission sources.

Infrastructure

The infrastructure used in our operations, including plants and facilities located in the Wilmington

field, is presented below:

Description

Quantity

Unit

Capacity

Gas Processing Plants(a) . . . . . . .
Power Plants(b) . . . . . . . . . . . . . . .
Steam Generators/Plants(c) . . . . .
Compressors . . . . . . . . . . . . . . . .
Water Management Systems(c) . .
. . . . . . . . . . . .
Water Softeners(c)
Oil and NGL Storage(d) . . . . . . . . .
. . . . . . . . . . . . . . . . . .
Pipelines(e)

6
3
>30
>300

MMcf/d
MW
MBbl/d
MHp
MBw/d
MBw/d
MBbls
Miles

San Joaquin Basin
525
595
150
320
1,900
125
408

Other
Basins
18
48
—
21
1,980
—
195

Total
543
643
150
341
3,880
125
603
>8,000

(a) Includes the Elk Hills cryogenic gas plant with a capacity of 200 MMcf/d of inlet gas and two low temperature separation plants
used as backup facilities. Our natural gas processing facilities are interconnected via pipelines to nearby third-party rail and
trucking facilities, with access to various North American NGL markets. In addition, we have truck rack facilities coupled with a
battery of pressurized storage tanks at our natural gas processing facilities for NGL sales to third parties.

(b) Includes our 550-megawatt combined-cycle Elk Hills power plant, located adjacent to the Elk Hills natural gas processing facility
and typically generates all the electricity needed by our Elk Hills field and certain contiguous operations in the San Joaquin
basin. We utilize approximately a third of its capacity for operations and our subsidiary sells the excess to the grid and to a local
utility. Also included is a 45-megawatt cogeneration facility at Elk Hills that provides additional flexibility and reliability to support
field operations and a 48-megawatt power generating facility that is part of the Long Beach Unit located in the Los Angeles
basin.

generate steam, reducing our operating costs. This is integral to our operations in the San Joaquin basin and supports our high-
margin oil fields.

(d) Our tank storage capacity throughout California gives us flexibility for a period of time to store crude oil and NGLs, allowing us to

continue production and avoid or delay any field shutdowns in the event of temporary power, pipeline or other shutdowns.
(e) Our pipelines are dedicated almost entirely to collecting our oil and natural gas production and are in close proximity to field-

specific facilities such as tank settings or central processing sites. Our oil pipelines connect to multiple third-party transportation
pipelines. In addition, virtually all of our natural gas facilities connect with major third-party natural gas pipeline systems.

Carbon Management Business

In 2021, we adopted a 2045 Full-Scope Net Zero goal to achieve permanent storage of captured or

removed carbon emissions in a volume equal to all of our Scope 1, 2 and 3 emissions by 2045. Our
climate-related goal could be modified as standards and rules develop related to greenhouse gas
emissions, and the potential separation of our carbon management business would also affect our
ability to reach this goal.

We have formed a carbon management business to pursue CCS projects that are directly-sited or within

close proximity to significant sources of CO2 emissions in California. We intend to manage our carbon
management business on a stand-alone basis over time. We expect that this will provide greater flexibility to
consider strategic options, including the potential separation from our E&P business. To facilitate that goal,
we have created a new board of directors at Carbon TerraVault, initially comprised of three of our directors:
Mark A. (Mac) McFarland, Andrew Bremner and James Chapman.

EPA Class VI Permits and CCS Projects

We are in the early stages of developing several CCS projects in California. To date, we have submitted

Class VI permit applications to the EPA for two permanent sequestration projects at our Elk Hills field. We
have also submitted permit applications for two permanent sequestration projects in the Sacramento Basin.

We continue to evaluate potential storage projects in California. One of our storage projects is
being jointly developed through the Carbon TerraVault JV. Several other projects are being considered
by the Carbon TerraVault JV for future development. If Brookfield elects to participate in a project, our
upfront costs to evaluate and permit that project will be subsequently recovered through Brookfield’s
investment in the Carbon TerraVault JV. We may also pursue the development of CCS projects
independently of the Carbon TerraVault JV if Brookfield elects not to participate.

In 2022, we executed two carbon dioxide management agreements (CDMAs) with emitters to

provide permanent carbon storage. The CDMAs frame the material economics and terms of the project
and include conditions precedent to close. The CDMAs are also subject to negotiation of definitive
documents and a final investment decision. One of the CDMAs relates to a project that will be
developed through the Carbon TerraVault JV. We are separately in discussions with other potential
emitters to enter into joint venture or other commercial arrangements with respect to CCS projects.

Once completed, we expect that our Carbon TerraVault CCS projects will inject CO2 captured from
industrial sources into subsurface reservoirs and permanently store CO2 deep underground. As part of
our commitment to carbon management, we are also evaluating the feasibility of developing a carbon
capture system for our 550-megawatt Elk Hills power plant (CalCapture) and pursuing a U.S.
Department of Energy grant for the development of a direct air capture hub in California.

We expect that the size and scope of our projects providing these and similar services and capital
spent on such projects will continue to grow given our strategy of expansion into these services and the
development of our carbon management business as a stand-alone business. For more information
about the risks involved in our carbon management business, see Part I, Item 1A – Risk Factors.

Carbon TerraVault JV

In August 2022, we entered into the Carbon TerraVault JV with Brookfield for the further development of

our carbon management business. We hold a 51% interest in the Carbon TerraVault JV and Brookfield
holds a 49% interest. Brookfield has committed an initial $500 million to invest in CCS projects that are
jointly approved through the Carbon TerraVault JV. At the formation of the Carbon TerraVault JV, we
contributed rights to inject CO2 into the 26R reservoir in our Elk Hills field for permanent CO2 storage (26R
reservoir) and Brookfield committed to make an initial investment of $137 million, payable in three equal
installments with the last two installments subject to the achievement of certain milestones. Brookfield
contributed the first $46 million installment of their initial investment to the Carbon TerraVault JV during the
year ended December 31, 2022. This amount may, at our sole discretion, be distributed to us or used to
satisfy future capital contributions, among other items. The parties have certain put and call rights with
respect to the 26R reservoir if certain milestones are not met. Future storage projects for Brookfield’s initial
commitment are subject to approval of the joint venture, including Brookfield.

The Carbon TerraVault JV has an option to participate in certain projects that involve the capture,
transportation and storage of CO2 in California. This option expires upon the earlier of (1) August 2027, (2)
when a final investment decision has been approved by the Carbon TerraVault JV for storage projects
representing in excess of 5 MMTPA in the aggregate, or (3) when Brookfield has made contributions to the
joint venture in excess of $500 million (unless Brookfield elects to increase its commitment). Refer to Part II,
Item 8 – Financial Statements and Supplementary Data, Note 8 Investment in Unconsolidated Subsidiary
and Related Party Transactions for more information on our Carbon TerraVault JV.

Human Capital Management

Our employees are our most valuable asset and we strive to provide a safe and healthy workplace,

development opportunities and financial rewards, ensuring focus on fair and equitable treatment. We
believe our core values of Character, Responsibility and Commitment and our comprehensive
business and ethical conduct policies sustain shareholder value.

Our comprehensive business and ethical conduct policies apply to all directors, officers and
employees, each of whom personally commits to following our code of conduct and our corporate
policies, as well as to suppliers and vendors working in our operations. Our position is that no business
goal is worth our employees compromising their integrity or our shared values.

As of December 31, 2022, we had approximately 1,060 employees, all in the United States. Of the

total 1,060 employees, 45 full-time equivalents are focused on our carbon management business.
Approximately 50 of our employees are covered by a collective bargaining agreement. We also utilize
the services of many third-party contractors throughout our operations.

Continued Employee Development

Employee development opportunities are provided to enhance leadership development and expand

career opportunities. Our employees undergo mandatory annual training on our policies including
health and safety, business ethics, harassment, IT security and others. Our mandatory training
reinforces our company-wide commitment to operate in accordance with all applicable laws, rules and
regulations and to sustain a diverse and empowered workforce comprising of our employees and those
of our suppliers, vendors and joint ventures. In addition to training, our employees receive regular
performance and career development discussions from their direct managers. All employees receive
annual performance reviews.

Our largest development initiatives include the Future Leaders Development Program with the
University of California, Los Angeles (UCLA) Anderson School; our Intrepid Women’s Program, a
program of coaching and development circles for women; and ELEVATE, a manager workshop on
communication styles and culture changing behaviors to develop our future leaders.

We have taken steps to promote the development of a pipeline of candidates as we develop our
carbon management business. In 2022, we pledged $2.5 million to fund several Kern County initiatives
with Kern Community College District (Kern CCD) and California State University, Bakersfield (CSUB)
to help advance the energy transition and further benefit local communities. We will collaborate with
Kern CCD to establish the CRC Carbon Management Institute, a first-of-its-kind initiative that will
empower local private and public partnerships to lead the way in defining how collaboration between
education and industry can positively impact communities. Funding will also be used for research and
development, community outreach and education, workforce training and education, and carbon
management academics that will focus on advancing CCS and emerging technologies. Additionally,
CSUB will launch the CRC Energy Transition Lecture Series on relevant topics and emerging issues
related to CCS and technologies that will lead the way to achieving a net zero future. Finally, the CRC
Carbon TerraVault Scholarship will be established to help provide students with academic
opportunities.

Diversity, Equity and Inclusion

Our goal is to foster an open and diverse culture and we are committed to advancing women and
minorities in our workplace. We believe increasing diversity, equity and inclusion (DE&I) will help us
achieve success through better retention rates, higher innovation, and increased productivity. We have
implemented a 2030 ethnic, racial and gender diversity leadership goal that prioritizes ethnic, racial
and gender diversity in company leadership positions and on the Board of Directors. Our goal is three
pronged, to maintain greater than 20% ethnically and racially diverse professionals in leadership
positions, increase gender diverse professionals in leadership positions to 30% and maintain current
Board composition with at least 30% ethnically, racially and gender diverse Board members. We also
established an Advisory Council focused on career development, promotion, recruitment and retention
to help ensure that we meet our DE&I goals. In 2022, we had all employees attend DE&I training to
reinforce an open and diverse culture.

The table below approximates our self-reported gender diverse and ethnically and racially diverse

employees and members of our Board of Directors as of December 31, 2022.

Gender Diverse

Ethnically and
Racially Diverse

All Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Managers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Board of Directors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

20%
21%
22%
33%

40%
23%
26%
33%

Employee Safety

Our unwavering commitment to health, safety and the environment defines how we operate our

business. We prepare our workforce to work safely through comprehensive training, safe work
practices, technology and rigorous maintenance and asset integrity programs. Each year, we set a
threshold TRIR as a quantitative metric that directly impacts incentive compensation for all of our
employees. We have achieved exemplary, steadily improved safety performance over the last several
years by promoting a culture of safety where all employees, contractors and vendors are empowered
with Stop Work Authority to cease any activity – without repercussions – to prevent a safety or
environmental accident.

Engagement and Retention

We survey our employees annually to ensure employee sentiment is collected and heard
throughout the year allowing us to assess engagement levels and drivers to determine areas of
improvement to enhance engagement and retention. The results of the engagement surveys are
reviewed by senior management and our Board of Directors. Senior leadership also host regular
townhalls so employees can engage with them through question and answer sessions.

We provide our employees industry competitive base wages and annual and long-term incentive

compensation opportunities, as well as matching and profit-sharing retirement contributions to
employees’ 401(k) accounts; comprehensive health benefits; life, disability and accident insurance
coverages; sick pay, paid holidays, paid parental leave and vacation; employee assistance for
confidential counseling services, a wellness program to promote the well-being of our employees and
their families; and various group discount programs. Our employee stock purchase program allows our
employees to purchase shares of our common stock at a discounted price. We also provide options for
alternate work schedules, flexible work hours, part-time work options and telecommuting.

Regulation of the Industries in Which We Operate

Our operations are subject to a wide range of federal, state and local laws and regulations. Those
that specifically relate to oil and natural gas exploration and production are described in this section.

Regulation of Exploration and Production Activities

Well Permitting

CalGEM is California’s primary regulator of the oil and natural gas production industry on private
and state lands, with additional oversight from the State Lands Commission’s administration of state
surface and mineral interests. From time to time we have experienced significant delays with respect to
obtaining drilling permits from CalGEM for our operations. A variety of factors outside of our control can
lead to such delays. CalGEM has not issued any permits for new production wells to any operators
since December 2022.

CalGEM currently requires an operator to identify the manner in which the California Environmental
Quality Act (CEQA) has been satisfied prior to issuing various state permits, typically through either an
environmental review or an exemption by a state or local agency. In Kern County, this requirement has
typically been satisfied by complying with the local oil and natural gas ordinance which was supported
by an Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015.

Our operations in Kern County have been subject to significant uncertainty over the past several
years as a result of ongoing challenges to the County’s ability to rely on an existing EIR to meet the
County’s obligations under CEQA. In December 2015 several groups challenged the sufficiency of the
EIR for satisfying CEQA requirements in Kern County for oil and natural gas permit approvals (Kern
County EIR Litigation). In March 2018 a trial court (Trial Court) found that the EIR inadequately
analyzed the environmental impacts to rangeland and road paving mitigation for purposes of well work
and rejected the plaintiffs’ other CEQA claims. The plaintiffs appealed. In February 2020, the California
Fifth District Appellate Court (Appellate Court) ruled that the plaintiffs’ other CEQA claims had merit
and ordered Kern County to rescind the Zoning Ordinance and cease issuing permits. In March 2021,
Kern County’s Board of Supervisors approved a revised Zoning Ordinance (the Revised Ordinance)
and certified a Supplemental Recirculated Environmental Impact Report (SREIR) for purposes of
satisfying CEQA requirements with respect to the issuance of oil and natural gas permits. A suit was
subsequently filed that same month challenging the sufficiency of the SREIR. In October 2021, the
Trial Court ordered Kern County to cease using the existing EIR to meet CEQA requirements until it
determined that the Revised Ordinance complied with CEQA requirements. The Trial Court
subsequently identified four deficiencies in the SREIR that needed correction to conform to CEQA. In
November 2022, upon the correction of those deficiencies to the Trial Court’s satisfaction, the Trial
Court lifted the suspension on Kern County’s ability to rely on the existing SREIR to meet CEQA
requirements in Kern County (the Discharge Order). In December 2022, the Trial Court denied a
motion to stay the Discharge Order. The plaintiffs appealed the judgment and Discharge Order and
filed a petition requesting a stay of the ordinance pending resolution of the merits of the appeal.

On January 26, 2023, the Appellate Court issued a preliminary order on the petition reinstating a
suspension of Kern County’s ability to rely on the existing SREIR to meet CEQA requirements pending
the outcome of a final order determining whether oil and natural gas permitting shall remain suspended
for the duration of the appeals process. That order is still pending.

We intend to address CEQA compliance for our oil and natural gas permits in Kern County through

alternative pathways. However, this will be a lengthy process and we cannot predict whether this
approach will ultimately be successful. As a result of these issues and current lack of permits with
respect to our Kern County properties, we do not currently plan to drill and complete any additional
wells within Kern County until permitting is resumed in Kern County, which may be later in the 2024
calendar year. However, there is no certainty that we will obtain permits on that timeline or at all, which
may further adversely affect our future development plans, proved undeveloped reserves, business,
operations, cash flows, financial position and results of operations. Approximately 71% of our proved
undeveloped reserves or 9% of our total proved reserves relate to wells to be drilled in Kern County
beginning in 2024 for which we would need to obtain permits.

The California Legislature and Governor have significantly increased the jurisdiction, duties and
enforcement authority of CalGEM, the State Lands Commission and other state agencies with respect
to oil and natural gas activities in recent years through legislation and policy pronouncements. For
example, 2019 state legislation expanded CalGEM’s duties effective on January 1, 2020 to include
public health and safety and reducing or mitigating greenhouse gas emissions while meeting the
state’s energy needs, and will require CalGEM to study and prioritize idle wells with emissions,
evaluate costs of abandonment, decommissioning and restoration, and review and update associated
indemnity bond amounts from operators if warranted, up to a specified cap which may be shared
among operators. Other 2019 legislation specifically addressed oil and natural gas leasing by the State
Lands Commission, including imposing conditions on assignment of state leases, requiring lessees to
complete abandonment and decommissioning upon the termination of state leases, and prohibiting
leasing or conveyance of state lands for new oil and natural gas infrastructure that would advance
production on certain federal lands such as national monuments, parks, wilderness areas and wildlife
refuges.

CalGEM and other state agencies have also significantly revised their regulations, regulatory
interpretations and data collection and reporting requirements. CalGEM issued updated regulations in
April 2019 governing management of idle wells and underground fluid injection, which include specific
implementation periods. The updated idle well management regulations require operators to either
submit annual idle well management plans describing how they will plug and abandon or reactivate a
specified percentage of long-term idle wells or pay additional annual fees and perform additional
testing to retain greater flexibility to return long-term idle wells to service in the future. The updated
underground injection regulations address injection approvals, project data requirements, testing of
injection wells, monitoring and reporting requirements with respect to injection parameters,
containment and incident response, among other topics.

In addition, certain local governments have proposed or adopted ordinances that would restrict certain

drilling activities in general and well stimulation, completion or injection activities in particular, impose
setback distances from certain other land uses, or ban such activities outright. For example, both the City
and the County of Los Angeles have voted to prohibit new oil and natural gas wells and phase out
existing wells over a number of years. Our operations in unincorporated areas of Los Angeles are not
affected by these bans, and we do not anticipate a material impact from these bans to our future drilling
operations as we have no drilling plans or proved undeveloped reserves within the area that would be
covered by these bans. However, from time to time, other local governments in California have sought to
enact similar bans and others may seek to do so in the future. For example, a similar ban was previously
proposed in Monterey County, where we own mineral rights but have no production, before being
declared to be preempted by state and federal regulation. Other local governments have sought to ban
natural gas or the transportation of natural gas through their cities. The City of Antioch declined to extend
our franchise agreement for a natural gas pipeline through its city. Several companies, including CRC,
have challenged the city’s inconsistent and arbitrary approach to natural gas approvals.

Setbacks

On September 16, 2022, the Governor of California signed Senate Bill No. 1137 into law, which
established 3,200 feet as the minimum distance between new oil and natural gas production wells and
certain sensitive receptors such as homes, schools and businesses open to the public effective
January 1, 2023. On January 6, 2023, CalGEM’s emergency regulations to support implementation of
Senate Bill No. 1137 were approved by the Office of Administrative Law and final regulations were
published. The regulations included applicable requirements of notice to property owners and tenants
regarding the work performed and offering the sampling of test water wells or surface water before and
after drilling; the contents of required notices for new production facilities; the annual submission of a
sensitive receptor inventory and sensitive receptor map and the contents and format of the same; and
the requirements of statements where operators have determined a location not to be within a health
protection zone. Additional provisions of Senate Bill No. 1137 include, among others, the imposition of
health, safety and environmental controls applicable to both current and new wells located within this
distance of sensitive receptors related to noise, light, and dust pollution controls and air emission
monitoring, and the immediate suspension of operations at production facilities determined to not be in
compliance with certain air emission requirements. In December 2022, proponents of a voter
referendum (the Referendum) collected more than the requisite number of signatures required to put
Senate Bill No. 1137 on the 2024 ballot. On February 3, 2023, the Secretary of State of California
certified the signatures and confirmed that the Referendum qualifies for the November 2024 ballot.
Accordingly, Senate Bill No. 1137 is stayed until it is put to a vote, although any stay could be delayed
if there are legal challenges to the Secretary of State’s certification. In addition, even during the stay,
CalGEM could attempt to initiate rulemaking with regard to setbacks.

The majority of our production is in rural areas in the San Joaquin basin and is unlikely to be affected
by Senate Bill No. 1137 should the outcome of the Referendum result in the bill being implemented. We
would not expect the implementation of this law to result in any change in our existing proved developed
producing reserves or current production rates or any material change to the timing of plugging and
abandonment liabilities. However, there is significant uncertainty with respect to our ability to develop
proved undeveloped reserves within the setback zones established by Senate Bill No. 1137. As a result,
we have removed from our reserves any proved undeveloped reserves that are located within setback
zones, except for those reserves for which we have existing drilling permits and intend to develop prior to
the November 2024 ballot. This resulted in a reduction to the net present value of our proved
undeveloped reserves by 24% and our overall proved reserves by 4% as of December 31, 2022.

Pipeline Transportation

Federal and state pipeline regulations have also been recently revised. CalGEM imposed more
stringent inspection and integrity management requirements in 2019 and 2020 with respect to certain
natural gas pipelines in specified locations, with additional regulations anticipated in 2022 regarding
digital mapping of such lines. The Office of the State Fire Marshal adopted regulations in 2020 to
require risk assessment of various oil lines in the coastal zone, followed by retrofitting of certain of
those lines with the best available control technology to mitigate oil spills over a specified
implementation period. Finally, the federal PHMSA has, from time to time, issued new regulations
expanding or otherwise revising pipeline integrity requirements. For example, in November 2021,
PHMSA issued a final rule imposing safety regulations on an aggregate of approximately 400,000
miles of previously unregulated onshore gas gathering lines across the United States that, among
other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting
requirements to all gas gathering operators and apply a set of minimum safety requirements to certain
gas gathering pipelines with large diameters and high operating pressures. And, in August 2022,
PHMSA finalized additional pipeline safety rules, which adjusted the repair criteria for pipelines in high
consequence areas, created new criteria for pipelines in non-high consequence areas, and
strengthened integrity management assessment requirements, among other items.

Water Injection

Our operations in the Wilmington Oil Field utilize injection wells to reinject produced water pursuant

to waterflooding plans. These operations are subject to regulation by the City of Long Beach and
CalGEM. We are currently in discussions with the City of Long Beach and CalGEM with respect to
what injection well pressure gradient complies with CalGEM’s requirements for the protection of
underground sources of drinking water, while at the same time mitigating subsidence risks. CalGEM’s
local office has preliminarily indicated that the injection well pressure gradient should be reduced from
the gradient that has been used for several decades. As part of our ongoing discussions, we and the
City of Long Beach have provided CalGEM with technical information regarding how the historical
injection well pressure gradient complies with CalGEM’s requirements and to inform them of the
absence of risk of leakage. If CalGEM were to ultimately disagree and determine to reduce the
injection well pressure gradient, and we were unable to reverse that decision on appeal or other legal
challenge, we expect any material reduction in injection well pressure gradient for our operations in the
Wilmington Oil Field would result in a decrease in production and reserves from the field.

Collectively, the effect of these regulations is to potentially limit the number and location of our wells

and the amount of oil and natural gas that we can produce from our wells compared to what we
otherwise would be able to do.

Regulation of Health, Safety and Environmental Matters

Numerous federal, state, local and other laws and regulations that govern health and safety, the

release or discharge of materials, land use or environmental protection may restrict the use of our
properties and operations, increase our costs or lower demand for or restrict the use of our products
and services. Applicable federal health, safety and environmental laws include the Occupational Safety
and Health Act, Clean Air Act, Clean Water Act, Safe Drinking Water Act, Oil Pollution Act, Natural Gas
Pipeline Safety Act, Pipeline Safety Improvement Act, Pipeline Safety, Regulatory Certainty, and Job
Creation Act, Endangered Species Act, Migratory Bird Treaty Act, Comprehensive Environmental
Response, Compensation, and Liability Act, Resource Conservation and Recovery Act and NEPA,
among others. California imposes additional laws that are analogous to, and often more stringent than,
such federal laws. These laws and regulations:

•

establish air, soil and water quality standards for a given region, such as the San Joaquin
Valley, conduct regional, community or field monitoring of air, soil or water quality, and require
attainment plans to meet those regional standards, which may include significant mitigation
measures or restrictions on development, economic activity and transportation in such region;
require various permits, approvals and mitigation measures before drilling, workover,
production, underground fluid injection or waste disposal commences, or before facilities are
constructed or put into operation;
require the installation of sophisticated safety and pollution control equipment, such as leak
detection, monitoring and shutdown systems, and implementation of inspection, monitoring and
repair programs to prevent or reduce releases or discharges of regulated materials to air, land,
surface water or ground water;
restrict the use, types or sources of water, energy, land surface, habitat or other natural
resources, require conservation and reclamation measures, impose energy efficiency or
renewable energy standards on us or users of our products and services, and restrict the use of
oil, natural gas or certain petroleum–based products such as fuels and plastics;
restrict the types, quantities and concentrations of regulated materials, including oil, natural gas,
produced water or wastes, that can be released or discharged into the environment, or any
other uses of those materials resulting from drilling, production, processing, power generation,
transportation or storage activities;

•

limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater
recharge, endangered species habitat and other protected areas, and require the dedication of
surface acreage for habitat conservation;
establish standards for the management of solid and hazardous wastes or the closure,
abandonment, cleanup or restoration of former operations, such as plugging and abandonment
of wells and decommissioning of facilities;
impose substantial liabilities for unauthorized releases or discharges of regulated materials into
the environment with respect to our current or former properties and operations and other
locations where such materials generated by us or our predecessors were released or
discharged;
require comprehensive environmental analyses, recordkeeping and reports with respect to
operations affecting federal, state and private lands or leases;
impose taxes or fees with respect to the foregoing matters;

•
• may expose us to litigation with government authorities, counterparties, special interest groups

or others; and

• may restrict our rate of oil, NGLs, natural gas and electricity production.

Due to the risk of future drought conditions in California, water districts and the state government
have implemented regulations and policies that may restrict groundwater extraction and water usage
and increase the cost of water. Water management, including our ability to recycle, reuse and dispose
of produced water and our access to water supplies from third-party sources, in each case at a
reasonable cost, in a timely manner and in compliance with applicable laws, regulations and permits, is
an essential component of our operations to produce crude oil, natural gas and NGLs economically
and in commercial quantities. As such, any limitations or restrictions on wastewater disposal or water
availability could have an adverse impact on our operations. We treat and reuse water that is
co-produced with oil and natural gas for a substantial portion of our needs in activities such as
pressure management, waterflooding, steamflooding and well drilling, completion and stimulation. We
also provide reclaimed produced water to certain agricultural water districts. We also use supplied
water from various local and regional sources, particularly for power plants and steam generation. We
are a net fresh water supplier to the State. While our production to date has not been impacted by
restrictions on access to third-party water sources, we cannot guarantee that there may not be
restrictions in the future.

In 2014, at the request of the EPA, CalGEM commenced a detailed review of the multi-decade

practice of permitting underground injection wells and associated aquifer exemptions under the SDWA. In
2015, the state set deadlines to obtain the EPA’s confirmation of aquifer exemptions under the SDWA in
certain formations in certain fields. Since the state and the EPA did not complete their review before the
state’s deadlines, the state announced that it will not rescind permits or enforce the deadlines with
respect to many of the formations pending completion of the review but has applied the deadlines to
others. Several industry groups and operators challenged CalGEM’s implementation of its aquifer
exemption regulations. In March 2017, the Kern County Superior Court issued an injunction barring the
blanket enforcement of CalGEM’s aquifer exemption regulations. The court found that CalGEM must find
actual harm results from an injection well’s operations and go through a hearing process before the
agency can issue fines or shut down operations. During the review, the state has restricted injection in
certain formations or wells in several fields, including some operated by us, requested that we change
injection zones in certain fields, and held certain pending injection permits in abeyance. We are
coordinating with the state to change injection zones in certain fields to facilitate disposal of produced
water in deeper formations where feasible or to increase recycling of produced water in pressure
maintenance or waterfloods in lieu of disposal. In September 2021, the EPA issued a letter to the
California Natural Resources Agency and the State Water Resources Control Board regarding the state’s
compliance with the 2015 compliance plan relating to the state’s process for approving aquifer
exemptions under the SDWA. The letter requested that California take appropriate action by September
2022, or the EPA would consider taking additional action to impose limits on California’s administration of
the UIC program, withhold federal funds for the administration of the UIC program, and direct orders to oil
and natural gas operators injecting into formations not authorized by the EPA, among other measures.
The state responded in October 2021 with a proposed compliance plan and a follow-up letter in August
2022 providing a mid-year update, but, to date, the EPA has not yet responded.

With respect to major federal actions pursuant to NEPA, recent modifications may impose additional
restrictions on oil and natural gas activities on federal lands. In October 2021, the Biden Administration
announced three significant changes to a 2020 rule finalized under the Trump Administration. These
changes included (i) authorizing agencies to consider the direct, indirect and cumulative effects of major
federal actions including upstream and downstream impacts of fossil fuel projects; (ii) allowing agencies
to determine the purpose and need of a project (thereby allowing consideration of less-harmful
alternatives); and (iii) affording agencies greater flexibility in crafting their own NEPA procedures,
consistent with Council of Environmental Quality (CEQ) regulations, so as to meet the agencies’ and
public’s need. To that end, in April 2022, the CEQ issued a final rule in line with the proposed changes –
“Phase I” of the Biden Administration’s two-phased approach to modifying NEPA. “Phase 2” of the
process includes the release of a new rule proposing broader changes to NEPA regulations.

Federal, state and local agencies may assert overlapping authority to regulate in these areas. In
addition, certain of these laws and regulations may apply retroactively and may impose strict or joint
and several liability on us for events or conditions over which we and our predecessors had no control,
without regard to fault, legality of the original activities, or ownership or control by third parties.

Regulation of Carbon Capture, Sequestration and Storage

On September 16, 2022, the Governor of California signed Senate Bill No. 905 into law, which
contemplates the development of unitization, permitting and pipeline safety regulations over a multi-
year period to facilitate the development of CCS projects in California, though the legislation does not
provide for compulsory unitization. Protocols to support CCS are to be adopted by January 1, 2024 and
a unified permit application is to be adopted by January 1, 2025. We believe our Carbon TerraVault
projects, for which permits with the EPA have been filed, will continue to be developed on a timeline
consistent with our initial expectations. These initial projects are not reliant on the unitization or
permitting regulations being developed. In addition, our Carbon TerraVault projects are expected to
either use emitters that are directly sited above these storage facilities or rely on pipelines for
transporting CO2 that will need to comply with yet to be developed CO2 pipeline safety regulations from
the federal PHMSA, which could take a number of years to effect. However, the terms of the final
pipeline safety regulations may impair or prohibit those projects that rely on the transportation of CO2.
In addition, delays in developing the required pipeline safety regulations would delay projects requiring
pipeline transportation of CO2. The lack of compulsory unitization could also delay project timelines.

The unified permitting process contemplated by Senate Bill No. 905 will be optional for project

applicants and is intended to simplify the permitting process for CCS projects. In the meantime,
pursuant to this legislation we are permitted to proceed with our existing and future permit applications
with the EPA. This law also contemplates the implementation of a new regulatory program
incorporating standards that are not yet defined and that could affect the timing of future CCS projects
in California.

Senate Bill No. 905 also prohibits CCS projects that utilize and permanently sequester CO2 in

connection with Enhanced Oil Recovery (EOR) projects. In light of this prohibition and the
enhancement of energy credits under the Inflation Reduction Act of 2022 (the Act), we transitioned our
CalCapture project to target CCS.

We currently do not have any oil and natural gas production or proved reserves associated with
EOR projects that rely on CO2 floods. As a result, we do not expect the limitations on EOR activities
included in Senate Bill No. 905 to impact our existing oil and natural gas production or proved
reserves.

President Biden signed the Act into law on August 16, 2022. Beginning in 2024, the Act’s methane

emissions charge imposes a fee on excess methane emissions from certain oil and natural gas
facilities, including some of our facilities, starting at $900 per metric ton of leaked methane in 2024 and
rising to $1,200 in 2025, and $1,500 in 2026 and thereafter.

The Act also enhanced existing credits for emissions reduction and sequestration (45Q credit) by

increasing the size of the credit to $85 per metric ton when captured from industrial and power
generation facilities, and to $180 per metric ton when utilizing direct air capture facilities. The Act also
extended the date for when qualifying facilities must begin construction by seven years, among other
modifications. Further, a direct pay option for the 45Q credit (for a limited five-year period) was added
and the Act provides an option to monetize the 45Q credit through a sale to another taxpayer. These
additional energy-related tax incentives are effective for new projects beginning on January 1, 2023
and enhance the development of CCS projects in California.

Regulation of Climate Change and Greenhouse Gas (GHG) Emissions

A number of international, federal, state, regional and local efforts seek to prevent or mitigate the
effects of climate change or to track, mitigate and reduce GHG emissions associated with energy use
and industrial activity, including operations of the oil and natural gas production sector and those who
use our products as a source of energy or feedstocks. President Biden has made climate change a
focus of his administration, and he has issued several executive orders on the subject, which, among
other things, recommitted the United States to the Paris Agreement in 2021, called for the
reinstatement or issuance of methane emissions standards for new, modified and existing oil and
natural gas facilities (rules pertaining to which have been proposed by the EPA) and called for an
increased emphasis on climate-related risk across governmental agencies and economic sectors.
Additionally, the EPA has adopted federal regulations to:

•

•
•

require reporting of annual GHG emissions from oil and natural gas exploration and production,
power plants and natural gas processing plants; gathering and boosting compression and
pipeline facilities; and certain completions and workovers;
incorporate measures to reduce GHG emissions in permits for certain facilities; and
restrict GHG emissions from certain mobile sources.

California has adopted stringent laws and regulations to reduce GHG emissions. These state laws

and regulations:

•

established a “cap-and-trade” program for GHG emissions that sets a statewide maximum limit
on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by
2030, the year that the cap-and-trade program currently expires;
require allowances or qualifying offsets for GHGs emitted from California operations and for the
volume of natural gas, propane and liquid transportation fuels sold for use in California;
established a low carbon fuel standard (LCFS) and associated tradable credits that require a
progressively lower carbon intensity of the state’s fuel supply than baseline gasoline and diesel
fuels, and provide a mechanism to generate LCFS credits through innovative crude oil
production methods such as those employing solar or wind energy or carbon capture and
sequestration;

• mandated that California derive 60% of its electricity for retail customers from renewable

•

resources by 2030;
established a policy to derive all of California’s retail electricity from renewable or “zero-carbon”
resources by 2045, subject to required evaluation of the feasibility by state agencies;
imposed state goals to double the energy efficiency of buildings by 2030 and to reduce
emissions of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013
levels by 2030; and

• mandated that all new single family and low–rise multifamily housing construction in California

include rooftop solar systems or direct connection to a state–approved community solar system.

In addition, the current and former Governors of California and certain municipalities in California

have announced their commitment to adhere to GHG reductions called for in the Paris Agreement
through executive orders, pledges, resolutions and memoranda of understanding or other agreements
with various other countries, U.S. states, Canadian provinces and municipalities. In furtherance of this
commitment, in September 2022, the Governor of California signed Assembly Bill No. 1279 into law,
which codifies a previously issued executive order by the Governor’s Office requiring the state to
achieve carbon neutrality by 2025. In addition, the Governor of California previously issued an
executive order directing several agencies to take further actions with respect to reducing emissions of
GHGs. The Governor has also directed state agencies to implement other measures to mitigate
climate change and strengthen biodiversity, such as via the conservation of 30% of state lands and
waters by 2030. For more information, see Part I, Item 1A – Risk Factors, Risks Related to Regulation
and Government Action, Recent and future actions by the State of California could reduce both the
demand for and supply of oil and natural gas within the state and consequently have a material and
adverse effect on our business, results of operations and financial condition.

The EPA and the California Air Resources Board (CARB) have also expanded direct regulation of

methane as a contributor to GHG emissions. In 2016, the EPA adopted regulations to require
additional emission controls for methane, volatile organic compounds and certain other substances for
new or modified oil and natural gas facilities. Although the EPA rescinded the methane-specific
requirements for production and processing facilities in September 2020, the U.S. Congress
subsequently approved, and President Biden signed into a law, a resolution to repeal the September
2020 revisions to the methane standards, effectively reinstating the prior standards. Additionally, in
November 2021, the EPA issued a proposed rule that, if finalized, would establish new source and
first-time existing source standards of performance for methane and volatile organic compound
emissions for oil and natural gas facilities. In November 2022, the EPA issued a supplemental proposal
which sets forth specific revisions strengthening the first nationwide emissions guidelines for states to
limit methane from existing oil and natural gas facilities and revises requirements for fugitive emissions
monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, among
other items. The proposal is expected to be finalized in 2023, though it will likely be challenged.
Moreover, CARB has implemented more stringent regulations that require monitoring, leak detection,
repair and reporting of methane emissions from both existing and new oil and natural gas production,
pipeline gathering and boosting facilities and natural gas processing plants, as well as additional
controls such as tank vapor recovery to capture methane emissions.

Regulation of Transportation, Marketing and Sale of Our Products

Our sales prices of oil, NGLs and natural gas in the U.S. are set by the market and are not presently
regulated. In 2015, the U.S. federal government lifted restrictions on the export of domestically produced
oil that allows for the sale of U.S. oil production, including ours, in additional markets.

Federal and state laws regulate transportation rates for, and marketing and sale of, petroleum
products and electricity with respect to certain of our operations and those of certain of our customers,
suppliers and counterparties. Such regulations also govern:

•

interstate and intrastate pipeline transportation rates for oil, natural gas and NGLs in regulated
pipeline systems;
prevention of market manipulation in the oil, natural gas, NGL and power markets;

•
• market transparency rules with respect to natural gas and power markets;
•

the physical and futures energy commodities market, including financial derivative and hedging
activity; and
prevention of discrimination in natural gas gathering operations in favor of producers or sources
of supply.

•

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

International treaties and regulations also affect the marketing or sale of our products. For example,

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

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

Available Information

We make available, free of charge on our website www.crc.com, our Annual Reports on Form 10-K,

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

ITEM 1A

RISK FACTORS

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

Summary:

Risks Related to Our Business

• Prices for our products can fluctuate widely and an extended period of low prices could

materially and adversely affect our financial condition, results of operations, cash flow and ability
to invest in our assets.

• Our producing properties are located exclusively in California, making us vulnerable to risks

associated with having operations concentrated in this geographic area.

• We may not be able to successfully separate our carbon management business from our E&P

business, or we may decide not to effect such separation.

• Our ability to achieve our 2045 Full-Scope Net Zero target and other goals related to carbon

management activities, is subject to risks and uncertainties.

• Our ability to grow our Carbon TerraVault business and develop large scale CCS projects is

subject to numerous risks and uncertainties. If we are unable to successfully execute our CCS
strategy, it could have an adverse effect on our business, results of operations and financial
condition.

• The economics of CCS projects depend on financial and tax incentives that may not currently be

sufficient for our CCS projects to be economical or could be changed or terminated.

• Our Carbon TerraVault JV with Brookfield is subject to inherent uncertainties, which could force

us to delay or cancel CCS projects or seek alternative sources of capital to fund our CCS
projects and thereby adversely affect our ability to implement our carbon management strategy.
• Drilling for and producing oil and natural gas carry significant operational and financial risks and
uncertainty. We may not drill wells at the times we scheduled, or at all. Wells we do drill may not
yield production in economic quantities or generate the expected payback.

• Our business involves substantial capital investments. We may be unable to fund our capital

program, or reach satisfactory terms for other future capital requirements which could lead to a
decline in our oil and natural gas reserves or production. Our capital investment program is also
susceptible to risks that could materially affect its implementation.

• We have been negatively impacted by inflation.
• We are subject to economic downturns and the effects of public health events, such as the

COVID-19 pandemic, which may materially and adversely affect the demand and the market
price for our products.

• The conflict in Ukraine and related price volatility and geopolitical instability could negatively

impact our business.

• From time to time we may engage in step-out drilling, or drilling in new or emerging plays. Our

drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is
unsuccessful.

• Many of our current and potential competitors have or may potentially have greater resources
than we have and we may not be able to successfully compete in acquiring, exploring and
developing new properties.

• Our hedging activities limit our ability to realize the full benefits of increases in commodity prices.
• Our level of hedging activities may be impacted by financial regulations that could increase our

costs of hedging and/or limit the number of hedging counterparties available to us.

• Estimates of proved reserves and related future net cash flows are not precise. The actual

quantities of our proved reserves and future net cash flows may prove to be lower than estimated.

Risks Related to Regulation and Government Action

• We may not be able to timely obtain drilling permits as a result of recent and future actions by

the State of California.

• Recent and future actions by the State of California could reduce both the demand for and

supply of oil and natural gas within the state and consequently have a material and adverse
effect on our business, results of operations and financial condition.

• Our business is highly regulated and government authorities can delay or deny permits and

approvals or change requirements governing our operations, which could increase costs, restrict
operations and change or delay the implementation of our business plans.

• Our Carbon TerraVault business and our CCS projects are subject to extensive government

regulation that, among other things, requires us to obtain and maintain permits for the injection
and sequestration of CO2. Many of these regulations are still being developed. Failure to comply
with these requirements and obtain the necessary permits, or the development of government
regulations that are unfavorable to our CCS projects, could have an adverse effect on our
business, results of operations and financial condition.

• Recent changes in California law may result in delays to our carbon capture, sequestration and

storage projects.

• Concerns about climate change and other air quality issues may prompt governmental action

that could materially affect our operations or results.

• The Inflation Reduction Act could accelerate the transition to a low-carbon economy and could

impose new costs on our operations.

• Adverse tax law changes may affect our operations.

Risks Related to our Indebtedness

• We may not be able to amend or refinance our existing debt to create more operating and

financial flexibility and to enhance shareholder returns.

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

flexibility.

• We may not be able to generate sufficient cash to service all of our indebtedness and may be

forced to take other actions to satisfy the obligations under our indebtedness, which may not be
successful.

• The lenders under our Revolving Credit Facility could limit our ability to borrow and restrict our

ability to use or access to capital.

• Restrictive covenants in our Revolving Credit Facility and the indenture governing our Senior

Notes may limit our financial and operating flexibility.

• Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate risk,

which could cause our debt service obligations to increase significantly.

Risks Related to Our Common Stock

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

risks.

• The trading price of our common stock may decline, and you may not be able to resell shares of

our common stock at prices equal to or greater than the price you paid or at all.

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

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

• The ownership position of certain of our stockholders limits other stockholders’ ability to

influence corporate matters and could affect the price of our common stock.

• Sales of shares of our common stock by our executive officers could negatively impact the

market price for our common stock.

General Risk Factors

Increasing attention to ESG matters may adversely impact our business.

•
• Acquisition and disposition activities involve substantial risks.
• We may incur substantial losses and be subject to substantial liability claims as a result of

pollution, environmental conditions or catastrophic events. We may not be insured for, or our
insurance may be inadequate to protect us against, these risks.

• Cybersecurity attacks, systems failures and other disruptions could adversely affect us.

Risks Related to Our Business

Prices for our products can fluctuate widely and an extended period of low prices could

materially and adversely affect our financial condition, results of operations, cash flow and ability
to invest in our assets.

Our financial condition, results of operations, cash flow and ability to invest in our assets are highly
dependent on oil, natural gas and NGL prices. A sustained period of low prices for oil, natural gas and
NGLs would reduce our cash flows from operations and could reduce our borrowing capacity or cause a
default under our financing agreements.

Prices for oil, natural gas and NGL may fluctuate widely in response to relatively minor changes in
supply and demand, market uncertainty and a variety of additional factors that are beyond our control,
such as:

•
•
•

•

changes in domestic and global supply and demand;
domestic and global inventory levels;
political and economic conditions, including international disputes such as the conflict between
Ukraine and Russia;
pandemics, epidemics, outbreaks or other public health events, such as the COVID-19
pandemic;
the actions of OPEC and other significant producers and governments;
changes or disruptions in actual or anticipated production, refining and processing;

government energy policies and regulation, including with respect to climate change;
the effects of conservation;

•
•
• worldwide drilling and exploration activities;
•
•
• weather conditions and other seasonal impacts;
•
•
•
•
•
•
•

speculative trading in derivative contracts;
currency exchange rates;
technological advances;
transportation and storage capacity, bottlenecks and costs in producing areas;
the price, availability and acceptance of alternative energy sources;
regional market conditions; and
other matters affecting the supply and demand dynamics for these products.

Lower prices could have adverse effects on our business, financial condition, results of operations

and cash flow, including:

•
•
•

•

reducing our proved oil and natural gas reserves over time;
limiting our ability to grow or maintain future production;
causing a reduction in our borrowing base under our Revolving Credit Facility, which could
affect our liquidity;
reducing our cash flow and ability to make interest payments or maintain compliance with financial
covenants in the agreements governing our indebtedness, which could trigger mandatory loan
repayments and default and foreclosure by our lenders and bondholders against our assets;

•

affecting our ability to attract counterparties and enter into commercial transactions, including
hedging, surety or insurance transactions; and
limiting our access to funds through the capital markets and the price we could obtain for asset
sales or other monetization transactions.

Our hedging program does not provide downside protection for all of our production. As a result,
our hedges do not fully protect us from commodity price declines, and we may be unable to enter into
acceptable additional hedges in the future.

Our producing properties are located exclusively in California, making us vulnerable to risks

associated with having operations concentrated in this geographic area.

Our operations are concentrated in California. Because of this geographic concentration, the
success and profitability of our operations may be disproportionately exposed to the effect of regional
conditions. These changes in state or regional laws and regulations affecting our operations, local price
fluctuations and other regional supply and demand factors, including gathering, pipeline, transportation
and storage capacity constraints, limited potential customers, infrastructure capacity and availability of
rigs, equipment, oil field services, supplies and labor. Our operations are also exposed to natural
disasters and related events common to California, such as wildfires, mudslides, high winds,
earthquakes and extreme weather events, and the potential increase to the frequency of drought and
flooding. Further, our operations may be exposed to power outages, mechanical failures, industrial
accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be
shut in, delay operations and growth plans, decrease cash flows, increase operating and capital costs,
prevent development of lease inventory before expiration and limit access to markets for our products.

We may not be able to successfully separate or finance our carbon management business

from our E&P business, or we may decide not to effect such separation.

On February 24, 2023, we announced that we had adjusted our corporate operating structure,

including setting up a board of directors at Carbon TerraVault, to facilitate the separate operation of our
E&P and carbon management businesses. We also intend to pursue financing options for our carbon
management business that are separate from the rest of our business. Our carbon management
business faces operational, technological and regulatory risks that could be considerable due to early
stage nature of these projects and the sector generally, which may make it more difficult to
independently finance and there are no assurances that it will be a viable standalone business in the
near term or at all. Further, there can be no assurances that we will be able to successfully separate
our E&P and carbon management businesses. We also may decide not to pursue such separation if
we do not believe it would maximize shareholder value.

Our ability to achieve our 2045 Full-Scope Net Zero target and other goals related to our

carbon management activities, is subject to risks and uncertainties.

We have adopted a number of targets and objectives related to sustainability matters, including our
2045 Full-Scope Net Zero target and our energy transition strategy. Our efforts to research, establish,
accomplish, and accurately report on these targets and objectives expose us to numerous operational,
reputational, financial, legal, and other risks. Our ability to achieve any stated target or objective is not
guaranteed and is subject to numerous factors and conditions, some of which are outside of our
control. In particular, our 2045 Full-Scope Net Zero goal includes Scope 1, 2 and 3 emissions and
estimation and management of Scope 3 emissions is subject to some degree of uncertainty. We
cannot guarantee that we have been able to completely quantify the full scope of our emissions and
account for mitigating all such emissions in our Full-Scope Net Zero goal.

Our ability to achieve our 2045 Full-Scope Net Zero goal relies heavily on our ability to develop our
Carbon TerraVault business and related CCS projects, which is subject to uncertainties and risks. See
Risks Related to our Business – The economics of CCS projects depend on financial and tax
incentives that may not currently be sufficient for our CCS projects to be economical or could be
changed or terminated, Risks Related to our Business – Our Carbon TerraVault JV with Brookfield is
subject to inherent uncertainties, which could force us to delay or cancel CCS projects or seek
alternative sources of capital to fund our CCS projects and thereby adversely affect our ability to
implement our carbon management strategy. In addition, the commercial and regulatory environment
related to emissions reductions and reporting is evolving and uncertain, and changes in GHG emission
accounting methodologies or new developments related to climate science could impact our ability to
claim emissions reductions related to our sequestration activities and timely achieve our 2045 Full-
Scope Net Zero goal or at all. If we are not able to successfully develop Carbon TerraVault and its
CCS projects and claim related emissions reductions, or we are successful in separating our carbon
management business, our ability to achieve our 2045 Full-Scope Net Zero goal would be materially
and adversely affected.

Our business may face increased scrutiny from investors and other stakeholders related to our

sustainability activities, including the goals, targets, and objectives that we announce, and our
methodologies and timelines for pursuing them. If our sustainability practices do not meet investor or
other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to
attract or retain employees, and our attractiveness as an investment or business partner could be
negatively affected. Similarly, our failure or perceived failure to pursue or fulfill our sustainability-
focused goals, targets, and objectives, to comply with ethical, environmental, or other standards,
regulations, or expectations, or to satisfy various reporting standards with respect to these matters,
within the timelines we announce, or at all, could adversely affect our business or reputation, as well as
expose us to government enforcement actions and private litigation.

Our ability to grow our Carbon TerraVault business and develop large scale CCS projects is
subject to numerous risks and uncertainties. If we are unable to successfully execute our CCS
strategy, it could have an adverse effect on our business, results of operations and financial
condition.

We have announced a strategy to pursue the development of a carbon management business in

California. To our knowledge, there are no existing large scale CCS projects in California similar to
those that we are seeking to have developed. These projects face operational, technological and
regulatory risks that could be considerable due to early stage nature of these projects and the sector
generally. Our ability to successfully develop these projects depends on a number of factors that we
are not able to fully control, including the following:

• The development of large scale CCS projects is an emerging sector and there are no

meaningful precedents to gauge the likely range of economic terms upon which these projects
may be feasibly developed. In addition, any of the operational, regulatory or financial risks could
cause actual results to differ materially from expected payback or cause a project to become
uneconomic or less profitable than forecast.

• The development of CCS projects will require us, our joint venture partner, and third-party

emitters to make significant capital investments in the relevant technology and infrastructure and
we may not have sufficient capital resources to fund such investments. Such projects may also
depend on third party financing and such financing may not be available on reasonable terms or
at all. In some cases, these projects will involve the production and sale of hydrogen, ammonia
or other products and markets for some of these products are still being developed.

• The development of a CCS project will require us to enter into long term binding agreements

with large carbon emitters and other third parties and we may not be able to do so on agreeable
terms or at all. Such agreements are complex and may involve allocation of not only fees but
also various credits, incentives and environmental attributes associated with the storage of CO2.
Not all emission sources produce sufficiently large quantities of pure or relatively pure streams
of CO2, or have installed equipment to capture such CO2, so as to be useable in one or more of
our CCS projects. As a result, we cannot assure whether we will be able to procure sufficient
quantities of CO2 on terms that are acceptable to us, and the failure to do so may have a
material impact on our ability to execute our CCS strategy.

• The development and operation of cost-effective, commercial-scale hydrogen and ammonia

production facilities and associated sequestration facilities is highly complex. There can be no
assurances that our partners will be able to successfully develop these production facilities, or
that we will be able to develop the related sequestration facilities, in a timely manner or at all. In
addition, there can be no assurances that these facilities can be maintained and operated over
the longer term.

• Certain of our anticipated CCS project sites rely on pore space that we do not own and we may

need to enter into agreements with landowners to allow us to inject CO2.

• Complex recordkeeping and GHG emissions/sequestration accounting may be required in

connection with one or more of our projects, which may increase the costs of such operations.
Different methodologies may be required for various regulatory and non-regulatory accounts
regarding GHG emissions/sequestration at one or more of our projects, including but not limited
to compliance with the EPA’s Mandatory Greenhouse Gas Reporting Program.

• Carbon capture may be viewed as a pathway to the continued use of fossil fuels and there may be
organized opposition to CCS projects from environmental groups, local residents and legislators.
• We may need to transport CO2 in pipelines if a CCS project relies on storage space that is not
co-located with the production facilities. Our ability to transport CO2 is subject to regulatory
uncertainty, see Risks Related to Regulation and Government Action – Senate Bill 905 may
result in delays to our CCS projects described below.

• Other regulatory uncertainties, see Risks Related to Regulation and Government Action – Our

Carbon TerraVault business and our CCS projects are subject to extensive government
regulation that, among other things, requires us to obtain permits for the injection of CO2. Many
of these regulations are still being developed. Failure to comply with these requirements and
obtain the necessary permits, or the development of government regulation that is unfavorable
to our CCS projects, could have a material adverse effect on our business, results of operations
and financial condition described below.

There can be no assurances that we will successfully develop our CCS projects, including Carbon
TerraVault and CalCapture, and such failure could have an adverse effect on our business. Our carbon
management business is currently in an early stage of development, and we do not expect the failure
of a single CCS project to create an impact on our overall financial condition or operations. However,
as the scale of our CCS projects grows, so will their impact on our overall financial condition and
operations. Moreover, our failure to successfully develop our CCS projects would adversely affect our
ability to claim emissions reductions related to our sequestration activities and our ability to meet our
carbon management goals, which in turn could have an adverse effect on our business and reputation.

The economics of CCS projects depend on financial and tax incentives that may not

currently be sufficient for our CCS projects to be economical or could be changed or
terminated.

Congress has incentivized the development of carbon capture projects through the establishment of

tax credits for the capture and sequestration of CO2, the production of clean hydrogen and the
production of other clean fuels. The successful development of our CCS projects is dependent upon
our ability to directly or indirectly benefit from these tax credits. The amount of tax credits from which
we may directly or indirectly benefit on our CCS projects is dependent upon satisfaction of certain
requirements, which we cannot assure you that we (or our partners) will satisfy. One of those
requirements is that a minimum volume of CO2 is captured by the applicable carbon capture equipment
during each taxable year. If we or our counterparties are not able to capture the minimum volumes
(which could be for a variety of reasons), then the tax credit will not be available. Additional financial
incentives may also be required for our CCS projects to be economical. In particular, we anticipate that
CCS projects associated with carbon emission reductions for transportation fuels will generate LCFS
credits and that these additional credits will improve the economics of CCS projects. If the existing
legal requirements for incentives such as the tax credits available for the capture and sequestration of
CO2 and the production of clean hydrogen or LCFS are subsequently amended in a manner that such
incentives no longer apply or are restricted in application, directly or indirectly, to our projects, we may
not be able to successfully achieve an economic return from our CCS business or, alternatively, the
construction or operation of applicable projects may be substantially delayed such that one or more
projects is unprofitable or otherwise infeasible.

The ability to monetize the tax credits for CO2 capture and sequestration is not certain. Either the
new owners of the carbon capture facilities or the sequester must either have the ability to use the tax
credit for itself, utilize direct pay (which is limited to the first five years), procure tax equity financing or
transfer the credits to another tax-payer. The ability to utilize direct pay and the tax equity financing and
credit transfers markets for tax credits provided under the IRA are still being analyzed and subject to
further guidance from the IRS, and therefore many uncertainties and complexities with respect to the
ability to monetize these credits exist.

The tax credit for the capture and sequestration of CO2 requires that the captured CO2 be stored in
secure geological storage for long periods of time. If we are not able to satisfy this requirement for the
duration of time required, there is the risk of recapture of tax credits or LCFS credits from us (or our
partners) by the government, as well as a risk of indemnification obligations to our partners, claims
from landowners and potential for fines and penalties for violations of environmental requirements.
Accidental releases of CO2 could also adversely impact our ability to meet our 2045 Full-Scope Net
Zero goal.

There can be no assurances that we (or our partners) will successfully comply with the

requirements for the available tax credits or LCFS, and such failure could have an adverse effect on
our liquidity, financial condition and results of operations.

Our Carbon TerraVault JV with Brookfield is subject to inherent uncertainties, which could
force us to delay or cancel CCS projects or seek alternative sources of capital to fund our CCS
projects and thereby adversely affect our ability to implement our carbon management
strategy.

In August 2022, we entered into the Carbon TerraVault JV with Brookfield to pursue the

development of a carbon management business in California. The management and financing of the
joint venture are subject to inherent uncertainties. These uncertainties could potentially force us to
delay or cancel CCS projects or to seek alternative sources of capital to fund our CCS projects, any of
which could adversely affect our ability to achieve our 2045 Full-Scope Net Zero target and other goals
related to our carbon management activities.

Brookfield has committed an initial $500 million to invest in CCS projects that are jointly approved

through Carbon TerraVault JV. At the time the Carbon TerraVault JV was formed, Brookfield
committed to make an initial investment of $137 million payable in three equal installments. The first
$46 million installment was contributed to the joint venture in August 2022, and the next two
installments are due upon completion of certain pre-agreed milestones related to the permitting
process with the EPA and final investment decision. Future storage projects for Brookfield’s initial
commitment are subject to approval of the joint venture, including Brookfield. There can be no
assurances that any of these funding milestones will be achieved so that Brookfield will fund the rest of
its commitment.

Furthermore, even though we own a 51% interest in the Carbon TerraVault JV, we share decision
making power with Brookfield on matters that most significantly impact the economic performance of
the joint venture. Any failure to reach a decision with Brookfield could potentially prevent or delay our
pursuit of CCS projects or cause such projects to be cancelled. Moreover, if Brookfield does not
approve a proposed CCS project that we want to pursue, we will have to seek alternative sources of
capital to fund the project and there can be no assurances that such sources of capital will be
available.

Drilling for and producing oil and natural gas carry significant operational and financial risks

and uncertainty. We may not drill wells at the times we scheduled, or at all. Wells we do drill
may not yield production in economic quantities or generate the expected payback.

The exploration and development of oil and natural gas properties depend in part on our analysis of

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

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

Any of the forgoing operational or financial risks could cause actual results to differ materially from

the expected payback or cause a well or project to become uneconomic or less profitable than
forecast.

We have specifically identified locations for drilling over the next several years, which represent a
significant part of our long-term growth strategy. Our actual drilling activities may materially differ from
those presently identified. If future drilling results in these projects do not establish sufficient production
and reserves to achieve an economic return, we may curtail drilling or development of these projects.
We make assumptions about the consistency and accuracy of data when we identify these locations
that may prove inaccurate. We cannot guarantee that our identified drilling locations will ever be drilled
or if we will be able to produce crude oil or natural gas from these drilling locations. In addition, some of
our leases could expire if we do not establish production in the leased acreage. The combined net
acreage covered by leases expiring in the next three years represented 8% of our total net
undeveloped acreage at December 31, 2022.

Our business involves substantial capital investments, which may include acquisitions,

partnerships or joint venture arrangements with other oil and natural gas exploration and
production companies or financial investors. We may be unable to fund our capital program, or
reach satisfactory terms for other future capital requirements, which could lead to a decline in
our oil and natural gas reserves or production. Our capital investment program is also
susceptible to risks that could materially affect its implementation.

Our exploration, development and acquisition activities can involve substantial capital investments.
We intend to fund our 2023 capital program using cash flow from operations. Accordingly, a reduction
in projected operating cash flow could cause us to reduce our future capital investments. In general,
the ability to execute our capital plan depends on a number of factors, including:

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the amount of oil, natural gas and NGLs we are able to produce;
commodity prices;
regulatory and third-party approvals;
our ability to timely drill, complete and stimulate wells;
our ability to secure equipment, services and personnel; and
our liquidity and ability fund capital expenditures.

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

Unless we make sufficient capital investments and conduct successful development and

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

We have been negatively impacted by inflation.

Increases in inflation have had an adverse effect on us. Current and future inflationary effects may

be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal
policies, and geopolitical instability. In 2022, we experienced high single digit inflation for certain
materials and services we procure from vendors including OCTG, fluid hauling, drilling equipment and
mechanical and electrical labor services, among other items. We have taken measures to limit the
effects of the inflationary market by entering into contracts for materials and services with terms of one
to three years. Additionally, we continually look at productivity and performance improvements from our
vendors in order to mitigate these price increases and also to reduce volumes consumed. However,
there can be no assurances that such measures will be effective and we anticipate modest price
increases for materials and services in the future. Continuing increases in inflation could further
increase our costs of labor and other costs related to our business, which could have an adverse
impact on our business, financial position, results of operations and cashflows. Inflation has also
resulted in higher interest rates in the United States, which could increase the cost of our future
financing efforts.

We are subject to economic downturns and the effects of public health events, such as the

COVID-19 pandemic, which may materially and adversely affect the demand and the market
price for our products.

The COVID-19 pandemic has adversely affected the global economy, and has resulted in, among

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

Additionally, to the extent the COVID-19 pandemic or any resulting worsening of the global business

and economic environment adversely affects our business and financial results, it may also have the
effect of heightening or exacerbating many of the other risks described in the Risk Factors herein.

The conflict in Ukraine and related price volatility and geopolitical instability could

negatively impact our business.

In late February 2022, Russia launched significant military action against Ukraine. The conflict has

caused, and could intensify, volatility in the prices of natural gas, oil and NGLs, and the extent and
duration of the military action, sanctions and resulting market disruptions have been significant and
could continue to have a substantial impact on the global economy and our business for an unknown
period of time.

Further, in the fall of 2022, OPEC+ announced a 2 million barrel per day reduction in production
quotas. This action was taken largely in response to the U.S. decision to continue releasing crude from
its Strategic Petroleum Reserve. While actual OPEC+ production capabilities are difficult to discern,
any return to previous targeted production levels could cause commodity prices to decline which would
reduce the revenues we receive for our oil and natural gas production.

Materialization of either of the events described above may also magnify the impact of the other

risks described in this “Risk Factors” section.

From time to time we may engage in step-out drilling or drilling in new or emerging plays.

Our drilling results are uncertain, and the value of our undeveloped acreage may decline if
drilling is unsuccessful.

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

Many of our current and potential competitors have or may potentially have greater
resources than we have and we may not be able to successfully compete in acquiring,
exploring and developing new properties.

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

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

prices.

We enter into hedges to mitigate our economic exposure to commodity price volatility and ensure

our financial strength and liquidity by protecting our cash flows. Our Revolving Credit Facility also
includes a covenant that would require us to enter into a certain level of hedges if a financial metric
related to our indebtedness is no longer satisfied. In addition, we have previously entered into
incremental hedges above these requirements for certain time periods. These hedges expose us to the
risk of financial losses depending on commodity price movements and may prevent us from realizing
the full benefits of price increases. Our ability to realize the benefits of our hedges also depends in part
upon the counterparties to these contracts honoring their financial obligations. If any of our
counterparties are unable to perform their obligations in the future, we could be exposed to increased
cash flow volatility that could affect our liquidity.

Our level of hedging activities may be impacted by financial regulations that could
increase our costs of hedging and/or limit the number of hedging counterparties available
to us.

U.S. financial regulations can impact both our level of hedging activity as well as the potential

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

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

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

Estimates of proved reserves and related future net cash flows are not precise. The
actual quantities of our proved reserves and future net cash flows may prove to be lower
than estimated.

Many uncertainties exist in estimating quantities of proved reserves and related future net cash

flows. Our estimates are based on various assumptions that require significant judgment in the
evaluation of available information. Our assumptions may ultimately prove to be inaccurate.
Additionally, reservoir data may change over time as more information becomes available from
development and appraisal activities.

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

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

In addition, our reserves information represents estimates prepared by internal engineers. Although

85% of our estimated proved reserve volumes as of December 31, 2022 were audited by our
independent petroleum engineers, Ryder Scott and NSAI, we cannot guarantee that the estimates are
accurate.

Reserves estimation is a partially subjective process of estimating accumulations of oil and natural

gas. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows
from those reserves depend upon a number of variables and assumptions. Changes in these variables
and assumptions could require us to make significant negative reserves revisions, which could affect
our liquidity by reducing the borrowing base under our Revolving Credit Facility. In addition, factors
such as the availability of capital, geology, government regulations and permits, the effectiveness of
development plans and other factors could affect the source or quantity of future reserves additions.

Risks Related to Regulation and Government Action

We may face material delays related to our ability to timely obtain permits necessary for our

operations, or be unable to secure such permits on favorable terms or at all as a result of
numerous California political, regulatory, and legal developments.

We must obtain various governmental permits to conduct exploration and production activities, as

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

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

Recently, we have experienced delays obtaining permits as a result of litigation related to the Kern

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

We have also experienced delays obtaining drilling permits from CalGEM since the passage of

Senate Bill No. 1137, which established 3,200 feet as the minimum distance between new oil and natural
gas production wells and certain sensitive receptors such as homes, schools and businesses open to the
public. The law became effective January 1, 2023 and CalGEM issued emergency regulations
implementing the requirements of the law on January 6, 2023. However, on February 3, 2023, the
Secretary of State of California certified voter signatures collected in connection with a referendum for the
November 2024 ballot to repeal Senate Bill No. 1137. As a result, any implementation of Senate Bill
No. 1137 is stayed until it is put to a vote, although any stay could be delayed if there are legal challenges
to the Secretary of State’s certification. In addition, even during the stay, CalGEM could attempt to initiate
new rulemaking with respect to setbacks. There is significant uncertainty with respect to the ability to
book proved undeveloped reserves and drill within the setback zone established by Senate Bill No. 1137
and, as a result, we have only booked proved undeveloped reserves for which we already have permits
within the zone and intend to develop prior to the November 2024 ballot. As of December 31, 2022,
changes in our development plans due to Senate Bill No. 1137 reduced the net present value of our
proved undeveloped reserves by 24% and our overall proved reserves by 4%.

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

Recent and future actions by the State of California could reduce both the demand for and

supply of oil and natural gas within the state and consequently have a material and adverse
effect on our business, results of operations and financial condition.

In recent years, the Governor of California, the Legislature and state agencies have taken a series

of actions that could materially and adversely affect the state’s oil and natural gas sector. Most
recently, on September 16, 2022, the Governor of California signed Senate Bill No. 1137 into law,
which establishes 3,200 feet as the minimum distance between new oil and natural gas production
wells and certain sensitive receptors such as homes, schools or parks. Senate Bill No. 1137 is
currently stayed pending the outcome of the California General Election in November 2024. For
additional information, see Part I, Item 1 and 2 – Business and Properties, Regulation of the Industries
in Which We Operate, Regulation of Exploration and Production Activities.

The trend in California is to impose increasingly stringent restrictions on oil and natural gas

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

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

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

To operate in compliance with these laws and regulations, we must obtain and maintain permits,
approvals and certificates from federal, state and local government authorities for a variety of activities
including siting, drilling, completion, stimulation, operation, inspection, maintenance, transportation,
storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and
threatened or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection
and disposal and water consumption, recycling and reuse. For example, our operations in the
Wilmington Oil Field utilize injection wells to reinject produced water pursuant to waterflooding plans.
These operations are subject to regulation by both the City of Long Beach and CalGEM. We are
currently in discussions with the City of Long Beach and CalGEM with respect to what injection well
pressure gradient complies with CalGEM’s requirements for the protection of underground sources of
drinking water while at the same time mitigating subsidence risks. CalGEM’s local office has
preliminarily indicated that the injection well pressure gradient should be reduced from the gradient that
has been used for several decades. As part of our ongoing discussions, we and the City of Long Beach
have provided CalGEM with technical information regarding how the historical injection well pressure
gradient complies with CalGEM’s requirements and to inform them of the absence of risk of leakage. If
CalGEM were to ultimately disagree and determine to reduce the injection well pressure gradient, and
we were unable to reverse that decision on appeal or other legal challenge, we expect 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.

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, new regulations, or legal challenges to
existing approvals for our operations from individual citizens and non-governmental organizations. For
example, beginning in 2021, CalGEM ceased issuing new well stimulation permits and has slowed the
approval 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.

Our Carbon TerraVault business and our CCS projects are subject to extensive government

regulation that, among other things, requires us to obtain permits for the injection and
sequestration of CO2. Many of these regulations are still being developed. Failure to comply
with these requirements and obtain the necessary permits, or the development of government
regulations that are unfavorable to our CCS projects, could have an adverse effect on our
business, results of operations and financial condition.

Successful development of CCS projects in the United States require that we comply with what we

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

Separately, permitting CCS projects requires obtaining a number of other permits and approvals

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

As CCS and carbon management represent an emerging sector, laws and regulations may evolve

rapidly, which could impact the feasibility of one or more of our anticipated projects. To the extent
additional legal or regulatory requirements are imposed, are amended, or more stringently enforced,
we may incur additional costs in the pursuit of one or more of our carbon capture projects, which costs
may be material or may render any one or more of our projects uneconomical.

Recent changes in California law may result in delays to our carbon capture, sequestration

and storage projects.

On September 16, 2022, the Governor of California signed Senate Bill No. 905 into law, which
contemplates the development of unitization, permitting and pipeline safety regulations over a multi-
year period to facilitate the development of CCS projects in California, though the legislation does not
provide for compulsory unitization. Protocols to support CCS are to be adopted by January 1, 2024,
and a unified permit application is to be adopted by January 1, 2025. We believe our Carbon
TerraVault projects, for which permits with the EPA have been filed, will continue to be developed on a
timeline consistent with our initial expectations. These initial projects are not reliant on the unitization or
permitting regulations being developed. In addition, our Carbon TerraVault projects are expected to
either use emitters that are directly sited above these storage facilities or rely on pipelines for
transporting CO2 that will need to comply with yet to be developed CO2 pipeline safety regulations from
the federal Pipeline and Hazardous Materials Safety Administration, which could take a number of
years to effect. Delays in developing required pipeline safety regulations would delay projects requiring
pipeline transportation of CO2. The lack of compulsory unitization could also delay project timelines.

The unified permitting process contemplated by Senate Bill No. 905 will be optional for project applicants

and is intended to simplify the permitting process for CCS projects. In the meantime, pursuant to this
legislation we are permitted to proceed with our existing and future CCS Class VI permit applications with
the EPA. This law also contemplates the implementation of a new regulatory program incorporating
standards that are not yet defined and that could affect the timing of future CCS projects in California.

Senate Bill No. 905 also prohibits CCS projects that utilize and permanently sequester CO2 in
connection with EOR projects. Although we do not have any existing oil and natural gas production or
proved reserves associated with EOR projects, this legislation required us to transition our CalCapture
project to target CCS and may require us to make other adjustments to projects in the future.

Concerns about climate change and other air quality issues may prompt governmental

action that could materially affect our operations or results.

Governmental, scientific and public concern over the threat of climate change arising from GHG
emissions, and regulation of GHGs and other air quality issues, may materially affect our business in
many ways, including increasing the costs to provide our products and services and reducing demand
for, and consumption of, our products and services, and we may be unable to recover or pass through
a significant portion of our costs. In addition, legislative and regulatory responses to such issues at the
federal, state and local level may increase our capital and operating costs and render certain wells or
projects uneconomic, and potentially lower the value of our reserves and other assets. Both the EPA
and California have implemented laws, regulations and policies that seek to reduce GHG emissions.
California’s cap-and-trade program operates under a market system and the costs of such allowances
per metric ton of GHG emissions are expected to increase in the future as the CARB tightens program
requirements and annually increases the minimum state auction price of allowances and reduces the
state’s GHG emissions cap. As the foregoing requirements become more stringent, we may be unable
to implement them in a cost-effective manner, or at all.

In August 2022, President Biden signed the Act into law. The Act includes a charge on methane
emissions that is expected to be applicable to the reported annual methane emissions of certain oil and
natural gas facilities, above specified methane intensity thresholds, starting in 2024. The full impact of
future climate regulations is uncertain at this time and it is unclear what additional actions may be
taken that may have an adverse effect upon our operations.

To the extent financial markets view climate change and GHG or other emissions as an increasing
financial risk, this could adversely impact our cost of, and access to, capital and the value of our stock
and our assets. Current investors in oil and natural gas companies may elect in the future to shift some
or all of their investments into other sectors, and institutional lenders may elect not to provide funding
for oil and natural gas companies. There is also a risk that financial institutions will be required to adopt
policies that have the effect of reducing the funding provided to the fossil fuel sector. Additionally, in
March 2022, the Securities and Exchange Commission (SEC) released a proposed rule that would
establish a framework for the reporting of climate risks, targets and metrics. A final rule is expected to
be released in Q2 2023, but we cannot predict the final form and substance of the rule and its
requirements. The ultimate impact of the rule on our business is uncertain and upon finalization may
result in additional costs to comply with any such disclosure requirements, alongside increased costs
of and restrictions on access to capital.

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

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

The Inflation Reduction Act could accelerate the transition to a low-carbon economy and

could impose new costs on our operations.

In August 2022, President Biden signed the Act into law. The Act contains hundreds of billions of
dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric
vehicles and supporting infrastructure and CCS, amongst other provisions. In addition, the Act imposes
the first ever federal fee on the emission of GHGs through a methane emissions charge. The Act
amends the Clean Air Act to impose a fee on the emission of methane from sources required to report
their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas
production categories. The methane emissions charge would start in calendar year 2024 at $900 per
ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year thereafter.
Calculation of the fee is based on certain thresholds established in the Act. In addition, the multiple
incentives offered for various clean energy industries referenced above could further accelerate the
transition of the economy away from fossil fuels towards lower- or zero-carbon emission alternatives.
The methane charges and various incentives for clean energy industries could decrease demand for
crude oil and natural gas, increase our compliance and operating costs and consequently materially
and adversely affect our business and results of operations.

Adverse tax law changes may affect our operations.

We are subject to taxation by various tax authorities at the federal, state and local levels where we

do business. New legislation could be enacted by any of these government authorities that could
adversely affect our business. For example, the Act includes a new excise tax on certain repurchases
of corporate stock. The 1% stock buyback excise tax applies to certain publicly traded corporations that
repurchase stock from their shareholders after December 31, 2022. The amount subject to the excise
tax is the fair market value of stock repurchased by such corporation net of the fair market value of any
stock issued by such corporation during such taxable year. Although the application of this excise tax is
not entirely clear, any redemptions made after December 31, 2022 in connection with our Share
Repurchase Program will be subject to this excise tax. We do not believe that the effect of this new
excise tax will be significant in 2023.

In addition, from time to time, legislation has been proposed that would, if enacted into law, make

significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal
income tax benefits currently available to oil and natural gas exploration and production companies.
Such changes have included, but have not been limited to, (i) the repeal of percentage depletion
allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible
drilling and development costs; (iii) an extension of the amortization period for certain geological and
geophysical expenditures; (iv) the elimination of certain other tax deductions and relief previously
available to oil and natural gas companies; and (v) an increase in the U.S. federal income tax rate
applicable to corporations such as us. However, it is unclear whether any such changes will be
enacted and, if enacted, how soon any such changes would be effective. Additionally, legislation could
be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could
result in increased operating costs and/or reduced demand for our products. The passage of any such
legislation or any other similar change in U.S. federal income tax law could eliminate or postpone
certain tax deductions that are currently available with respect to natural gas and oil exploration and
development or could increase costs and any such changes could have an adverse effect on our
financial condition, results of operations and cash flows.

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

Risks Related to our Indebtedness

We may not be able to amend or refinance our existing debt to create more operating and

financial flexibility and to enhance shareholder returns.

In light of our strategic goals and the restrictions under our existing debt, we are evaluating options

to amend and extend or replace our Revolving Credit Facility, as well as refinancing options for our
Senior Notes. Our ability to refinance our debt depends on a variety of factors, including our ability to
access the commercial banking and debt capital markets. Changes in interest rates could also impact
our ability to refinance our debt. If interest rates increase, the interest expense burden of any
refinanced debt or other variable rate debt would increase even though the amount borrowed remained
the same. There can be no assurances that we will be successful in amending, replacing or refinancing
our existing debt on acceptable terms or at all.

Our existing and future indebtedness may adversely affect our business and limit our

financial flexibility.

As of December 31, 2022, we had $600 million of total long-term debt, and additional borrowing
capacity of $458 million under the Revolving Credit Facility (after taking into account $144 million of
outstanding letters of credit). The terms of our Revolving Credit Facility and Senior Notes permit us to
incur significant additional debt, some of which may be secured. Our level of future indebtedness could
affect our business in several ways, including the following:

•

•
•

•

limit management’s discretion in operating our business and our flexibility in planning for, or
reacting to, changes in our business and the industry in which we operate;
require us to dedicate a portion of our cash flow from operations to service our existing debt,
thereby reducing the cash available to finance our operations and other business activities due
to restrictions on our ability to obtain additional financing, make investments, lease equipment,
sell assets and engage in business combinations;
limit our ability to pay dividends and repurchase shares;
increase our vulnerability to downturns and adverse developments in our business and the
economy generally;
limit our ability to access the capital markets to raise capital on favorable terms or to obtain
additional financing for working capital, capital expenditures, acquisitions, general corporate or
other expenses, or to refinance existing indebtedness;

• make it more likely that a reduction in our borrowing base following a periodic redetermination

could require us to repay a portion of our then-outstanding bank borrowings; and

• make us vulnerable to increases in interest rates as our indebtedness under the Revolving

Credit Facility varies with prevailing interest rates.

Our ability to satisfy our obligations depends on our future operating performance and on economic,

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

We may not be able to generate sufficient cash to service all of our indebtedness, and may

be forced to take other actions to satisfy the obligations under our indebtedness, which may
not be successful.

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

The lenders under our Revolving Credit Facility could limit our ability to borrow and restrict

our use or access to capital.

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

The borrowing base under our Revolving Credit Facility is redetermined semi-annually by our
lenders who review the value of our reserves and other factors that may be deemed appropriate.
Currently, our borrowing base is set at $1.2 billion and the availability under our Revolving Credit
Facility is limited by the aggregate elected commitment amount of our lenders, which as of February 1,
2023 was set at $602 million.

A reduction in our borrowing base below the aggregate commitment amount of our lenders would

materially and adversely affect our liquidity and may hinder our ability to execute on our business
strategy.

Restrictive covenants in our Revolving Credit Facility and the indenture governing our

Senior Notes may limit our financial and operating flexibility.

Both our Revolving Credit Facility and the indenture governing our Senior Notes contain certain
restrictions, which may have adverse effects on our business, financial condition, cash flows or results
of operations. These restrictions limit our ability to, among other things, (i) incur additional
indebtedness; (ii) pay dividends or repurchase shares; (iii) sell properties; and (iv) make capital
investments.

The Revolving Credit Agreement also requires us to comply with certain financial maintenance

covenants, including a leverage ratio and current ratio.

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

Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate

risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Revolving Credit Facility are at variable rates of interest and expose us to
interest rate risk. As of December 31, 2022, we had no amounts borrowed under our Revolving Credit
Facility. If in the future we borrow under the Revolving Credit Facility, then our results of operations
would be sensitive to movements in interest rates. There are many economic factors outside our
control that have in the past and may, in the future, impact rates of interest including publicly
announced indices that underlie the interest obligations related to our Revolving Credit Facility. Factors
that impact interest rates include governmental monetary policies, inflation, economic conditions,
changes in unemployment rates, international disorder and instability in domestic and foreign financial
markets. If interest rates increase, our debt service obligations on the variable rate indebtedness would
increase even though the amount borrowed remained the same, and our results of operations would
be adversely impacted. Such increases in interest rates could have a material adverse effect on our
financial condition and results of operations if we borrow under the Revolving Credit Facility in the
future.

Risks Related to Our Common Stock

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

certain risks.

We have adopted a cash dividend policy which anticipates a total annual dividend of $1.13 per
share, payable to shareholders in quarterly increments of $0.2825 per share of common stock, subject
to board authorization and declaration each quarter. In addition, as of December 31, 2022, we had
remaining authorization under our Share Repurchase Program to repurchase up to $389 million of
shares of our common stock, before the increase of $250 million approved by our Board of Directors
on February 23, 2023. Any payment of future dividends or repurchasing shares of our common stock
will be at the discretion of our Board of Directors and will depend upon, among other things, our
earnings, liquidity, capital requirements, financial condition and other factors deemed relevant. Our
Revolving Credit Facility and Senior Notes both limit our ability to pay dividends and repurchase shares
of our common stock. In addition, cash dividend payments in the future may only be made out of
legally available funds and, if we experience substantial losses, such funds may not be available. We
can provide no assurances that we will continue to pay dividends at the anticipated rate or repurchase
shares of our common stock within the authorized amount or at all.

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

The trading price of our common stock may decline for many reasons, some of which are beyond

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

Future issuances of our common stock could reduce our stock price, and any additional

capital raised by us through the sale of equity or convertible securities may dilute your
ownership in us.

We may sell additional shares of common stock in subsequent public or private offerings. We may
also issue additional shares of common stock or convertible securities. As of December 31, 2022, we
had 71,949,742 outstanding shares of common stock and 4,295,434 shares of common stock issuable
upon exercise of outstanding warrants. We cannot predict the size of future issuances of our common
stock or securities convertible into common stock or the effect, if any, that future issuances and sales
of shares of our common stock will have on the market price of our common stock. Sales of substantial
amounts of our common stock (including shares issued in connection with an acquisition), or the
perception that such sales could occur, may adversely affect prevailing market prices of our common
stock.

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

Downward pressure on the market price of our common stock that likely will result from sales of our

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

The ownership position of certain of our stockholders limits other stockholders’ ability to

influence corporate matters and could affect the price of our common stock.

As of December 31, 2022, five of our shareholders owned at least 5% each and collectively owned

approximately 40% of our common stock. As a result, each of these stockholders, or any entity to
which such stockholders sell their stock, may be able to exercise significant control over matters
requiring stockholder approval. Further, because of this large ownership position, if these stockholders
sell their stock, the sales could depress our share price.

Sales of shares of our common stock by our executive officers could negatively impact the

market price for our common stock.

Following our emergence from bankruptcy in October 2020, we granted our executive officers
restricted stock units and performance stock units under our Long Term Incentive Plan. These units
are settled in shares of our common stock and a significant portion of these grants vest in January
2024. Sales of our common stock by our executive officers may adversely impact the trading price of
our common stock, even when done in compliance with our policies with respect to insider sales.
Although we do not expect that the relatively small volume of such sales will itself significantly impact
the trading price of our common stock, the market could react negatively to the announcement of such
sales, which could in turn affect the trading price of our common stock.

General Risk Factors

Increasing attention to ESG matters may adversely impact our business.

Organizations that provide information to investors on corporate governance and related matters
have developed ratings processes for evaluating companies on their approach to ESG matters. Such
ratings are used by some investors to evaluate their investment and voting decisions. Companies in
the energy industry, and in particular those focused on oil or natural gas extraction, often do not score
as well under ESG assessments compared to companies in other industries. Unfavorable ESG ratings
may lead to increased negative investor sentiment toward us and to the diversion of their investment
away from the fossil fuel industry to other industries which could have a negative impact on our stock
price and our access to and costs of capital. To the extent ESG matters negatively impact our
reputation, we may not be able to compete as effectively or recruit or retain employees, which may
adversely affect our operations.

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time

to time, many of the statements in those voluntary disclosures will be based on expectations and
assumptions that may or may not be representative of actual risks or events, including the costs
associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone
to error or subject to misinterpretation given the long timelines involved and the lack of an established
single approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we
may also announce various voluntary ESG targets, such targets are aspirational. We may not be able
to meet such targets in the manner or on such a timeline as initially contemplated, including, but not
limited to as a result of unforeseen costs or technical difficulties associated with achieving such results.
To the extent we do meet such targets, they may ultimately be achieved through various contractual
arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our
ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that
there will be sufficient offsets available for purchase given the increased demand from numerous
businesses implementing net zero goals, or that, notwithstanding our reliance on any reputable third-
party registries, that the offsets we do purchase will successfully achieve the emissions reductions they
represent. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or
other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee
that we will be able to implement such goals because of potential costs or technical or operational
obstacles.

Public statements with respect to ESG matters, such as emissions reduction goals, other
environmental targets, or other commitments addressing certain social issues, are becoming
increasingly subject to heightened scrutiny from public and governmental authorities related to the risk
of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG
benefits. As a result, we may face increased litigation risks from private parties and governmental
authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or
others in our industry may lead to further negative sentiment and diversion of investments. Additionally,
we could face increasing costs as we attempt to comply with and navigate further ESG-related focus
and scrutiny.

Such ESG matters may also impact our customers or suppliers, which may adversely impact our

business, financial condition, or results of operations.

Acquisition and disposition activities involve substantial risks.

Our acquisition activities carry risks that we may:

•

•
•
•

not fully realize anticipated benefits due to less-than-expected reserves or production or
changed circumstances;
bear unexpected integration costs or experience other integration difficulties;
assume liabilities that are greater than anticipated; and
be exposed to currency, political, marketing, labor and other risks.

In connection with our acquisitions, we are often only able to perform limited due diligence. Successful

acquisitions of oil and natural gas properties require an assessment of a number of factors, including
estimates of recoverable reserves, the timing for recovering the reserves, exploration potential, future
commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such
assessments are inexact and incomplete, and we may be unable to make these assessments with a high
degree of accuracy. If we are not able to make acquisitions, we may not be able to grow our reserves or
develop our properties in a timely manner or at all.

We regularly review our property base for the purpose of identifying nonstrategic assets, the

disposition of which would increase capital resources available for other activities and create
organizational and operational efficiencies. Our disposition activities carry risks that we may:

•
•
•
•

not be able to realize reasonable prices or rates of return for assets;
be required to retain liabilities that are greater than desired or anticipated;
experience increased operating costs; and
reduce our cash flows if we cannot replace associated revenue.

There can be no assurance that we will be able to divest assets on financially attractive terms or at all.
Our ability to sell assets is also limited by the agreements governing our indebtedness. If we are not able
to sell assets as needed, we may not be able to generate proceeds to support our liquidity and capital
investments.

We may incur substantial losses and be subject to substantial liability claims as a result of
pollution, environmental conditions or catastrophic events. We may not be insured for, or our
insurance may be inadequate to protect us against, these risks.

We are not fully insured against all risks. Our business and assets are subject to risks from natural
disasters and operating risks associated with oil and natural gas exploration and production activities.
Pollution or environmental conditions with respect to our operations or on or from our properties, whether
arising from our operations or those of our predecessors or third parties, could expose us to substantial
costs and liabilities. Such events may cause operations to cease or be curtailed and could adversely
affect our business, workforce and the communities in which we operate. The cost and availability of
obtain insurance for natural disasters has increased in recent years. We may be unable to obtain, or may
elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is
excessive relative to the risks presented.

Cybersecurity attacks, systems failures, and other disruptions could adversely affect us.

We rely on electronic systems and networks to communicate, control and manage our exploration,
development and production activities. We also use these systems and networks to prepare our financial
management and reporting information, to analyze and store data and to communicate internally and with
third parties, including our service providers and customers. If we record inaccurate data or experience
infrastructure outages, our ability to communicate and control and manage our business could be
adversely affected.

Cybersecurity attacks on businesses have escalated and become more sophisticated. If we or the
third parties with whom we interact were to experience a successful attack, the potential consequences
to our business, workforce and the communities in which we operate could be significant, including
financial losses, loss of business, litigation risks and damage to reputation. We utilize various
technologies, controls and procedures, as well as internal staff and external specialists to protect our
systems and data, to identify and remediate vulnerabilities and to monitor and respond to threats.
However, there can be no assurance that such measures will be sufficient to prevent security breaches
from occurring. If a breach occurs, it may remain undetected for an extended period of time. If we or
third parties with whom we interact were to experience a cybersecurity attack or a successful breach,
the potential consequences could be significant, including loss of data, loss of business, damage to our
reputation, potential financial or legal liability requiring us to incur significant costs, disruptions related
to investigations and costs related to remediation.

Energy-related assets may be at a greater risk of strategic terrorist attacks or cybersecurity attacks

than other targets. A cybersecurity attack on the digital technology that controls most oil and natural
gas refining and distribution necessary to transport and market our products could impact critical
distribution and storage assets or the environment, disrupt energy markets by delaying or preventing
product delivery, or make it difficult or impossible to accurately account for production and settle
transactions.

As cybersecurity threats continue to evolve in sophistication and magnitude, we may be required to
expend significant additional resources to continue to modify or enhance our protective measures or to
investigate and remediate any cybersecurity vulnerabilities. Further, state and federal cybersecurity
and data privacy legislation could result in complex new requirements that increase our cost of doing
business.

ITEM 1B UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 3

LEGAL PROCEEDINGS

For information regarding legal proceedings, see Part II, Item 7 – Management’s Discussion and

Analysis of Financial Condition and Results of Operations – Lawsuits, Claims, Commitments and
Contingencies and Part II, Item 8 – Financial Statements and Supplementary Data – Note 6 Lawsuits,
Claims, Commitments and Contingencies.

ITEM 4 MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5 MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER

MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information for Common Stock

Since our emergence from bankruptcy on October 27, 2020, our common stock has been listed
under the symbol “CRC” on the New York Stock Exchange (NYSE). During the period from July 16,
2020 through October 26, 2020, the Predecessor company’s common stock was quoted on the OTC
Pink Market under the symbol “CRCQQ”. Prior to July 16, 2020, the Predecessor company’s common
stock was listed on the NYSE under the symbol “CRC”.

Holders of Record

Our common stock was held by 4 stockholders of record at January 31, 2023, which does not

include the beneficial owners for whom Cede and Co. or others act as nominees.

Dividend Policy

Our Board of Directors has approved a cash dividend policy that contemplates a total annual
dividend of $1.13 per share of common stock, payable to stockholders in quarterly increments of
$0.2825 per share. This includes a recent amendment in the fourth quarter of 2022 to our prior
dividend policy that contemplated a total quarterly dividend of $0.17 per share of common stock
approved. All dividends are subject to quarterly approval by our Board of Directors and will be
determined based on conditions including, our earnings, financial condition, restrictions from our
Revolving Credit Facility, Senior Notes, business conditions and other factors. Based on current
conditions and subject to Board approval, we expect to continue paying regular quarterly dividends of
$0.2825 per share throughout 2023.

Share Repurchases

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. This includes a recent increase of $250 million to our Share
Repurchase Program and extension through June 30, 2024 approved by our Board of Directors on
February 23, 2023. Our Share Repurchase Program does not obligate us to acquire any number of
shares and may be discontinued at any time. For further information regarding our Share Repurchase
Program, see Part II, Item 7 – Management’s Discussion and Analysis of Financial Results of
Operations, Share Repurchase Program. Our share repurchase activity for the year ended
December 31, 2022 was as follows:

Period

Total
Number of
Shares
Purchased

Average
Price
Paid per
Share

Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs

Maximum Dollar
Value of Shares that
May Yet be
Purchased Under the
Plans or Programs(a)

January 1, 2022 - March 31, 2022 . . . . . . . . .
April 1, 2022 - June 30, 2022 . . . . . . . . . . . . . .
July 1, 2022 - September 30, 2022 . . . . . . . . .
October 1, 2022 - October 31, 2022 . . . . . . . .
November 1, 2022 - November 30, 2022 . . . .
December 1, 2022 - December 31, 2022 . . . .

1,668,456 $ 42.52
2,255,445 $ 42.57
1,921,181 $ 41.78
682,792 $ 42.19
306,006 $ 45.77
532,392 $ 42.92

Total 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . .

7,366,272 $ 42.47

1,668,456 $
2,255,445
1,921,181
682,792
306,006
532,392

7,366,272 $

—
—
—
—
—
—

—

(a) The remaining capacity for shares that may be acquired under our Share Repurchase Program was $389 million as of

December 31, 2022.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table summarizes the securities available for issuance under equity compensation
plans as of December 31, 2022. A description of our stock-based compensation plans can be found in
Part II, Item 8 – Financial Statements and Supplementary Data, Note 10 Stock-Based Compensation.

Plan Category

Equity compensation plans
approved by security holders(1)
Equity compensation plan not
approved by security holders(2)

. . . .

Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights
(a)

Weighted-
average
exercise price
of outstanding
options,
warrants and
rights
(b)

Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities in column
(a))
(c)

1,250,000

2,098,436

—

1,223,781

7,159,304

8,383,085
Total . . . . . . . . . . . . . . . . . . . . . . . . . .
(1) Reflects shares available under our Employee Stock Purchase Plan for purchase at 85% of the lower of the market price at

3,348,436

either (i) the beginning of a quarter or (ii) the end of a quarter.

(2) The aggregate number of 9,257,740 shares of our common stock authorized for issuance under our Long-Term Incentive

Plan were approved by the Bankruptcy Court as part of the joint plan of reorganization upon our emergence from
bankruptcy. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 15 Chapter 11 Proceedings for more
information on the joint plan of reorganization. The number of securities to be issued upon vesting of performance stock
units assumes all units are earned upon achieving the specified 60-trading day volume weighted average prices for shares
of our common stock. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 10 Stock-Based
Compensation for more information on these awards.

Performance Graph

The following graph compares the cumulative total return to stockholders on our common stock
relative to the cumulative total returns of the S&P 500 and Dow Jones U.S. Exploration and Production
indexes and our peer group. The graph assumes that on October 28, 2020, $100 was invested in our
common stock and in each of the peer group companies’ common stock weighted by their relative market
capitalization, or invested on October 31, 2020 in an index, and that all dividends were reinvested. The
results shown are based on historical results and are not intended to suggest future performance.

Our 2021 peer group consisted of Antero Resources Corporation; Berry Corporation; Callon
Petroleum Company; Chord Energy Corp (the combination of Oasis Petroleum Inc and Whiting
Petroleum Corporation which merged in 2022); Comstock Resources Inc.; Coterra Energy Inc.; Denbury
Inc.; Kosmos Energy Ltd.; Magnolia Oil & Gas Corp; Matador Resources Company; Murphy Oil
Corporation; PDC Energy, Inc.; Range Resources Corporation; SM Energy Company; Southwestern
Energy Company; and Vermilion Energy Inc.

Our 2022 peer group consisted of Antero Resources Corporation; Berry Corporation; Callon
Petroleum Company; Chord Energy Corporation; Comstock Resources Inc.; Coterra Energy Inc.;
Crescent Energy Company; Denbury Inc.; Kosmos Energy Ltd.; Magnolia Oil & Gas Corp; Matador
Resources Company; Murphy Oil Corporation; PDC Energy, Inc.; Range Resources Corporation; SM
Energy Company; Southwestern Energy Company; Talos Energy Inc.; and Vermilion Energy Inc.

Our peer group changed from the prior year. We added Crescent Energy Company which is a newly
formed company with similar market capitalization and operations. We also added Talos Energy Inc. to
our peer group due to its similar financial, operational and strategic metrics as well as its presence in the
carbon sequestration sector in the United States.

PERFORMANCE GRAPH*
Among California Resources Corp, the S&P 500 Index,
the Dow Jones US Exploration & Production Index,
2021 Peer Group and 2022 Peer Group

$450

$400

$350

$300

$250

$200

$150

$100

$50

$0
10/28/20 12/31/20

3/31/21

6/30/21

9/30/21

12/31/21

3/31/22

6/30/22

9/30/22

12/31/22

California Resources Corp

S&P 500

Dow Jones US Exploration & Production

2021 Peer Group

2022 Peer Group

*$100 invested on 10/28/20 in stock or 10/31/20 in index, including reinvestment of dividends.
Fiscal year ending December 31.

10/28/20 12/31/20 3/31/21 6/30/21 9/30/21 12/31/21 3/31/22 6/30/22 9/30/22 12/31/22

California Resources Corp
S&P 500
Dow Jones US Exploration &

Production
2021 Peer Group
2022 Peer Group

100.00
100.00

157.27
115.21

160.40 200.93 273.33
122.33 132.78 133.56

285.97
148.28

300.68 259.81 260.22
141.47 118.69 112.89

296.45
121.43

100.00
100.00
100.00

143.37
123.79
123.98

192.09 221.97 226.75
192.31 255.22 285.49
192.30 255.07 283.86

245.05
279.94
276.93

337.58 318.37 344.37
411.95 365.19 387.84
407.17 359.56 382.17

391.02
394.74
388.55

* This performance graph shall not be deemed “soliciting material” or to be “filed” with the SEC for purposes of Section 18 of the
Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liabilities under that Section, and shall
not be deemed to be incorporated by reference into any filing of CRC under the Securities Act of 1933, as amended, or the
Exchange Act except to the extent that we specifically request it be treated as soliciting material or specifically incorporate it by
reference.

ITEM 6 RESERVED

ITEM 7 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

The following discussion should be read in conjunction with other sections of this report, including but

not limited to, Part I, Item 1 and 2 – Business and Properties and Part II, Item 8 – Financial Statements
and Supplementary Data.

Basis of Presentation

All financial information presented consists of our consolidated results of operations, financial
position and cash flows unless otherwise indicated. We have eliminated all significant intercompany
transactions and accounts. We account for our share of oil and natural gas production 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 balance sheets and statements of
operations and cash flows.

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy

Code. On October 13, 2020, the Bankruptcy Court confirmed our joint plan of reorganization (the Plan)
and we subsequently emerged from Chapter 11 on October 27, 2020 with a new Board of Directors, new
equity owners and a significantly improved financial position.

We qualified for and adopted fresh start accounting upon emergence from bankruptcy at which point
we became a new entity for financial reporting purposes. We adopted an accounting convenience date of
October 31, 2020 for the application of fresh start accounting. As a result of the application of fresh start
accounting and the effects of the implementation of the Plan, the financial statements after October 31,
2020 may not be comparable to the financial statements prior to that date. References to “Predecessor”
refer to the Company for periods ended on or prior to October 31, 2020 and references to “Successor”
refer to the Company for periods subsequent to October 31, 2020. See Part II, Item 8 – Financial
Statements and Supplementary Data, Note 15 Chapter 11 Proceedings and Note 16 Fresh Start
Accounting for more information.

The periods November 1, 2020 through December 31, 2020 (Successor period) and January 1, 2020
through October 31, 2020 (Predecessor period) are distinct reporting periods as a result of the adoption
of fresh start accounting. Certain operating results and performance measures were not significantly
impacted by the reorganization. Accordingly, we believe that discussing the combined results for the two
periods in 2020 is relevant and useful when making comparisons between periods for certain items such
as production, realized prices, production costs and general and administrative expenses. While this
combined presentation is not in accordance with generally accepted accounting principles in the United
States (GAAP) and no comparable GAAP measures are presented, management believes that providing
this information supplements the discussion of our results. For items that are not comparable (for
example depreciation, depletion and amortization, interest expense and noncontrolling interest), our
discussion addresses Predecessor and Successor results separately.

Supply Chain Constraints and Inflation

The Russia-Ukraine conflict negatively impacted the supply of steel-based raw materials which are

utilized in manufacturing products used in our business. Additionally, the COVID-19 pandemic has
continued to create challenges including disrupting global supply chains. These global events caused
intermittent disruptions in our ability to acquire certain tools, pipe and other oilfield equipment. These
disruptions resulted in cost increases but did not materially affected our development plans or
operations. The continued impact on our supply chains and prices for goods is likely to continue for the
foreseeable future.

Operating and capital costs in the oil and natural gas industry are heavily influenced by commodity

prices. Typically, suppliers will negotiate price increases for drilling and completion services, oilfield
services, equipment and materials as prices rise for energy-related commodities and raw materials (such
as steel, metals and chemicals). In 2022, we experienced high single digit inflation for certain materials
and services we procure from vendors including OCTG, fluid hauling, drilling equipment and mechanical
and electrical labor services, among other items. We also experienced higher natural gas and electricity
prices as well as increased compensation-related expenses in 2022.

We have taken measures to limit the effects of the inflationary market by entering into contracts for
materials and services with terms of one to three years. Additionally, we continually look at productivity
and performance improvements from our vendors in order to mitigate these price increases and also to
reduce volumes consumed. We anticipate moderate price increases for certain purchased goods and
services in 2023.

We continue to implement state and local county guidelines to protect the health of our workforce and

to support the prevention of COVID-19 at our plants, rigs, fields and administrative offices. We have not
experienced any operational slowdowns due to COVID-19 among our workforce.

Production, Prices and Realizations

The following table sets forth our average net production volumes of oil, NGLs and natural gas per
day for the years ended December 31, 2022 and 2021, the Successor period from November 1, 2020
through December 31, 2020, the Predecessor period from January 1, 2020 through October 31, 2020
and the combined year ended December 31, 2020:

Successor

Predecessor Combined

2022

2021

November 1, 2020 -
December 31, 2020

January 1, 2020 -
October 31, 2020

2020

Oil (MBbl/d)

San Joaquin Basin . . .
Los Angeles Basin . . . .
Ventura Basin . . . . . . .

Total

. . . . . . . . . . . . .

NGLs (MBbl/d)

San Joaquin Basin . . .

Total

. . . . . . . . . . . . .

Natural gas (MMcf/d)

San Joaquin Basin . . .
Los Angeles Basin . . . .
Ventura Basin . . . . . . .
Sacramento Basin . . . .

Total

. . . . . . . . . . . . .

Total Daily Net
Production (MBoe/d) . . .

37
18
—

129
1
—
17

147

39
19
2

135
1
4
19

159

100

38
23
2

138
1
3
23

165

103

42
25
3

147
2
4
21

174

112

42
24
3

145
2
4
21

172

111

The following table summarizes the changes to our total daily net production for each period

presented:

Beginning of the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Divestitures(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant downtime(b)
Acquisitions(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSC effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural decline and other . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

End of the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Year ended
December 31, 2022

Year ended
December 31, 2021

(in MBoe/d)
100
(5)
(1)
1
—
(4)

(9)

111
(1)
—
1
(3)
(8)

(11)

100

(a) See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more
information.
(b) In the first quarter of 2022, we conducted routine maintenance at one of our gas processing facilities.

Our operating results and those of the oil and natural gas industry as a whole are heavily influenced

by commodity prices. Global commodity prices increased during 2021 and continued in 2022 amid
strong demand recovery from the economic impacts of COVID-19, among other factors. 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. The following tables set

forth average benchmark prices, average realized prices and price realizations as a percentage of
average benchmark prices for our products for the periods indicated below:

Successor

2022

2021

Average
Price

Realization

Average
Price

Realization

Oil ($ per Bbl)
Brent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

98.89

Realized price without derivative settlements . . . . . . . . . $
Effects of derivative settlements . . . . . . . . . . . . . . . . . . . .

98.26
(36.46)

99%

Realized price with derivative settlements . . . . . . . . . . . . $

61.80

62%

WTI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price without derivative settlements . . . . . . . . . $
Realized price with derivative settlements . . . . . . . . . . . . $

94.23
98.26
61.80

104%
66%

NGLs ($ per Bbl)
Realized price(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

64.33
64.33

65%
68%

Natural gas
NYMEX ($/MMBTU) - Contract Month Average . . . . . . . $

6.36

Realized price without derivative settlements

($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

Effects of derivative settlements . . . . . . . . . . . . . . . . . . . .

7.68
(0.14)

121%

Realized price with derivative settlements

($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

7.54

119%

NYMEX ($/MMBTU) - Average Monthly Settled Price . . $

6.64

Realized price without derivative settlements
($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Effects of derivative settlements . . . . . . . . . . . . . . . . . . . . $

Realized price with derivative settlements
($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

7.68
(0.14)

116%

7.54

114%

(a) Realization is calculated as a percentage of Brent.
(b) Realization is calculated as a percentage of WTI.

$
$
$

$
$

70.79

70.43
(14.38)

99%

56.05

79%

67.91
70.43
56.05

104%
83%

53.62
53.62

76%
79%

3.61

4.22
(0.02)

117%

4.20

116%

3.84

4.22
(0.02)

110%

4.20

109%

Successor

Predecessor

November 1, 2020 -
December 31, 2020

January 1, 2020 -
October 31, 2020

Average
Price

Realization

Average
Price

Realization

Oil ($ per Bbl)
Brent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

47.10

Realized price without derivative settlements . . . . . . . . . $
Effects of derivative settlements . . . . . . . . . . . . . . . . . . . .

45.65
(0.28)

97%

Realized price with derivative settlements . . . . . . . . . . . . $

45.37

96%

44.21
45.65
45.37

103%
103%

NGLs ($ per Bbl)
Realized price(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

38.00
38.00

81%
86%

Natural gas
NYMEX ($/MMBTU) - Contract Month Average . . . . . . . $

2.86

Realized price without derivative settlements

($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

Effects of derivative settlements . . . . . . . . . . . . . . . . . . . .

3.21
(0.07)

112%

Realized price with derivative settlements

($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

3.14

110%

NYMEX ($/MMBTU) - Average Monthly Settled Price . . $

2.95

. . $
Realized price without derivative settlements ($/Mcf)
Effects of derivative settlements . . . . . . . . . . . . . . . . . . . . $

3.21
(0.07)

109%

Realized price with derivative settlements
($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

3.14

106%

(a) Realization is calculated as a percentage of Brent.
(b) Realization is calculated as a percentage of WTI.

$
$
$

$
$

42.43

41.21
1.98

43.19

38.44
41.21
43.19

97%

102%

107%
112%

25.70
25.70

61%
67%

1.95

2.11
0.06

108%

2.17

111%

1.90

2.11
0.06

111%

2.17

114%

Oil — Brent index and realized prices excluding hedge settlements were higher for the year ended

December 31, 2022 compared to 2021. Capital and production discipline across domestic and
international producers generally offset continued COVID-19 lockdowns in China, reduced energy
demand across much of Europe and the release of meaningful quantities of oil from the United States
Strategic Petroleum Reserve.

NGLs — Prices for NGLs increased in the year ended December 31, 2022 compared to 2021.

Prices increased as NGL markets benefited from higher energy and fuel prices, as a whole.

Natural Gas — In 2022, natural gas prices increased both across the United States and within

California compared to 2021 primarily due to strong domestic demand for power generation.

Divestitures

From time to time, we review our extensive portfolio of assets for potential divestitures. See Part II,
Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more
information on our transactions during years ended December 31, 2022 and 2021, the Successor period
from November 1, 2020 through December 31, 2020 and the Predecessor period from January 1, 2020
through October 31, 2020.

Acquisitions and Joint Ventures

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Investment in
Unconsolidated Subsidiary and Related Party Transactions for more information on our Carbon
TerraVault JV.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Joint Ventures in our

2020 Form 10-K for more information on the history of our joint ventures.

Dividend Policy

Our Board of Directors declared a cash dividend of $0.17 per share of common stock in each of the
first three quarters of 2022. On November 2, 2022, our Board of Directors approved an increase in our
dividend policy to an expected total annual dividend of $1.13 per share of common stock. Dividends are
payable to shareholders in quarterly increments, subject to the quarterly approval of our Board of
Directors. Our Board of Directors approved a quarterly cash dividend on November 2, 2022 in the
amount of $0.2825 per share of common stock. For the year ended December 31, 2022, we paid
$59 million in cash dividends on our common stock.

On February 23, 2023, our Board of Directors declared a cash dividend of $0.2825 per share of
common stock. The dividend is payable to shareholders of record at the close of business on March 6,
2023 and is expected to be paid on March 16, 2023.

Share Repurchase Program

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $850 million of
our common stock through December 31, 2023. On February 23, 2023 our Board of Directors increased
the Share Repurchase Program by $250 million to $1.1 billion and extended the program 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. Shares
repurchased are held as treasury stock.

Total Number of
Shares Purchased
(number of shares)

Dollar Value of
Shares Purchased
(in millions)

Average Price Paid
per Share
($ per share)

Year ended December 31, 2021 . . .
Year ended December 31, 2022 . . .

4,089,988
7,366,272

$
$

Total for 2021 and 2022 . . . . . .

11,456,260

148 $
313 $

461 $

36.08
42.47

40.19

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 11 Stockholders’ Equity
for more information on our share repurchase activity during the years ended December 31, 2022 and
2021.

Seasonality

Certain of our operating costs and the prices for our products fluctuate throughout the year. For
example, prices for natural gas (that we both sell and purchase for use in our operations) tend to be
higher in the winter and summer months. However, seasonality overall does not have a material effect
on our earnings during the year.

Income Taxes

All of our income is earned from domestic operations and is subject to tax in the United States. The

following table sets forth our effective tax rate on income from continuing operations:

Successor

Predecessor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

January 1, 2020 -
October 31, 2020

U.S. federal statutory tax
rate . . . . . . . . . . . . . . . . . . . . .
State income taxes, net
. . . .
Exclusion of income
attributable to noncontrolling
interests . . . . . . . . . . . . . . . . .
Changes in tax attributes . . .
Executive compensation . . .
Change in the U.S. federal
valuation allowance . . . . . . .
Other . . . . . . . . . . . . . . . . . . .

21%
9

—
(2)
—

2
1

Effective tax rate . . . . . . . . . .

31%

21%
(81)

(1)
(8)
2

(106)
—

(173)%

21%
—

—
—
—

(20)
(1)

—%

21%
—

(1)
—
—

(21)
1

—%

For the year ended December 31, 2022, our effective rate of 31% differed from the U.S. federal
statutory tax rate of 21% primarily due to state taxes and an increase in the valuation allowance for a
capital loss generated from the sale of Lost Hills. In February 2023, the original tax treatment of the
Lost Hills transaction was amended which allowed us to recognize the tax benefit for this loss in the
first quarter of 2023. For the year ended December 31, 2021, our effective tax rate of negative 173%
differed from the U.S. federal statutory tax rate of 21% primarily due to state taxes and releasing all of
our valuation allowance recorded against our net deferred tax assets given our anticipated future
earnings trends at that time. A portion of the change in our allowance during 2021 was for the
utilization of tax benefits against current year income and the remainder was recognized as a tax
benefit reflecting the projected utilization of our deferred tax assets. We did not record an income tax
provision (benefit) in the period ended December 31, 2020 or the period ended October 31, 2020.

Total deferred tax assets after valuation allowance were $164 million as of December 31, 2022.
Management expects to realize the recorded deferred tax assets primarily through future operating
income and reversal of taxable temporary differences. We assess the realizability of our deferred tax
assets each period by considering whether it is more-likely-than-not that all or a portion of our deferred
tax assets will be realized. At each reporting date new evidence is considered, both positive and
negative, including whether sufficient future taxable income will be generated to permit realization of
existing deferred tax assets. Changes in assumptions or changes in tax laws and regulations could
materially affect the realizability of our deferred tax assets.

The amount of deferred tax assets considered realizable is not assured and could be adjusted if

estimates change or three-years of cumulative income is no longer present.

We expect to continue paying cash income taxes in 2023. Our tax paying status depends on a
number of factors, including but not limited to, the amount and type of our capital spend, cost structure
and activity levels. For additional information on tax-related items, see information set forth in Part II,
Item 8 – Financial Statements and Supplementary Data, Note 9 Income Taxes.

Statement of Operations Analysis

Results of Oil and Natural Gas Operations

The following table includes key operating data for our oil and natural gas operations, excluding
certain corporate expenses, on a per Boe basis for the years ended December 31, 2022 and 2021, the
Successor period from November 1, 2020 through December 31, 2020 and the Predecessor period
from January 1, 2020 through October 31, 2020. 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.

Successor

Predecessor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

January 1, 2020 -
October 31, 2020

($ per Boe)
Energy operating costs . . . . . $
Gas processing costs . . . . . . $
Non-energy operating
costs . . . . . . . . . . . . . . . . . . . . $

Operating costs . . . . . . . $

9.76
0.52

13.47

23.75

$
$

7.01
0.54

11.84

19.39

$
$

6.03
0.55

11.61

18.19

$
$

4.71
0.55

9.69

14.95

Field general and
administrative expenses(a) . . . $
Field depreciation, depletion
and amortization(b) . . . . . . . . . $
Field taxes other than on
income . . . . . . . . . . . . . . . . . . $
(a) Excludes unallocated general and administrative expenses.
(b) Excludes depreciation, depletion and amortization related to our corporate assets, carbon management assets and Elk Hills

5.23

1.12

1.11

2.83

5.29

4.95

8.75

1.09

0.94

0.64

3.10

3.36

power plant.

Energy operating costs per Boe in 2022 were higher than 2021 on a per Boe basis primarily as a
result of higher electricity and natural gas prices. Lower production volumes in 2022 also contributed to
the increase on a per Boe basis. Non-energy operating costs per Boe in 2022 increased as compared
to 2021 primarily related to downhole maintenance activity. We expect non-energy operating costs per
Boe related to maintenance activities to increase in 2023, in part due to increased costs for services,
labor and supplies.

Field taxes other than on income on a per Boe basis were higher in 2022 as compared to 2021 due

to increased production taxes from higher tax rates and GHG taxes which increased as market prices
for GHG allowances rose. This increase was partially offset by lower ad valorem taxes.

Consolidated Results of Operations

Our consolidated results of operations include financial information related to oil and natural gas
operations and our carbon management business. Our carbon management business is still in the
early stages of development and was insignificant for 2021. For the year ended December 31, 2022,
we have separately identified the results of our carbon management business included in consolidated
general and administrative expenses and other operating expenses, net.

Year Ended December 31, 2022 vs. 2021

The following table presents our consolidated revenue and other income items:

Year ended
December 31,
2022

Year ended
December 31,
2021

Oil, natural gas and NGL sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss from commodity derivatives . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales of purchased natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electricity sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(in millions)
$

2,643
(551)
314
261
40

Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,707

2,048
(676)
312
172
33

1,889

Oil, natural gas and NGL sales – Oil, natural gas and NGL sales, excluding the impact of settled
hedges, were $2,643 million for the year ended December 31, 2022, which is an increase of 29% or
$595 million, compared to $2,048 million for the year ended December 31, 2021. The increase was
primarily due to higher realized prices, partially offset by lower production volumes, as shown in the
following table:

Oil

NGLs

Natural
Gas

Total

Year ended December 31, 2021 . . . . . . $
Changes in realized prices . . . . . . . . . . .
Changes in production . . . . . . . . . . . . . .

1,555
614
(201)

(in millions)
$

250
51
(37)

243
200
(32)

Year ended December 31, 2022 . . . . . . $

1,968

264

411

Note: See Production, Prices and Realizations for volumes and realized prices by commodity type for each period.

2,048
865
(270)

2,643

The effect of cash settlements on our commodity derivative contracts is not included in oil, natural
gas and NGL sales. Including the effect of net payments on settled commodity derivatives described
below, our oil, natural gas and NGL sales increased by $176 million or 10% in 2022 compared to the
same prior year period.

Net loss from commodity derivatives – Net loss from commodity derivatives was $551 million for the

year ended December 31, 2022 compared to a net loss of $676 million for the year ended
December 31, 2021. 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. Gains and losses
from our commodity derivative contracts are shown in the table below:

Year ended
December 31,
2022

Year ended
December 31,
2021

Non-cash commodity derivative gain (loss) . . . . . . . . . . . . . . . . . . . $
Net payments on settled commodity derivatives . . . . . . . . . . .
Net loss from commodity derivatives . . . . . . . . . . . . . . . . . . . . . $

(in millions)
187 $

(738)
(551) $

(357)
(319)
(676)

Electricity sales — Electricity sales increased by $89 million to $261 million during the year ended

December 31, 2022 compared to $172 million for the year ended December 31, 2021. The increase
was predominantly due to higher electricity prices in 2022 resulting from higher natural gas prices.

Interest and other revenue — Other revenue increased by $7 million to $40 million for the year
ended December 31, 2022, compared to $33 million for the year ended December 31, 2021 primarily
due to increased sales of purchased NGL volumes which were acquired to meet our delivery
commitments while one of our cryogenic gas processing facilities was down for planned maintenance
in the first quarter of 2022.

The following table presents our consolidated expenses, income tax (provision) benefit and income

attributable to noncontrolling interest:

Year ended
December 31,
2022

Year ended
December 31,
2021

Operating expenses
Energy operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Gas processing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-energy operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General and administrative expenses . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, depletion and amortization . . . . . . . . . . . . . . . . . . . . . .
Asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes other than on income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased natural gas expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electricity generation expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other operating expenses, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

Net gain on asset divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Non-operating (expenses) income
Reorganization items, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest and debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (loss) gain on early extinguishment of debt . . . . . . . . . . . . . . . . .
Loss from investment in unconsolidated subsidiary . . . . . . . . . . . . . .
Other non-operating expenses, net . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Income tax (provision) benefit

Net income (loss)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Net (income) loss attributable to noncontrolling interests . . . . . . . . . $

(in millions)
323 $
17
445
222
198
2
162
4
273
167
50
43
48
1,954 $
59
812

—
(53)
—
(1)
3
761
(237)
524 $
— $

255
20
430
200
213
28
145
7
196
96
51
50
29
1,720
124
293

(6)
(54)
(2)
—
(2)
229
396
625
(13)

Energy operating costs – Energy operating costs were $323 million for the year ended December 31,

2022, which was an increase of 27% or $68 million compared to $255 million for the year ended
December 31, 2021. The increase was predominantly a result of higher prices for purchased natural gas,
which we use to generate electricity for our operations and steam for our steamfloods, and for purchased
electricity.

Non-energy operating costs – Non-energy operating costs for the year ended December 31, 2022

were $445 million, which was an increase of $15 million or 3% from $430 million for the year ended
December 31, 2021 was primarily a result of increased surface and downhole maintenance activity in
2022.

General and administrative expenses – General and administrative expenses were $222 million for
the year ended December 31, 2022, which was an increase of $22 million from $200 million for the year
ended December 31, 2021. The increase in G&A expenses was primarily attributable to compensation-
related expenses and additional headcount related to developing our carbon management business. The
table below shows the portion of total G&A expenses which are directly attributable to our carbon
management business:

Exploration and production, corp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
orate and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Carbon management business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total general and administrative expenses . . . . . . . . . . . . . . . . . . . . $

Year ended December 31,

2022

2021

(in millions)

210
12

222

200
—

200

Depreciation, depletion and amortization – Depreciation, depletion and amortization decreased
$15 million to $198 million for the year ended December 31, 2022 from $213 million for the same prior
year period. The decrease was primarily the result of a lower carrying value in our exploration and
production assets due to asset divestitures which occurred during the fourth quarter of 2021 and the first
quarter of 2022. For further detail about our asset divestitures see Part II, Item 8 – Financial Statements
and Supplementary Data, Note 3 Divestitures and Acquisitions.

Asset impairments – Asset impairments were $2 million for the year ended December 31, 2022
compared to $28 million for the year ended December 31, 2021. The asset impairment charge in 2022
related to the write-down of a commercial office building located in Bakersfield, California to fair market
value. For the year ended December 31, 2021 we recorded a write-down of $25 million related to the
same commercial office building and a $3 million write-off of capitalized costs related to projects which
were abandoned. The decline in asset value of our commercial office building primarily related to limited
demand for office space of this size and type in the Bakersfield market and general trends in commercial
real estate in 2021 due to the COVID-19 pandemic. For further detail about our asset impairments see
Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Property, Plant and Equipment.

Taxes other than on income – Taxes other than on income were $162 million for the year ended

December 31, 2022, which was an increase of $17 million from $145 million for the year ended
December 31, 2021. Taxes other than on income were higher in 2022 due to increased production taxes
from higher tax rates and GHG taxes which increased as market prices for GHG allowances rose. This
increase was partially offset by a decrease in ad valorem taxes.

Purchased natural gas expense – Purchased natural gas expense was $273 million for the year
ended December 31, 2022, which was an increase of $77 million, or 39%, from $196 million for the
year ended December 31, 2021 primarily due to higher prices in 2022 for purchased natural gas
related to our trading activities.

Electricity generation expense – Electricity generation expenses increased to $167 million for the year

ended December 31, 2022 from $96 million for the year ended December 31, 2021. The increase of
$71 million, or 74%, was predominantly a result of higher natural gas prices used in electricity generation.

Other operating expenses, net – Other operating expenses, net was $48 million for the year ended
December 31, 2022, which was an increase of $19 million, or 66%, from $29 million for the year ended
December 31, 2021. The table below shows the portion of other operating expenses, net directly
attributable to our carbon management business:

Year ended December 31,

2022

2021

Exploration and production, corporate and other
Carbon management business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . $

Total other operating expenses, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

(in millions)
34
14

29
—

Other operating expenses, net for exploration and production, corporate and other includes higher
maintenance costs for offshore platforms and purchased NGL volumes which were acquired to meet our
delivery commitments while one of our cryogenic gas processing facilities was undergoing maintenance.
The prior comparative period included $15 million of severance costs related to the reduction in our
workforce and the departure of certain executive and other senior officers. Other operating expense, net
for our carbon management business includes lease cost for sequestration easements, advocacy, and
other startup-related costs.

Net gain on asset divestitures – Net gain on asset divestitures for the year ended December 31, 2022
was $59 million primarily related to the sale of our 50% non-operated working interest in certain horizons
within our Lost Hills field and certain Ventura basin assets. Gain on asset divestitures for the year ended
December 31, 2021 was $124 million related to the sale of the majority of our Ventura basin operations,
unimproved land and other non-core assets. For more information on our asset divestitures, see Part II,
Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions.

Income tax (provision) benefit – The income tax provision for the year ended December 31, 2022 was

$237 million (effective tax rate of 31%), which included a $35 million provision for a valuation allowance
recorded in the first quarter of 2022 at the time of our Lost Hills divestiture. This compares to an income
tax benefit of $396 million for the year ended December 31, 2021 which included the release of a
valuation allowance in the fourth quarter of 2021. See Part II, Item 8 – Financial Statements and
Supplementary Data, Note 9 Income Taxes for more information on our ability to realize deferred tax
assets.

Net income attributable to noncontrolling interests – BSP’s preferred interest in the BSP JV was

automatically redeemed in full in September 2021 and income was allocated to BSP up to the redemption
date. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 11 Stockholders’ Equity
for more information on the redemption of the preferred member interest from BSP.

Year Ended December 31, 2021 vs. the Successor and Predecessor Periods of 2020

See Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of
Operations, Statement of Operations Analysis in our 2021 Form 10-K for our analysis of the changes in
our consolidated statements of operations for the year ended December 31, 2021 compared to the
Successor period from November 1, 2020 through December 31, 2020 and the Predecessor period
from January 1, 2020 through October 31, 2020 along with supplemental information for the combined
year ended December 31, 2020.

Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations, cash and
cash equivalents on hand and available borrowing capacity under our Revolving Credit Facility which
matures in April 2024. We also generated additional cash flow of $80 million from strategic asset
divestitures during 2022. Our primary uses of operating cash flow for 2022 were capital investments,
repurchase shares of our common stock and dividends.

The following table summarizes our liquidity:

December 31,
2022
(in millions)

Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Revolving Credit Facility:

Borrowing capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding letters of credit

Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

Liquidity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

307

602
(144)

458

765

The aggregate commitments from our Revolving Credit Facility increased to $602 million from
$492 million at December 31, 2021 due to additional commitments from new lenders that joined this
facility. As of December 31, 2022, we were in compliance with all of the covenants of our Revolving
Credit Facility. For a description of the terms and conditions of our long-term debt, see Part II, Item 8 –
Financial Statements and Supplementary Data, Note 4 Debt.

We consider our low leverage and ability to adjust our capital plan and overall spending to be a
core strength and strategic advantage, which we are focused on maintaining. At current commodity
prices, 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 we may
(i) increase investments in our drilling program to accelerate value, (ii) return available cash to
shareholders through dividends or stock buybacks to the extent permitted under our Revolving Credit
Facility and Senior Notes indenture, (iii) advance carbon management activities, or (iv) maintain cash
on our balance sheet. We believe we have sufficient sources of liquidity to meet our obligations for the
next twelve months. See Other Uses of Cash below for our long-term obligations.

We are evaluating options to amend and extend or replace our Revolving Credit Facility, as well as

refinancing options for our Senior Notes, which we expect to provide us with greater operating and
financial flexibility to bolster our ongoing shareholder return program. We also intend to pursue
financing options for our carbon management business that are separate from the rest of our business.

Derivatives

Significant changes in oil and natural gas prices may have a material impact on our liquidity. Our
hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our financial
strength and liquidity by protecting our operating cash flows. Prior to April 2022, our Revolving Credit
Facility included covenants that required us to maintain a certain level of hedges at all times. We also
entered into hedges above and beyond those that were required for certain periods. In prior years,
these hedges prevented us from realizing the full benefits of price increases. Our existing hedges,
including the 2023 hedges entered into by us in 2020 to comply with our Revolving Credit Facility, may
also negatively impact our realized prices in the future. Following an amendment to our Revolving
Credit Facility in April 2022, we are only required to maintain hedges in the event the ratio of our
consolidated total debt to consolidated EBITDAX (as defined in our Revolving Credit Facility) exceeds
1:1. As of December 31, 2022, this ratio was not exceeded. 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 year ended December 31, 2022.

Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives for
more information on our open derivative contracts as of December 31, 2022 and Note 4 Debt for more
information on an amendment to the hedging requirements included in our Revolving Credit Facility.

Uses of Cash

2023 Capital Program

We expect our 2023 capital program to range between $200 and $245 million assuming normal
operating conditions. Of this amount, $165 to $195 million is related to oil and natural gas development
(including approximately $10 to $15 million to build replacement water injection facilities which will
allow us to use one of our depleted oil and natural gas reservoirs for CCS), $5 to $15 million for carbon
management projects and $30 to $35 million for corporate and other activities (including procuring
long-lead time items for planned maintenance at our Elk Hills power plant in 2024). We expect our
capital program related to oil and natural gas development to be focused primarily on executing
projects using existing permits outside of Kern County. The foregoing amounts related to carbon
management projects do not include amounts funded by Brookfield through the Carbon TerraVault JV.
See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Investment in
Unconsolidated Subsidiary and Related Party Transactions for more information on our joint venture
with Brookfield.

The actual amount of spending under our 2023 capital program will depend on a variety of factors.

In particular, our ability to obtain additional permits during the course of the year may cause us to
adjust our capital spending. There are also a number of other factors that could affect the size of our
capital program, including other changes in regulation and permitting, commodity prices, the success
of our drilling program, operating costs and other general market conditions. In particular, as the Kern
County EIR Litigation remains ongoing and in order to reduce the uncertainty surrounding permitting in
Kern County, we will seek CEQA permits for updated field level EIRs to reduce reliance on the Kern
County EIR in future years. Because we own and operate substantially all of our assets, the amount
and timing of our capital spending is largely within our control and we are able to shift our development
activities to projects so as to minimize the impact of external factors. Any curtailment of the
development of our oil and natural gas properties for regulatory or operational reasons could lead to a
decline in our production and may lower our reserves. A continued decline in our production and
reserves would negatively impact our cash flow from operations and the value of our assets.

Other Uses of Cash

Other than our 2023 capital program, our expected material uses of cash during 2023 include:
(1) dividends and share repurchases; (2) settlements on commodity derivative contracts; (3) income
taxes; (4) settlement of asset retirement obligations; (5) funds used in operations; and (6) costs related
to advancing our carbon management activities not included in our capital program, such as employee
costs and engineering studies.

The table below summarizes our current and long-term material cash requirements as of

December 31, 2022 that we expect to fund with operating cash flow (in millions):

Total

Less than
1 Year

Payments Due by Year
Years 2
and 3
(in millions)

Years 4
and 5

More than
5 Years

On-Balance Sheet

Long-term debt(a) . . . . . . . . . . . . . . . . . . $
Interest on long-term debt . . . . . . . . . . .
Pension and postretirement(b) . . . . . . . .
Operating leases(c) . . . . . . . . . . . . . . . . .

Off-Balance Sheet

Purchase obligations(d)

. . . . . . . . . . . . .

600
132
86
85

112

— $
43
14
21

— $
85
18
27

600
4
15
17

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

1,015

139

145

647

—
—
39
20

(a) Represents the outstanding long-term debt balance as of December 31, 2022. See Part II, Item 8 – Financial Statements

and Supplementary Data, Note 4 Debt for more information on our long-term debt agreements.
(b) Represents undiscounted future obligations for defined benefit and post-employment benefit plans.
(c) Our operating leases include drilling rigs, commercial office space, fleet vehicles, easements and certain facilities.
(d) Reflects amounts that will become due under long-term agreements to purchase goods and services used in the normal
course of business. Purchase obligations for pipeline capacity include ship or pay arrangements that are based on
contractual volumes and current market rates for firm transportation capacity during the contract period. Oil and natural
gas leases reflect obligations for fixed payments under our contracts.

Cash Flow Analysis

Cash flows from operating activities – Our net cash provided by operating activities is sensitive to
many variables, particularly changes in commodity prices. Commodity price movements may also lead
to changes in other variables in our business, including adjustments to our capital program.

Our operating cash flow for the year ended December 31, 2022 was $690 million, which was an

increase of $30 million, or 5%, from $660 million for the year ended December 31, 2021. The increase was
primarily related to higher average realized prices (including the effects of settlements on our commodity
derivatives) partially offset by declining production and increased operating costs. The increase in operating
costs in 2022 as compared to 2021 primarily related to higher prices for purchased natural gas and
electricity used in our operations as well as cost increases we experienced due to inflation.

Cash flows from investing activities – The table below summarizes net cash used in investing

activities:

Year ended
December 31,
2022

Year ended
December 31,
2021

Capital investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Changes in capital accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from divestitures, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions related to the Carbon TerraVault JV . . . . . . . . . . . . . . . .
Capitalized joint venture transaction costs . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . $

(in millions)

(379) $
1
80
(17)
12
(12)
(2)
(317) $

(194)
20
67
(52)
—
—
(2)
(161)

The increase in the use of cash primarily related to a higher capital program in 2022 as compared to
2021. In 2022, we invested $16 million in our carbon management activities including $12 million to build
replacement water injection facilities which will allow us to use one of our depleted oil and natural gas
reservoirs for CCS. Proceeds from divestitures, net for the year ended December 31, 2022 included the
sale of our 50% non-operated working interest in certain horizons within our Lost Hills field, certain of our
Ventura basin assets and our commercial office building in Bakersfield, California. We sold the majority of
our Ventura basin operations in 2021 and other non-core assets including unimproved land. In 2022, our
acquisitions related to our carbon management business. In 2021, we acquired working interests in certain
joint venture wells held by MIRA. Part II, Item 8 – Financial Statements and Supplementary Data, Note 3
Divestitures and Acquisitions for more information on our divestitures and acquisitions.

Cash flows from financing activities – The table below summarizes net cash used by financing

activities:

Year ended
December 31,
2022

Year ended
December 31,
2021

Debt transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Distributions to noncontrolling interest holders . . . . . . . . . . . . . . . . . .
Repurchases of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Net cash used by financing activities . . . . . . . . . . . . . . . . . . . . . . . . $

(in millions)
— $
—
(313)
1
(59)
(371) $

(12)
(50)
(148)
2
(14)
(222)

Our net cash used in financing activities for the year ended December 31, 2022 related to

repurchases of our common stock under our Share Repurchase Program and dividends. See Part II,
Item 8 – Financial Statements and Supplementary Data, Note 11 Stockholders’ Equity for more
information on our cash dividends.

Our net cash used in financing activities for the year ended December 31, 2021 primarily related to

distributions to BSP as well as repurchases of our common stock under our Share Repurchase
Program. Part II, Item 8 – Financial Statements and Supplementary Data, Note 11 Stockholders’ Equity
for additional information on our BSP JV.

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
December 31, 2022 and 2021 were not material to our consolidated balance sheets as of such dates.

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 challenged 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 we are now appealing the order from BSEE.

We also evaluate the amount of reasonably possible losses that we could incur as a result of these

matters. We believe that reasonably possible losses that we could incur in excess of reserves cannot
be accurately determined.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 6 Lawsuits, Claims,

Commitments and Contingencies.

Critical Accounting Estimates

Our critical accounting estimates that could result in a material impact to the consolidated financial

statements due to the levels of subjectivity and management judgment include the following:

Sensitivities

Our total proved reserves were
417 MMBoe and our total
proved developed reserves
were 363 MMBoe at
December 31, 2022. We
estimate our 2023 depletion
rate for oil and natural gas
producing properties using the
unit-of-production method will
be approximately $5.80/Boe. A
5% change in our reserves
would increase or decrease this
DD&A rate by approximately
$0.30/Boe.

If realized prices used in our
year-end reserve estimates
increased or decreased by
10%, our proved reserve
quantities at December 31,
2022 would have increased by
3 MMBoe or decreased by 4
MMBoe, respectively.

Title

Description

Oil and Natural
Gas Properties

The carrying value of our
property, plant and equipment
represents the costs incurred
to acquire or develop the
asset, including any asset
retirement obligations, net of
accumulated depreciation,
depletion and amortization
and impairment charges, if
any. We use the successful
efforts method of accounting
for our oil and gas producing
activities. Under this method,
we capitalize the costs of
acquiring properties,
development costs and the
costs of drilling successful
exploration wells.

The estimated amount of
proved reserve volumes are
used as the basis for
recording depletion expense.
We determine depletion on
our oil and natural gas
producing properties using the
unit-of-production method.
Under this method, acquisition
costs are amortized based on
total proved oil and gas
reserves and capitalized
development and successful
exploration costs are depleted
based on proved developed
oil and natural gas reserves.

Future cash flows from
expected reserve volumes for
producing properties may be
used in an impairment
analysis or a determination of
whether sufficient future
taxable income will be
generated to permit realization
of existing deferred tax
assets. We also use reserves
to predict when a producing
well will become inactive, and
then idle, to schedule the
timing of abandonment in
estimating certain of our asset
retirement obligations.

Estimation and
Uncertainties

The determination of
quantities of proved reserves
is a highly technical process
performed by our petroleum
engineers and geoscientists.
The analysis is based on
drilling results, reservoir
performance, subsurface
interpretation and future
development plans.
Production rate forecasts are
primarily derived from
estimates from decline-curve
analysis and type-curve
analysis. Secondary inputs
may include material balance
calculations, which consider
the volumes of substances
replacing the volumes
produced and associated
reservoir pressure changes.
Additional inputs may also
include seismic analysis and
computer simulations of
reservoir performance. These
field-tested technologies have
demonstrated reasonably
certain results with
consistency and repeatability
in the formations being
evaluated or in analogous
formations. The data for a
given reservoir may also
change over time as a result
of numerous factors including,
but not limited to, additional
development activity and
future development costs,
production history and
continuous reassessment of
the viability of future
production volumes under
varying economic conditions.
Several other factors could
change our proved oil and gas
reserves including changes in
energy costs, inflation,
deflation and the political and
regulatory environment, all of
which are beyond our control.

Estimation and
Uncertainties

The recognition of an asset
retirement obligation
requires us to make
assumptions including an
estimate of future
abandonment costs and
inflation rates, timing of
activity and our credit-
adjusted discount rate
among others. Changes in
the legal, regulatory and
political environment could
also affect our estimated
future cash outflows.

Sensitivities

As of December 31, 2022
and 2021, we had asset
retirement obligations of
$491 million and
$489 million, respectively.

Excluding liabilities
associated with our assets
held for sale, a 1% increase
in the inflation rate would
increase our liability by
$32 million and a 1%
decrease in the inflation rate
would decrease our liability
by $29 million as of
December 31, 2022.

Title

Asset
Retirement
Obligations

Description

The majority of our asset
retirement obligations
relate to the plugging and
abandonment of oil and
natural gas wells.

We determine our asset
retirement obligation for oil
and natural gas wells by
calculating the present
value of estimated future
cash outflows related to
the abandonment
obligation. The asset
retirement cost is
capitalized as part of the
carrying amount of the
related long-lived asset. In
periods subsequent to
initial measurement, the
asset retirement cost is
depreciated using the
unit-of-production method,
while increases in the ARO
liability resulting from the
passage of time (accretion
expense) is included in
operating expenses on our
consolidated statements of
operations.

FORWARD-LOOKING STATEMENTS

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

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

•

fluctuations in commodity prices,
including supply and demand
considerations for our products and
services;
decisions as to production levels and/or
pricing by OPEC or U.S. producers in
future periods;
government policy, war and political
conditions and events, including the war
in Ukraine and oil sanctions on Russia,
Iran and others;
regulatory actions and changes that affect
the oil and gas industry generally and us
in particular, including (1) the availability
or timing of, or conditions imposed on,
permits and approvals necessary for
drilling or development activities or our
carbon management business; (2) the
management of energy, water, land,
greenhouse gases (GHGs) or other
emissions, (3) the protection of health,
safety and the environment, or (4) the
transportation, marketing and sale of our
products;
the impact of inflation on future expenses
and changes generally in the prices of
goods and services;
changes in business strategy and our
capital plan;
lower-than-expected production or higher-
than-expected production decline rates;

•

•
•

•

changes to our estimates of reserves and
related future cash flows, including
changes arising from our inability to
develop such reserves in a timely
manner, and any inability to replace such
reserves;
the recoverability of resources and
unexpected geologic conditions;
general economic conditions and trends,
including conditions in the worldwide
financial, trade and credit markets;
production-sharing contracts’ effects on
production and operating costs;
the lack of available equipment, service
or labor price inflation;
limitations on transportation or storage
capacity and the need to shut-in wells;
any failure of risk management;
results from operations and competition in
the industries in which we operate;
our ability to realize the anticipated
benefits from prior or future efforts to
reduce costs;
environmental risks and liability under
federal, regional, state, provincial, tribal,
local and international environmental laws
and regulations (including remedial
actions);
the creditworthiness and performance of
our counterparties, including financial
institutions, operating partners, CCS
project participants and other parties;

•

reorganization or restructuring of our
operations;
our ability to claim and utilize tax credits
or other incentives in connection with our
CCS projects,
our ability to realize the benefits
contemplated by our energy transition
strategies and initiatives, including CCS
projects and other renewable energy
efforts;
our ability to successfully identify, develop
and finance carbon capture and storage
projects and other renewable energy
efforts, including those in connection with
the Carbon TerraVault JV;
our ability to successfully develop
infrastructure projects and enter into third
party contracts on contemplated terms;
and
uncertainty around the accounting of
emissions and our ability to successfully
gather and verify emissions data and
other environmental impacts.
changes to our dividend policy and share
repurchase program, and our ability to
declare future dividends or repurchase
shares under our debt agreements;
limitations on our financial flexibility due
to existing and future debt;
insufficient cash flow to fund our capital
plan and other planned investments and
return capital to shareholders;

•
•

•

•
•

•

changes in interest rates;
our access to and the terms of credit in
commercial banking and capital markets,
including our ability to refinance our debt
or obtain separate financing for our
carbon management business;
changes in state, federal or international
tax rates, including our ability to utilize our
net operating loss carryforwards to
reduce our income tax obligations;
effects of hedging transactions;
the effect of our stock price on costs
associated with incentive compensation;
inability to enter into desirable
transactions, including joint ventures,
divestitures of oil and natural gas
properties and real estate, and
acquisitions, and our ability to achieve
any expected synergies;
disruptions due to earthquakes, forest
fires, floods 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; and
other factors discussed in Part I,
Item 1A – Risk Factors.

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

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 PSCs. We maintain a commodity
hedging program primarily focused on crude oil to help protect our cash flows, margins and capital
program from the volatility of crude oil prices. We have not designated any instruments as hedges for
accounting purposes and we do not enter into such instruments for speculative trading purposes. We
believe we have limited price volatility risk in the near term as a result of our current hedges in place.
As of December 31, 2022, we had hedges on approximately 65% of our anticipated oil production
through 2023 and approximately 5% through 2024, which are in line with the covenants of our
Revolving Credit Facility.

The primary market risk relating to our derivative contracts relates to fluctuations in market prices as
compared to the fixed contract price for a notional amount of our production. As of December 31, 2022, we
had net liabilities of $200 million for our derivative commodity positions which are carried at fair value, using
industry-standard models with various inputs, including the forward curve for the relevant price index. We
estimate that a $10/bbl increase in Brent oil forward prices could increase our settlement payments by
$123 million in 2023, limiting our upside. We estimate that a $10 decrease in Brent oil forward prices could
decrease our settlement payments by $137 million in 2023, negating the downside price movement for
hedged volumes.

A summary of our Brent-based crude oil derivative contracts at December 31, 2022 are included in Part

II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives.

Counterparty Credit Risk

Our counterparty credit risk relates primarily to trade receivables and derivative financial instruments.

Credit exposure for each counterparty is monitored for outstanding balances and current activity.
Counterparty credit limits have been established based upon the financial health of counterparties, and
these limits are actively monitored. In the event counterparty credit risk is heightened, we may request
collateral or accelerate payment dates for product deliveries. Approximately 60% of our production during
2022 was oil which was sold predominately to refineries in California. Trade receivables for all commodities
are collected within 30 to 60 days following the month of delivery. For derivative instruments entered into as
part of our hedging program, we are subject to counterparty credit risk to the extent the counterparty is
unable to meet its settlement commitments. We have master netting agreements with each of our derivative
counterparties, which allows us to net our settlement payments for the same commodity with the same
counterparty. Therefore, our loss is limited to the net amount due from a defaulting counterparty. All of our
counterparties in the hedging program have an investment grade credit rating. Concentration of credit risk is
regularly reviewed to ensure that counterparty credit risk is adequately diversified.

Interest-Rate Risk

We had no variable-rate debt outstanding as of December 31, 2022. Due to rising interest rates, we may

be limited in amending, replacing or refinancing our existing Revolving Credit Facility and Senior Notes at
favorable terms if at all.

ITEM 8

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors
California Resources Corporation:

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of California Resources Corporation
and subsidiaries (the Company) as of December 31, 2022 and December 31, 2021, the related
consolidated statements of operations, comprehensive income (loss), changes in stockholders’ equity
(deficit), and cash flows for each of the years in the two-year period ended December 31, 2022
(Successor), for the period from November 1, 2020 to December 31, 2020 (Successor), and for the
period from January 1, 2020 to October 31, 2020 (Predecessor), and the related notes and financial
statement schedule II (collectively, the consolidated financial statements). We also have audited the
Company’s internal control over financial reporting as of December 31, 2022, based on criteria
established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission.

In our opinion, the consolidated financial statements referred to above present fairly, in all material
respects, the financial position of the Company as of December 31, 2022 and December 31, 2021, and
the results of its operations and its cash flows for each of the years in the two-year period ended
December 31, 2022 (Successor), for the period from November 1, 2020 to December 31, 2020
(Successor), and for the period from January 1, 2020 to October 31, 2020 (Predecessor), in conformity
with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all
material respects, effective internal control over financial reporting as of December 31, 2022 based on
criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission.

New Basis of Presentation

As discussed in Notes 1 and 15 to the consolidated financial statements, the Company emerged from
Chapter 11 bankruptcy on October 27, 2020 with a reporting date of October 31, 2020. Accordingly,
the accompanying consolidated financial statements as of December 31, 2022, 2021, and 2020 have
been prepared in conformity with Accounting Standards Codification Topic 852, Reorganizations, with
the Company’s assets, liabilities, and capital structure having carrying amounts that are not
comparable with prior periods.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for maintaining
effective internal control over financial reporting, and for its assessment of the effectiveness of internal
control over financial reporting, included in the accompanying Management’s Annual Assessment of and
Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the
Company’s consolidated financial statements and an opinion on the Company’s internal control over
financial reporting based on our audits. We are a public accounting firm registered with the Public Company
Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to
the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of
the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require
that we plan and perform the audits to obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement, whether due to error or fraud, and whether
effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks
of material misstatement of the consolidated financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test
basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our
audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements.
Our audit of internal control over financial reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (1) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that
receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or
timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a
material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the
consolidated financial statements that were communicated or required to be communicated to the audit
committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial
statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the consolidated financial
statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing
separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Impact of estimated oil and gas reserves on depletion expense for proved oil and gas properties

As discussed in Note 1 to the consolidated financial statements, the Company determines depletion of
oil and gas producing properties by the unit-of-production method. Under this method, acquisition costs
are amortized based on total proved oil and gas reserves and capitalized development and successful
exploration costs are amortized based on proved developed oil and gas reserves. The Company
recorded depreciation, depletion, and amortization expense of $198 million for the year ended
December 31, 2022 (Successor). Estimating proved oil and gas reserves requires the expertise of
professional petroleum reservoir engineers, who take into consideration estimates of future production,
operating and development costs and commodity prices inclusive of market differentials. The Company
employs technical personnel, such as reservoir engineers and geoscientists, who estimate proved oil
and gas reserves. The Company also engages independent reservoir engineering specialists to perform
an independent evaluation of the Company s proved oil and gas reserves estimates.

We identified the assessment of estimated proved oil and gas reserves on the determination of
depreciation, depletion and amortization expense for proved oil and gas properties as a critical audit
matter. Complex auditor judgment was required to evaluate the Company’s estimate of proved oil and
gas reserves, which is an input to the determination of depreciation, depletion, and amortization
expense. Specifically, auditor judgment was required to evaluate the assumptions used by the Company
related to estimated future oil and gas production, future commodity prices inclusive of market
differentials, and future operating and development costs.

The following are the primary procedures we performed to address this critical audit matter. We
evaluated the design of certain internal controls related to the Company’s depletion process,
including controls related to the estimation of proved oil and gas reserves. We evaluated (1) the
professional qualifications of the Company’s internal reservoir engineers, as well as the
independent reservoir engineering specialists and external engineering firm, (2) the knowledge,
skills, and ability of the Company’s internal and independent reservoir engineers, and (3) the
relationship of the independent reservoir engineering specialists and external engineering firms to
the Company. We assessed the methodology used by the technical personnel employed by the
Company and the independent reservoir engineering specialists to estimate the reserves used in
the determination of depreciation, depletion and amortization expense for compliance with industry
and regulatory standards. We compared estimated future oil and gas production and estimated
future operating and development costs estimated by the technical personnel employed by the
Company to historical results. We compared the commodity prices used by the Company’s internal
technical personnel to publicly available prices and recalculated the relevant market differentials
based on actual price realizations. We read and considered the reports of the independent reservoir
engineering specialists in connection with our evaluation of the Company’s proved oil and gas
reserves estimates.

Assessment of control of the Carbon TerraVault Joint Venture under the variable interest entity model

As discussed in Note 1, if an entity is determined to be a Variable Interest Entity (VIE) but the Company
does not have a controlling financial interest, the entity is accounted for under the equity method. As
discussed in Note 8, the Company accounts for its investment in the Carbon TerraVault Joint Venture
(Carbon TerraVault JV) under the equity method of accounting. As of December 31, 2022, the
Company’s carrying value of its equity method investment in the Carbon TerraVault JV was $13 million.

We identified the evaluation of control of the Carbon TerraVault JV as a critical audit matter. Identifying
the activities of the VIE that most significantly impact its economic performance and evaluating whether
the Company had the ability to direct these activities required a high degree of subjective auditor
judgment.

The following are the primary procedures we performed to address the critical audit matter. We
evaluated the design and tested the operating effectiveness of internal controls over the evaluation of
technical accounting matters, including the evaluation of control for the Carbon TerraVault JV
transaction. We obtained the Company’s accounting analysis and compared the relevant information in
the analysis to the joint venture agreements and other underlying documentation, including the
Company’s evaluation of the significant activities of the Carbon TerraVault JV and which party has the
power to direct those activities. We inspected the relevant joint venture agreements and evaluated the
Company’s determination of whether power is shared.

/s/ KPMG LLP

We have served as the Company’s auditor since 2014.

Los Angeles, California
February 24, 2023

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2022 and 2021
(in millions, except share data)

2022

2021

CURRENT ASSETS

Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trade receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Receivable from affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets, net

Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTY, PLANT AND EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depreciation, depletion and amortization . . . . . . . . .

Total property, plant and equipment, net . . . . . . . . . . . . . . . . . .
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY . . . . . . . . . . . .
DEFERRED TAX ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OTHER NONCURRENT ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

307
326
60
5
33
133

864
3,228
(442)

2,786
13
164
140

3,967

345
5
246
298

894

592
—
432
185

—

CURRENT LIABILITIES

Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities associated with assets held for sale . . . . . . . . . . . . . . . .
Fair value of derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

NONCURRENT LIABILITIES

Long-term debt, net
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

STOCKHOLDERS’ EQUITY

Preferred stock (20 million shares authorized at $0.01 par value);
no shares outstanding at December 31, 2022 or 2021 . . . . . . . . .
Common stock (200 million shares authorized at $0.01 par
value); (83,406,002 and 83,389,210 shares issued; 71,949,742
and 79,299,222 shares outstanding at December 31, 2022 and
2021, respectively) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock (11,456,260 shares held at cost at December 31,
2022 and 4,089,988 shares held at December 31, 2021) . . . . . . .
Additional paid-in capital
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive income . . . . . . . . . . . . . . . . . .

Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY . . . . . . . . . .

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

(461)
1,305
938
81

1,864

3,967

(148)
1,288
475
72

1,688

3,846

305
245
60
22
—
121

753
2,845
(246)

2,599
—
396
98

3,846

266
21
270
297

854

589
132
438
145

—

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
For the years ended December 31, 2022 and 2021, the period from November 1, 2020 through
December 31, 2020 and the period from January 1, 2020 through October 31, 2020
(in millions, except share and per share data)

Successor

Predecessor

Year ended
December 31,

2022

2021

November 1, 2020 -
December 31, 2020

January 1, 2020 -
October 31, 2020

REVENUES

Oil, natural gas and NGL sales . . . . . . . . .
Net (loss) gain from commodity
derivatives . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales of purchased natural gas . . . . . . . . .
Electricity sales . . . . . . . . . . . . . . . . . . . . . .
Interest and other revenue . . . . . . . . . . . . .
Total operating revenues . . . . . . . . . . . .

OPERATING EXPENSES

Operating costs . . . . . . . . . . . . . . . . . . . . . .
General and administrative expenses . . . .
Depreciation, depletion and
amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Asset impairments . . . . . . . . . . . . . . . . . . . .
Taxes other than on income . . . . . . . . . . . .
Exploration expense . . . . . . . . . . . . . . . . . .
Purchased natural gas expense . . . . . . . .
Electricity generation expenses . . . . . . . . .
Transportation costs . . . . . . . . . . . . . . . . . .
Accretion expense . . . . . . . . . . . . . . . . . . . .
Other operating expenses, net . . . . . . . . . .
Total operating expenses . . . . . . . . . . . .
Net gain on asset divestitures . . . . . . . . . .
OPERATING INCOME (LOSS) . . . . . . . . . . .
NON-OPERATING (EXPENSES) INCOME

Reorganization items, net . . . . . . . . . . . . . .
Interest and debt expense . . . . . . . . . . . . .
Net (loss) gain on early extinguishment of
debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss from investment in unconsolidated
subsidiary . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-operating income (expenses),
net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

INCOME (LOSS) BEFORE INCOME
TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax (provision) benefit . . . . . . . . . . . .
NET INCOME (LOSS) . . . . . . . . . . . . . . . . . .
NET (INCOME) LOSS ATTRIBUTABLE TO
NONCONTROLLING INTERESTS

Mezzanine equity . . . . . . . . . . . . . . . . . . . .
Stockholders’ equity . . . . . . . . . . . . . . . . . .

Net (income) loss attributable to
noncontrolling interests . . . . . . . . . . . . . . . . .
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCK . . . . . . . . . . . . . . . . . . . . .

Net income (loss) attributable to
common stock per share
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average common shares
outstanding
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,643

2,048

237

(551)
314
261
40
2,707

785
222

198
2
162
4
273
167
50
43
48
1,954
59
812

—
(53)

—

(1)

761
(237)
524

—
—

—

(676)
312
172
33
1,889

705
200

213
28
145
7
196
96
51
50
29
1,720
124
293

(6)
(54)

(2)

—

(2)

229
396
625

—
(13)

(13)

$
$

524

612

6.94
6.75

$
$

75.5
77.6

7.46
7.37

82.0
83.0

(141)
38
15
3
152

114
40

34
—
10
1
24
10
8
8
9
258
—
(106)

(3)
(11)

—

(5)

(125)
—
(125)

—
2

(123)

(1.48)
(1.48)

83.3
83.3

$
$

1,092

91
124
86
14
1,407

511
212

328
1,736
134
10
78
53
35
33
56
3,186
—
(1,779)

4,060
(206)

—

(84)

1,996
—
1,996

(94)
(13)

(107)

1,889

40.59
40.42

49.4
49.6

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)
For the years ended December 31, 2022 and 2021, the period from November 1, 2020 through
December 31, 2020 and the period from January 1, 2020 through October 31, 2020
(in millions)

Successor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

Predecessor

January 1, 2020 -
October 31, 2020

Net income (loss) . . . . . . . . . . . . $
Net (income) loss attributable to
noncontrolling interests . . . . . . . .
Other comprehensive income
(loss):

Actuarial gains (losses)
associated with pension and
postretirement plans . . . . . . .
Prior service credit
. . . . . . . .
Amortization of prior service
cost credit included in net
periodic benefit cost

. . . . . . .

Comprehensive income (loss)
attributable to common
stock . . . . . . . . . . . . . . . . . . . . . . . $

524 $

625

(125)

—

(13)

13
—

(4)

16
65

(1)

(8)
—

—

1,996

(107)

(2)
2

—

533 $

692

(131)

1,889

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
For the years ended December 31, 2022 and 2021, the period from November 1, 2020 through
December 31, 2020 and the period from January 1, 2020 through October 31, 2020
(in millions)

Common
Stock

Treasury
Stock

Additional
Paid-in
Capital

Accumulated
(Deficit)
Earnings

Accumulated
Other
Comprehensive
(Loss) Income

Equity
Attributable
to Common
Stock

Equity
Attributable to
Noncontrolling
Interests

Total
(Deficit)
Equity

Predecessor

Balance, December 31,
2019 . . . . . . . . . . . . . . . . $ — $ — $ 5,004 $

(5,370) $
1,889

(23)
—

(389) $
1,889

93 $
13

(296)
1,902

—

138

128

—

261

—

408

—

. . . . . . . . . . . .

Net income . . . . . . . . .
Distributions to
noncontrolling interest
holders . . . . . . . . . . . .
Shared-based
compensation, net . . .
Modification of
noncontrolling
interest
. . . . . . . . . . . .
Gain on acquisition of
noncontrolling
interest
Issuance of
Successor common
stock for acquisition of
a noncontrolling
interest in connection
with the Plan . . . . . . .
Issuance of
Successor common
stock to creditors in
connection with the
Plan . . . . . . . . . . . . . . .
Issuance of
Subscription Rights to
creditors in
connection with the
Plan . . . . . . . . . . . . . . .
Issuance of
Successor common
stock for junior
debtor-in-possession
exit fee . . . . . . . . . . . .
Issuance of
Successor common
stock to Subscription
Rights holders and
backstop parties in
connection with the
Plan, net . . . . . . . . . . .
Warrants issued in
connection with the
Plan . . . . . . . . . . . . . . .
Fair value adjustment
related to
noncontrolling
interest
Elimination of
Predecessor equity . .

. . . . . . . . . . . .

—

445

—

(5,224)

3,481

—

138

128

(37)

—

(37)

138

128

—

261

—

261

—

408

—

408

—

446

—

(1,720)

—

446

(1,720)

Balance, October 31,
2020 . . . . . . . . . . . . . . . . $

$ — $ 1,268 $

— $

1,269 $

76 $

1,345

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

Common
Stock

Treasury
Stock

Additional
Paid-in
Capital

Accumulated
(Deficit)
Earnings

Accumulated
Other
Comprehensive
(Loss) Income

Equity
Attributable
to Common
Stock

Equity
Attributable to
Noncontrolling
Interests

Total
Equity

Successor

Balance, October 31,
2020 . . . . . . . . . . . . . . . . $
Net loss . . . . . . . . . . . . . .
Distributions to
noncontrolling interest
holder . . . . . . . . . . . . . . .
Other comprehensive
loss . . . . . . . . . . . . . . . . .

Balance, December 31,
2020 . . . . . . . . . . . . . . . . $
Net income . . . . . . . . . . .
Distributions to
noncontrolling interest
holder . . . . . . . . . . . . . . .
Cash dividends ($0.17
per share) . . . . . . . . . . . .
Redemption of
noncontrolling
interest(a) . . . . . . . . . . . . .
Share-based
compensation . . . . . . . . .
Repurchases of
common stock . . . . . . . .
Issuance of common
stock . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . .
Other comprehensive
income . . . . . . . . . . . . . .

Balance, December 31,
2021 . . . . . . . . . . . . . . . . $
Net income . . . . . . . . . . .
Cash dividends
($0.7925 per share) . . . .
Share-based
compensation . . . . . . . . .
Repurchases of
common stock . . . . . . . .
Other . . . . . . . . . . . . . . . .
Other comprehensive
income, net of tax . . . . .

Balance, December 31,
2022 . . . . . . . . . . . . . . . . $

1 $
—

— $ 1,268 $
—

—

— $

(123)

— $
—

1,269 $
(123)

76 $ 1,345
(125)
(2)

—

(8)

—

(8)

(30)

—

(30)

(8)

1 $
—

— $ 1,268 $
—

—

(123) $
612

(8) $
—

1,138 $
612

44 $ 1,182
625
13

—

—
—

—

1 $
—

—

—
—

—

(148)

—
—

—

2
(2)

—

(148) $ 1,288 $

—

(313)
—

—

—
(2)

—

(14)

—

—
—

—

475 $
524

(61)

—

—
—

—

—
—

—

(14)

(148)

2
(2)

(50)

—

(7)

—

—
—

—

(50)

(14)

—

(148)

2
(2)

72 $
—

1,688 $
524 $

— $ 1,688
524
—

—

—
—

(61) $

19 $

(313) $
(2) $

9 $

—

—
—

—

(61)

(313)
(2)

1 $

(461) $ 1,305 $

938 $

81 $

1,864 $

— $ 1,864

(a) The remaining balance in equity attributable to noncontrolling interest was reallocated to additional paid-in capital of the

parent upon redemption of ECR’s preferred member interest in the BSP JV. No gain or loss was recognized on the equity
transaction. See Note 15 Chapter 11 Proceedings for more information.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the years ended December 31, 2022 and 2021, the period from November 1, 2020 through
December 31, 2020 and the period from January 1, 2020 through October 31, 2020
(in millions)

CASH FLOW FROM OPERATING ACTIVITIES

Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income (loss) to net
cash provided (used) by operating activities:

Depreciation, depletion and amortization . . .
Deferred income tax provision (benefit) . . . .
Asset impairments . . . . . . . . . . . . . . . . . . . .
Net loss (gain) from commodity
derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net settlement (payments) proceeds from
commodity derivatives . . . . . . . . . . . . . . . . .
Net loss (gain) on early extinguishment of
debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred gain . . . . . . . . . . . .
Net gain on asset divestitures . . . . . . . . . . .
Other non-cash charges to income, net . . . .
Reorganization items, net (non-cash)
. . . . .
Reorganization items, net
(debtor-in-possession financing costs) . . . . .

Changes in operating assets and liabilities, net:

(Increase) decrease in trade receivables . . .
Decrease (increase) in inventories . . . . . . . .
Decrease (increase) in other current
assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Decrease) increase in accounts payable
and accrued liabilities . . . . . . . . . . . . . . . . . .

Net cash provided (used) by
operating activities . . . . . . . . . . . . . . .

CASH FLOW FROM INVESTING ACTIVITIES

Capital investments . . . . . . . . . . . . . . . . . . . . . . .
Changes in accrued capital investments . . . . . . .
Proceeds from asset divestitures . . . . . . . . . . . . .
Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distribution related to the Carbon TerraVault
JV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capitalized joint venture transaction costs . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Net cash used in investing
activities . . . . . . . . . . . . . . . . . . . . . . . .

CASH FLOW FROM FINANCING ACTIVITIES

Proceeds from 2014 Revolving Credit Facility . . .
Repayments of 2014 Revolving Credit Facility . .
Proceeds from debtor-in-possession facilities . . .
Repayments of debtor-in-possession facilities . .
Proceeds from Revolving Credit Facility . . . . . . .
Repayments of Revolving Credit Facility . . . . . . .
Proceeds from Second Lien Term Loan . . . . . . .
Debtor-in-possession financing costs . . . . . . . . .
Proceeds from Senior Notes . . . . . . . . . . . . . . . .
Debt repurchases . . . . . . . . . . . . . . . . . . . . . . . . .
Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . .

Successor

Year ended
December 31,

2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

Predecessor

January 1, 2020 -
October 31, 2020

524

625

(125)

1,996

198
226
2

551

(738)

—
—
(59)
43
—

—

(81)
—

(11)

690

(379)
1
80
(17)

12
(12)
(2)

(317)

—
—
—
—
—
—
—
—
—
—
—

213
(396)
28

676

(319)

2
—
(124)
62
—

—

(68)
—

(47)

660

(194)
20
67
(52)

—
—
(2)

(161)

—
—
—
—
16
(115)
—
—
600
—
(13)

34
—
—

141

(1)

—
—
—
27
—

—

(28)
1

(67)

(12)

(7)
(1)
—
—

—
—
1

(7)

—
—
—
—
82
(208)
—
—
—
—
—

328
—
1,736

(91)

108

(5)
(39)
—
60
(4,128)

128
(1)

(1)

118

(40)
(24)
41
—

—
—
(7)

(30)

797
(1,315)
802
(802)
225
—
200
(25)
—
(3)
(20)

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

Repayment of Second Lien Term Loan . . . . . . .
Repayment of EHP Notes . . . . . . . . . . . . . . . . . .
Repayment of 2020 Senior Notes . . . . . . . . . . . .
Contributions from noncontrolling interest
holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions to noncontrolling interest
holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repurchases of common stock . . . . . . . . . . . . . .
Common stock dividends . . . . . . . . . . . . . . . . . .
Acquisition of noncontrolling interest in
connection with the Plan . . . . . . . . . . . . . . . . . . .
Issuance of common stock . . . . . . . . . . . . . . . . .
Shares cancelled for taxes and other . . . . . . . .

Net cash (used) provided by
financing activities . . . . . . . . . . . . . .

Increase (decrease) in cash . . . . . . . . . . . . . . . .
Cash—beginning of period . . . . . . . . . . . . . . . .

Cash—end of period . . . . . . . . . . . . . . . . . . . . . .

—
—
—

—

—
(313)
(59)

—
1
—

(371)

2
305

307

(200)
(300)
—

—

(50)
(148)
(14)

—
2
—

(222)

277
28

305

—
—
—

—

(30)
—
—

—
—
—

(156)

(175)
203

—
—
(100)

—

(104)
—
—

(2)
446
(1)

186
17

203

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

NOTE 1 NATURE OF BUSINESS, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND
OTHER

Nature of Business

We are an independent oil and natural gas exploration and production company operating

properties exclusively within California. We are committed to energy transition and have some of the
lowest carbon intensity production in the United States. We are in the early stages of permitting several
carbon capture and storage 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 Joint
Ventures and Investments in Unconsolidated Subsidiaries below for our accounting policy related to
joint ventures and investments in unconsolidated subsidiaries and Note 8 Investments 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 (CalCapture).

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.

Basis of Presentation

We have prepared this report in accordance with United States (U.S.) generally accepted

accounting principles (U.S. GAAP) and the rules and regulations of the U.S. Securities and Exchange
Commission applicable to annual financial information.

All financial information presented consists of our consolidated results of operations, financial
position and cash flows. We have eliminated significant intercompany transactions and balances. 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 consolidated financial statements.

We qualified for and adopted fresh start accounting upon emergence from Chapter 11 in October

2020 at which point we became a new entity for financial reporting purposes. We adopted an
accounting convenience date of October 31, 2020 for the application of fresh start accounting.

As a result of the application of fresh start accounting and the effects of the implementation of our
Plan of Reorganization, the financial statements after October 31, 2020 may not be comparable to the
financial statements prior to that date. Accordingly, “black-line” financial statements are presented to
distinguish between the Predecessor and Successor companies. References to “Predecessor” refer to
the Company for periods ended on or prior to October 31, 2020 and references to “Successor” refer to
the Company for periods subsequent to October 31, 2020. See Note 15 Chapter 11 Proceedings and
Note 16 Fresh Start Accounting for additional information on our bankruptcy proceedings and the
impact of fresh start accounting on our consolidated financial statements.

100

Use of Estimates

The process of preparing financial statements in conformity with U.S. GAAP requires management

to select appropriate accounting policies and make informed estimates and judgments regarding
certain types of financial statement balances and disclosures. Such estimates primarily relate to
unsettled transactions and events as of the date of the financial statements and judgments on
expected outcomes as well as the materiality of transactions and balances. Changes in facts and
circumstances or discovery of new information relating to such transactions and events may result in
revised estimates and judgments. Further, actual results may differ from estimates upon settlement.
Management believes that these estimates and judgments provide a reasonable basis for the fair
presentation of our consolidated financial statements.

Risks and Uncertainties

Our revenue, profitability and future growth or our oil and natural gas operations are substantially

dependent upon prevailing and future prices for oil and natural gas, which can be volatile and
dependent on factors beyond our control including global production inventories, available storage and
transportation capacities, government regulation, the Russia-Ukraine conflict and economic conditions.
The Coronavirus Disease 2019 (COVID-19) pandemic continues to create price volatility for oil and
natural gas. The ongoing impacts from the Russia-Ukraine conflict and COVID-19 on our financial
position, results of operations and cash flows will depend on uncertain factors, including future
developments that are beyond our control. We are in the early stages of developing a carbon capture
and sequestration business which is subject to risks as an emerging industry. We operate exclusively
in California which is a highly regulated environment.

Concentration of Customers

We sell crude oil, natural gas and NGLs to marketers, California refineries and other customers that

have access to transportation and storage facilities. In light of the ongoing energy deficit in California
and strong demand for native crude oil production, we do not believe that the loss of any single
customer would have a material adverse effect on our consolidated financial statements taken as a
whole.

For the year ended December 31, 2022, three California refineries each accounted for at least 10%,

and collectively 52%, of our sales (before the effects of hedging). For the year ended December 31,
2021, three California refineries each accounted for at least 10%, and collectively accounted for 51%,
of our sales (before the effects of hedging). For the 2020 Successor period, three California refineries
each accounted for at least 10%, and collectively accounted for 50%, of our sales (before the effects of
hedging). For the 2020 Predecessor period, two California refineries, each accounted for at least 10%,
and collectively accounted for 46%, of our sales (before the effects of hedging).

Recently Adopted Accounting and Disclosure Changes

ASC Topic 848, Reference Rate Reform contains guidance for applying U.S. GAAP to contracts,
hedging relationships and other transactions that are impacted by reference rate reform. Under this
guidance, we elected to account for the February 2022 amendment of our Revolving Credit Facility
described in Note 4 Debt as a modification of the original instrument. The debt modification did not
have a material impact to our consolidated financial statements.

101

Significant Accounting Policies

Restructuring under Chapter 11 of the Bankruptcy Code and Workforce Reductions

On July 15, 2020, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the

Bankruptcy Code (Chapter 11 Cases) in the United States Bankruptcy Court for the Southern District of
Texas, Houston Division (Bankruptcy Court). On October 13, 2020, the Bankruptcy Court confirmed
our joint plan of reorganization (the Plan) and we subsequently emerged from Chapter 11 proceedings
on October 27, 2020 (Effective Date). See Note 15 Chapter 11 Proceedings for more information on
our voluntary reorganization. We qualified for fresh start accounting and allocated the reorganization
value to our individual assets and liabilities based on their estimated relative fair value. Our
reorganization value was less than the fair value of identifiable assets of the emerging entity and we
allocated the difference to nonfinancial assets on a relative fair value basis. Our valuation approach for
determining the estimated fair value of our significant assets acquired and liabilities assumed is
discussed in Note 16 Fresh Start Accounting.

In 2021, we reduced the size of our management team and realigned several functions, which
resulted in headcount and cost reductions. We recorded a restructuring charge of $15 million during
the year ended December 31, 2021. In 2020, we reduced our workforce in response to economic
conditions, resulting in a restructuring charge of $10 million in the Predecessor period ended
October 31, 2020 and $5 million in the Successor period ended December 31, 2020. These charges
are included in other operating expenses, net on our consolidated statement of operations.

Property, Plant and Equipment (PP&E)

We use the successful efforts method to account for our oil and natural gas properties. Under this
method, we capitalize costs of acquiring properties, costs of drilling successful exploration wells and
development costs. The costs of exploratory wells, including permitting, land preparation and drilling
costs, are initially capitalized pending a determination of whether we find proved reserves. If we find
proved reserves, the costs of exploratory wells remain capitalized. Otherwise, we charge the costs of
the related wells to expense. In cases where we cannot determine whether we have found proved
reserves at the completion of exploration drilling, we conduct additional testing and evaluation of the
wells. We generally expense the costs of such exploratory wells if we do not find proved reserves
within a one-year period after initial drilling has been completed.

Proved Reserves – Proved reserves are those quantities of oil and natural gas that, by analysis of

geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible—from a specific date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are used for the estimation. We have no
proved oil and natural gas reserves for which the determination of economic producibility is subject to
the completion of major capital investments.

Several factors could change our proved oil and natural gas reserves. For example, for long-lived

properties, higher commodity prices typically result in additional reserves becoming economic and
lower commodity prices may lead to existing reserves becoming uneconomic. Estimation of future
production and development costs is also subject to change partially due to factors beyond our control,
such as energy costs and inflation or deflation of oil field service costs. These factors, in turn, could
lead to changes in the quantity of proved reserves. Additional factors that could result in a change of
proved reserves include production decline rates and operating performance differing from those
estimated when the proved reserves were initially recorded as well as availability of capital to
implement the development activities contemplated in the reserves estimates and changes in
management’s plans with respect to such development activities.

102

We perform impairment tests with respect to proved properties when product prices decline other

than temporarily, reserves estimates change significantly, other significant events occur or
management’s plans change with respect to these properties in a manner that may impact our ability to
realize the recorded asset amounts. Impairment tests incorporate a number of assumptions involving
expectations of undiscounted future cash flows, which can change significantly over time. These
assumptions include estimates of future product prices, which we base on forward price curves and,
when applicable, contractual prices, estimates of oil and natural gas reserves and estimates of future
expected operating and development costs. Any impairment loss would be calculated as the excess of
the asset’s net book value over its estimated fair value. We recognize any impairment loss on proved
properties by adjusting the carrying amount of the asset.

Unproved Properties – When we make acquisitions that include unproved properties, we assign

values based on estimated reserves that we believe will ultimately be proved. As exploration and
development work progresses and if reserves are proved, we transfer the book value from unproved to
proved based on the initially determined rate per BOE. If the exploration and development work were
to be unsuccessful, or management decided not to pursue development of these properties as a result
of lower commodity prices, higher development and operating costs, regulatory changes, contractual
conditions or other factors, the capitalized costs of the related properties would be expensed.

Impairments of unproved properties are primarily based on qualitative factors including intent of

property development, lease term and recent development activity. The timing of impairments on
unproved properties, if warranted, depends upon management’s plans, the nature, timing and extent of
future exploration and development activities and their results. We recognize any impairment loss on
unproved properties by providing a valuation allowance.

Depreciation, Depletion and Amortization – We determine depreciation, depletion and

amortization (DD&A) of oil and natural gas producing properties by the unit-of-production method. Our
unproved reserves are not subject to DD&A until they are classified as proved properties. We amortize
acquisition costs over total proved reserves, and capitalized development and successful exploration
costs over proved developed reserves. Our gas and power plant assets are depreciated over the
estimated useful lives of the assets, using the straight-line method, with expected initial useful lives of
the assets of up to 30 years. We depreciated other property and equipment using the straight-line
method based on expected useful lives of the individual assets or group of assets. The useful lives
typically include ranges of 4-10 years for leasehold improvements, 1-4 years for software and
telecommunications equipment and up to 5 years for computer hardware.

We expense annual lease rentals, the costs of injection used in production and exploration, and
geological, geophysical and seismic costs as incurred. Costs of maintenance and repairs are expensed
as incurred, except that the costs of replacements that expand capacity or add proven oil and natural
gas reserves are capitalized.

Fair Value Measurements

Our assets and liabilities measured at fair value are categorized in a three-level fair-value hierarchy,

based on the inputs to the valuation techniques:

Level 1—using quoted prices in active markets for the assets or liabilities;
Level 2—using observable inputs other than quoted prices for the assets or liabilities; and
Level 3—using unobservable inputs.

Transfers between levels, if any, are recognized at the end of each reporting period. We apply the
market approach for certain recurring fair value measurements, maximize our use of observable inputs
and minimize use of unobservable inputs. We generally use an income approach to measure fair value
when observable inputs are unavailable. This approach utilizes management’s judgments regarding
expectations of projected cash flows and discount rates.

103

Commodity derivatives are carried at fair value. We utilize the mid-point between bid and ask prices

for valuing these instruments. Our commodity derivatives comprise over-the-counter bilateral financial
commodity contracts, which are generally valued using industry-standard models that consider various
inputs, including quoted forward prices for commodities, time value, volatility factors, credit risk and
current market and contracted prices for the underlying instruments, as well as other relevant
economic measures. Substantially all of these inputs are observable data or are supported by
observable prices based on transactions executed in the marketplace. We classify these
measurements as Level 2. Commodity derivatives are the most significant items on our consolidated
balance sheets affected by recurring fair value measurements.

Our PP&E may be written down to fair value if we determine that there has been an impairment.
The fair value is determined as of the date of the assessment generally using discounted cash flow
models based on management’s expectations for the future. Inputs include estimates of future
production, prices based on commodity forward price curves, inclusive of market differentials, as of the
date of the estimate, estimated future operating and development costs and a risk-adjusted discount
rate.

The carrying amounts of cash and other on-balance sheet financial instruments, other than fixed-

rate debt, approximate fair value.

Revenue Recognition

We derive substantially all of our revenue from sales of oil, natural gas and NGLs and associated
hedging activities, with the remaining revenue generated from sales of electricity and trading activities
related to storage and managing excess pipeline capacity. Revenues are recognized when control of
promised goods is transferred to our customers, in an amount that reflects the consideration we expect
to receive in exchange for those goods.

Commodity sales contracts — Disaggregated revenue for sales of oil, natural gas and natural gas

liquids (NGLs) to customers includes the following:

Successor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

Predecessor

January 1, 2020 -
October 31, 2020

(in millions)

Oil . . . . . . . . . . . . . . . .
NGLs . . . . . . . . . . . . .
Natural gas . . . . . . . .

Oil, natural gas and
NGL sales . . . . . . .

1,968
264
411

1,555
250
243

2,643

2,048

176
29
32

237

874
106
112

1,092

See Note 14 Revenue for more information on our revenue from contracts with customers.

104

Joint Ventures and Investments in Unconsolidated Subsidiaries

We may enter into joint ventures that are considered to be a variable interest entity (VIE). A VIE is a

legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to
permit the legal entity to finance its activities without additional subordinated financial support, equity
owners are unable to direct the activities that most significantly impact the legal entity’s economic
performance (or they possess disproportionate voting rights in relation to the economic interest in the
legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the
right to receive the legal entity’s expected residual returns. We consolidate a VIE if we determine that
we have (i) the power to direct the activities of the VIE that most significantly impact its economic
performance and (ii) the obligation to absorb losses or the right to receive benefits from the VIE that
are more than insignificant to the VIE. If an entity is determined to be a VIE but we do not have a
controlling interest, the entity is accounted for under either the cost or equity method depending on
whether we exercise significant influence. See Note 8 Investment in Unconsolidated Subsidiary and
Related Party Transactions for more information on the Carbon TerraVault JV. These evaluations are
highly complex and involve management judgment and may involve the use of estimates and
assumptions based on available information. The evaluation requires continual assessment.

Investments in unconsolidated entities are assessed for impairment whenever changes in the facts

and circumstances indicate a loss in value may have occurred, which is other than temporary.

Allowance for Credit Losses

Our receivables from customers relate to sales of our commodity products, trading activities and
joint interest billings. Credit exposure for each customer is monitored for outstanding balances and
current activity. We actively manage our credit risk by selecting counterparties that we believe to be
financially sound and continue to monitor their financial health. Concentration of credit risk is regularly
reviewed to ensure that counterparty credit risk is adequately diversified. We believe exposure to
counterparty credit-related losses at December 31, 2022 was not material and losses associated with
counterparty credit risk have been insignificant for all periods presented.

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 predominantly comprise oil and natural gas liquids (NGLs), which are
valued at the lower of cost or net realizable value. Inventories, by category, are as follows:

Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Finished goods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Derivative Instruments

2022

2021

(in millions)
56
4

54
6

The fair value of our derivative contracts are netted when a legal right of offset exists with the same

counterparty with an intent to offset. Since we did not apply hedge accounting to our commodity
derivatives for any of the periods presented, we recognized fair value adjustments, on a net basis, in
our consolidated statements of operations. Unless otherwise indicated, we use the term “hedge” to
describe derivative instruments that are designed to achieve our hedging program goals, even though
they are not accounted for as cash-flow or fair-value hedges.

105

Stock-Based Incentive Plans

The shares issuable under our long-term incentive plan were authorized by the Bankruptcy Court

and the terms of a new long-term incentive plan were approved by our new board of directors in
January 2021. In accordance with our new long-term incentive plan, we reserved 9,257,740 shares of
common stock (subject to adjustment) for future issuances to certain executives, employees and
non-employee directors that are more fully described in Note 10 Stock-Based Compensation.

Earnings Per Share

Basic earnings (loss) per share is calculated as net income (loss) divided by the weighted average

number of our common shares outstanding during the period. Diluted earnings (loss) per share is
calculated by dividing net income (loss) by the weighted average number of our common shares
outstanding including the effect of dilutive potential common shares. We compute basic and diluted
earnings per share (EPS) using the two-class method required for participating securities, when
applicable, and the treasury stock method when participating securities are not in place. Certain
restricted and performance stock awards are considered participating securities when such shares
have non-forfeitable dividend rights, which participate at the same rate as common stock.

Under the two-class method, net income allocated to participating securities is subtracted from net
income attributable to common stock in determining net income available to common stockholders. In
loss periods, no allocation is made to participating securities because the participating securities do not
share in losses.

Asset Retirement Obligations

We recognize the fair value of asset retirement obligations (ARO) in the period in which a

determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the
property at the end of its useful life and the cost of the obligation can be reasonably estimated. The fair
value of the retirement obligation is based on future retirement cost estimates and incorporates many
assumptions such as time of abandonment, current regulatory requirements, technological changes,
future inflation rates and a risk-adjusted discount rate. When the liability is initially recorded, we
capitalize the cost by increasing the related PP&E balances. If the estimated future cost or timing of
cash flow changes, we adjust the fair value of the liability and PP&E. Over time the liability is
increased, and expense is recognized for accretion. The cost capitalized to PP&E is recovered over
either the useful life of our facilities or the unit-of-production method for our minerals.

We have asset retirement obligations for certain of our facilities, which includes plant and field
decommissioning, and the plugging and abandonment of wells. In certain cases, we will recognize
ARO in the periods in which sufficient information becomes available to reasonably estimate their fair
values. Additionally, for certain plants, we do not have a legal obligation to decommission them and,
accordingly, we have not recorded a liability.

106

The following table presents a rollforward of our ARO.

(in millions)

Year ended
December 31,
2022

Year ended
December 31,
2021

Beginning balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities settled and divested . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion expense on discounted obligation . . . . . . . . . . . . . . . . . .
Revisions of estimated obligation . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities associated with assets held for sale . . . . . . . . . . . . . . . .

Ending balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$
$

489
(57)
43
15
6
(5)
—

491

59
432

$
$

597
(157)
50
(11)
30
1
(21)

489

51
438

During 2022, our total asset retirement obligation increased by $2 million from 2021. Our liabilities

settled and divested in 2022 of $57 million, included $40 million for settlement payments and
$17 million of liabilities assumed related to our Lost Hills divestiture. Revisions of our estimated
obligation increased $15 million, which reflect higher anticipated future abandonment costs, including
inflation and changes in the timing of settlement.

During 2021, our total asset retirement obligation decreased by $108 million from 2020. Our

liabilities settled and divested in 2021 of $157 million included $42 million for settlement payments and
$115 million of liabilities assumed as part of our Ventura divestiture. Our liabilities included $30 million
of additions, partially offset by $21 million of liabilities reclassified as held for sale. Revisions to our
future cost estimates and abandonment dates for our oil and natural gas assets resulted in a decrease
of $11 million.

See Note 3 Divestitures and Acquisitions for more information on our sold properties and our

liabilities reclassified as held for sale.

Loss Contingencies

In the normal course of business, we are involved in lawsuits, claims and other environmental and
legal proceedings and audits. We accrue reserves for these matters when it is probable that a liability
has been incurred and the liability can be reasonably estimated. In addition, we disclose, if material, in
aggregate, our exposure to losses in excess of the amount recorded on the balance sheet for these
matters if it is reasonably possible that an additional material loss may be incurred. We review our loss
contingencies on an ongoing basis.

Loss contingencies are based on judgments made by management with respect to the likely outcome
of these matters and are adjusted as appropriate. Management’s judgments could change based on new
information, changes in, or interpretations of, laws or regulations, changes in management’s plans or
intentions, opinions regarding the outcome of legal proceedings, or other factors.

Income Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences
attributable to differences between the financial statement carrying amounts of assets and liabilities
and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be
realized. We periodically assess our deferred tax assets and reduce such assets by a valuation
allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will
not be realized.

107

We recognize the financial statement effects of tax positions when it is more likely than not, based

on the technical merits, that the position will be sustained upon examination by a tax authority. We
recognize interest and penalties, if any, related to uncertain tax positions as a component of the
income tax provision. No interest or penalties related to uncertain tax positions were recognized in the
financial statements for the periods presented.

Production-Sharing Type Contracts

Our share of production and reserves from operations in the Wilmington field is subject to

contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the
economic life of the assets. Under such contracts we are obligated to fund all capital and operating
costs. We record a share of production and reserves to recover a portion of such capital and operating
costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover
our partners’ share of capital and operating costs that we incur on their behalf, (ii) for our share of
contractually defined base production and (iii) for our share of remaining production thereafter. We
generate returns through our defined share of production from (ii) and (iii) above. These contracts do
not transfer any right of ownership to us and reserves reported from these arrangements are based on
our economic interest as defined in the contracts. Our share of production and reserves from these
contracts decreases when product prices rise and increases when prices decline, assuming
comparable capital investment and operating costs. However, our net economic benefit is greater
when product prices are higher. These PSCs represented approximately 16% of our total production
for the year ended December 31, 2022.

In line with industry practice for reporting PSCs, we report 100% of operating costs under such
contracts in our consolidated statements of operations as opposed to reporting only our share of those
costs. We report the proceeds from production designed to recover our partners’ share of such costs
(cost recovery) in our revenues. Our reported production volumes reflect only our share of the total
volumes produced, including cost recovery, which is less than the total volumes produced under the
PSCs. This difference in reporting full operating costs but only our net share of production equally
inflates our revenue and operating costs per barrel and has no effect on our net results.

Pension and Postretirement Benefit Plans

All of our employees participate in postretirement benefit plans we sponsor. These plans are
primarily funded as benefits are paid. In addition, a small number of our employees also participate in
defined benefit pension plans sponsored by us. We recognize the net overfunded or underfunded
amounts in the consolidated financial statements at each measurement date.

We determine our defined benefit pension and postretirement benefit plan obligations based on
various assumptions and discount rates. The discount rate assumptions used are meant to reflect the
interest rate at which the obligations could effectively be settled on the measurement date. We
estimate the rate of return on assets with regard to current market factors but within the context of
historical returns.

Pension plan assets are measured at fair value. Publicly registered mutual funds are valued using
quoted market prices in active markets. Commingled funds are valued at the fund units’ net asset value
(NAV) provided by the issuer, which represents the quoted price in a non-active market. Guaranteed
deposit accounts are valued at the book value provided by the issuer.

Actuarial gains and losses that have not yet been recognized through income, are recorded in
accumulated other comprehensive income within equity, net of taxes, until they are amortized as a
component of net periodic benefit cost.

108

Leases

We account for our leases in which we are the lessee, other than mineral leases including oil and

natural gas leases, under an accounting standard which requires us to recognize most leases,
including operating leases, on the balance sheet. The majority of our leases are for commercial office
space, fleet vehicles, drilling rigs, easements and facilities. We categorize leases as either operating or
financing at lease commencement. We recognize a right-of-use (ROU) asset and associated lease
liability for each operating and finance lease with contractual terms of greater than 12 months on the
balance sheet. In considering whether a contract contains a lease, we first consider whether there is an
identifiable asset and then consider how and for what purpose the asset would be used over the
contract term. Our ROU assets are measured at the initial amount of the lease liability determined by
measuring the present value of the fixed minimum lease payments, adjusted for any payments made
before or at the lease commencement date, discounted using our incremental borrowing rate (IBR). In
determining our IBR, we consider the average cost of borrowing for publicly traded corporate bond
yields, which are adjusted to reflect our credit rating, the remaining lease term for each class of our
leases and frequency of payments.

The ROU assets for operating leases are amortized over the term of the lease using the straight-
line method. Lease expense also includes accretion of the lease liability recognized using the effective
interest method. ROU assets are tested for impairment in the same manner as long-lived assets.

Share Repurchase Program

We repurchase shares of our common stock from time to time under a program authorized by our
Board of Directors, including pursuant to a contract, instruction or written plan meeting requirements of
Rule 10b5-1(c)(1) of the Exchange Act. Share repurchases have not been retired and are displayed
separately as treasury stock on our consolidated balance sheet.

Assets Held for Sale

We may market certain non-core oil and natural gas assets or other properties for sale. At the end
of each reporting period, we evaluate if these assets should be classified as held for sale. The held for
sale criteria includes the following: management commitment to a plan to sell, the asset is available for
immediate sale, an active program to locate a buyer exists, the sale of the asset is probable and
expected to be completed within one year, the asset is being actively marketed for sale and it is
unlikely that significant changes will be made to the plan. If all of these criteria are met, the asset is
presented as held for sale on our consolidated balance sheet and measured at the lower of the
carrying amount or estimated fair vale less costs to sell. DD&A expense is not recorded on assets once
classified as held for sale.

The assets classified as held for sale at December 31, 2022 include the remaining assets and the
associated asset retirement obligations in the Ventura basin. See Note 3 Divestitures and Acquisitions
for more information.

109

Other Current Assets

Other current assets, net consisted of the following:

December 31,
2022

December 31,
2021

Net amounts due from joint interest partners(a) . . . . . . . . . . . . . . . . . .
Fair value of derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Greenhouse gas allowances(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas margin deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other

(in millions)
39
39
17
—
16
10
12

47
6
16
31
12
—
9

Other current assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

133

121

Included in the 2022 net amounts due from joint interest partners are allowances of $1 million.

(a)
(b) Greenhouse gas allowances were higher at December 31, 2021 compared to 2022 due to the timing of the allowance

purchases.

Other Noncurrent Assets

Other noncurrent assets consisted of the following:

December 31,
2022

December 31,
2021

Operating lease right-of-use assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred financing costs - Revolving Credit Facility . . . . . . . . . . . . . .
Emission reduction credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid power plant maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deposits and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(in millions)
73
$
6
11
28
7
15

Other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

140

43
11
11
21
1
11

Accrued Liabilities

Accrued liabilities consisted of the following:

December 31,
2022

December 31,
2021

Accrued employee-related costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued taxes other than on income . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating lease liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Premiums due on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . .
Liability for settlement payments due on derivative contracts . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other

(in millions)
49
32
59
19
18
58
33
30

61
30
51
19
11
57
25
43

Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

298

297

110

Other Long-Term Liabilities

Other long-term liabilities consisted of the following:

December 31,
2022

December 31,
2021

Compensation-related liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Postretirement and pension benefit plans . . . . . . . . . . . . . . . . . . . . . .
Operating lease liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Premiums due on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . .
Contingent liability related to Carbon TerraVault JV put and call
rights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other

(in millions)
36
33
52
8

48
8

38
59
37
5

—
6

Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

185

145

Reorganization Items, net

Reorganization items, net consisted of the following:

Successor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

Predecessor

January 1, 2020 -
October 31, 2020

. . . .

(in millions)
Gain on settlement of
liabilities subject to
compromise . . . . . . . . . . . . . .
Unamortized deferred gain
and issuance costs, net
Junior debtor-in-possession
exit fee . . . . . . . . . . . . . . . . . .
Acceleration of unrecognized
compensation expense on
cancelled stock-based
compensation awards . . . . .
Write-off of prepaid directors
and officers’ insurance
premiums . . . . . . . . . . . . . . . .

— $

—

Total non-cash
reorganization items . . .

— $

Legal, professional and
other, net . . . . . . . . . . . . . . . .
Debtor-in-possession
financing costs . . . . . . . . . . .

Total reorganization
items, net . . . . . . . . . . . .

—

(6)

—

(3)

—

4,022

125

(12)

(5)

(2)

4,128

(43)

(25)

— $

(6)

(3)

4,060

111

FORWARD-LOOKING STATEMENTS

Supplemental Cash Flow Information

Supplemental disclosures to our consolidated statements of cash flows, excluding leases and ARO,

are presented below:

Successor

Predecessor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

January 1, 2020 -
October 31, 2020

(in millions)
Supplemental Cash Flow

Information
Interest paid, net of amount
capitalized . . . . . . . . . . . . . . . . . . . . .
Income tax paid . . . . . . . . . . . . . . . . .

Supplemental Disclosure of
Noncash Investing and Financing
Activities

Successor common stock,
Subscription Rights and Warrants
issued pursuant to the Plan . . . . . . .
Successor common stock issued for
the junior debtor-in-possession exit
fee pursuant to the Plan . . . . . . . . . .
Successor common stock and EHP
Notes issued for acquisition of
noncontrolling interest pursuant to
the Plan . . . . . . . . . . . . . . . . . . . . . . .
Successor common stock issued for
a backstop commitment premium
pursuant to the Plan . . . . . . . . . . . . .
Derivative related to additional
earn-out consideration for the
Ventura divestiture . . . . . . . . . . . . . .
Receivable from affiliate . . . . . . . . . .
Dividends accrued for stock-based
compensation awards . . . . . . . . . . . .
Contribution to the Carbon
TerraVault JV . . . . . . . . . . . . . . . . . .

$
$

(43) $
20 $

(28)
—

— $

— $
32 $

2 $

—

3
—

—

$
$

(8)
—

—

—
—

—

$
$

(79)
—

(494)

(12)

(561)

(52)

—
—

—

NOTE 2 PROPERTY, PLANT AND EQUIPMENT

We capitalize the costs incurred to acquire or develop our oil and natural gas assets, including ARO

and interest. For asset acquisitions, purchase price, including liabilities assumed, is allocated to
acquired assets based on relative fair values at the acquisition date. We evaluate long-lived assets on
a quarterly basis for possible impairment.

112

Property, plant and equipment, net consisted of the following:

December 31,
2022

December 31,
2021

Proved oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . .
Unproved oil and natural gas properties . . . . . . . . . . . . . . . . . . . .
Facilities and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total property, plant and equipment

. . . . . . . . . . . . . . . . . . .
Accumulated depreciation, depletion and amortization . . . . . . . .

(in millions)

2,972
2
254

3,228
(442)

Total property, plant and equipment, net . . . . . . . . . . . . . . . .

2,786

2,604
1
240

2,845
(246)

2,599

The following table summarizes the activity of capitalized exploratory well costs:

Successor

Predecessor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

January 1, 2020 -
October 31, 2020

(in millions)

Beginning balance . . . . . . . . . . . . .
Additions to capitalized
exploratory well costs . . . . . . . . . .
Reclassification to property, plant
and equipment . . . . . . . . . . . . . . . .
Charged to expense . . . . . . . . . . .
Impact of fresh start

accounting . . . . . . . . . . . . . . . . .

Ending balance . . . . . . . . . . . . . . .

—

—
—

—

—
(2)

—

—
—

—

—
(2)

(2)

There are not significant exploratory well costs in the periods presented that have been capitalized
for a period greater than one year after the completion of drilling. Our capitalized exploratory well costs
at December 31, 2022 are for permitted wells that we intend to drill.

Asset Impairments

We recognized an asset impairment of $2 million for the year ended December 31, 2022 related to

a write-down of a commercial office building located in Bakersfield, California to fair value. Asset
impairments were $28 million for the year ended December 31, 2021, including $25 million related to
the write-down of the same commercial office building to fair value and a $3 million write-off of
capitalized costs related to projects which were abandoned. We valued our commercial office building
based on a market approach (using Level 3 inputs in the fair value hierarchy). The decline in
commercial demand for office space of this size and type in that market at each assessment resulted in
an impairment. In 2022, we sold our commercial office building for $13 million. See Note 3 Divestitures
and Acquisitions for further information regarding the sale of CRC Plaza.

The following table presents a summary of our asset impairments during the Predecessor period of

2020 (in millions):

Proved oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1,487
228
21

1,736

113

The impairment charge of $1,736 million during the period ended October 31, 2020 was due to the

sharp drop in commodity prices as of our March 31, 2020 assessment date.

The fair values of our proved oil and natural gas properties were determined using discounted cash

flow models incorporating a number of fair value inputs which are categorized as Level 3 on the fair
value hierarchy. These inputs were based on management’s expectations for the future considering
the then-current environment and included index prices based on forward curves, pricing adjustments
for differentials, estimates of future oil and natural gas production, estimated future operating costs and
capital development plans based on the embedded price assumptions. We used a market-based
weighted average cost of capital to discount the future net cash flows. The impairment charge on our
proved oil and natural gas properties primarily related to a steamflood property located in the San
Joaquin basin.

As of our March 31, 2020 assessment date, we determined our ability to develop our unproved

properties, which primarily consisted of leases held by production in the San Joaquin basin, was
constrained for the foreseeable future and we did not intend to develop them.

We did not record an impairment charge during the Successor period of 2020.

NOTE 3 DIVESTITURES AND ACQUISITIONS

Divestitures

Ventura Basin

During the second quarter of 2021, we entered into transactions to sell our Ventura basin assets.
The transactions contemplate multiple closings that are subject to customary closing conditions. The
closings that occurred in the second half of 2021 resulted in the divestiture of the vast majority of our
Ventura basin assets. We recognized a gain of $120 million on the Ventura divestiture during the year
ended December 31, 2021.

During the year ended December 31, 2022, we recognized a gain of $11 million related to the sale
of certain Ventura basin assets. The closing of the sale of our remaining assets in the Ventura basin is
subject to final approval from the State Lands Commission, which we expect to receive in the first half
of 2023. These remaining assets, consisting of property, plant and equipment and associated asset
retirement obligations, are classified as held for sale on our consolidated balance sheet as of
December 31, 2022.

Lost Hills

On February 1, 2022, we sold our 50% non-operated working interest in certain horizons within our

Lost Hills field, located in the San Joaquin basin, recognizing a gain of $49 million. We retained an
option to capture, transport and store 100% of the CO2 from steam generators across the Lost Hills
field for future carbon management projects. We also retained 100% of the deep rights and related
seismic data.

CRC Plaza

In June 2022, we sold our commercial office building located in Bakersfield, California for net
proceeds of $13 million, recognizing no gain or loss on sale. We also leased back a portion of the
building with a term of 18 months. See Note 2 Property, Plant and Equipment for details of impairment
charges we recognized prior to the sale of this property.

114

Other Divestitures

In 2022, we sold non-core assets recognizing a $1 million loss.

In 2021, we also sold unimproved land and other non-core assets for $13 million in proceeds

recognizing a $4 million gain.

In January 2020, we sold royalty interests and divested non-core assets resulting in $41 million of

proceeds which was treated as a normal retirement and no gain or loss was recognized.

Acquisitions

MIRA JV

Our development joint venture with Macquarie Infrastructure and Real Assets Inc. (MIRA JV)

contemplated that MIRA would fund the development of certain of our oil and natural gas properties in
exchange for a 90% working interest. In August 2021, we purchased MIRA’s entire working interest
share for $52 million. We accounted for this transaction as an asset acquisition. Prior to the acquisition,
our consolidated results reflect only our 10% working interest share in the productive wells.

Other Acquisitions

In 2022, we acquired properties for carbon management activities for approximately $17 million.

NOTE 4 DEBT

As of December 31, 2022 and 2021, our long-term debt consisted of the following:

Successor

Interest Rate

Maturity

2022

2021

Revolving Credit Facility . . . . . . . . . . .

Senior Notes . . . . . . . . . . . . . . . . . . . .

Principal amount of debt

. . . . . . .
Unamortized debt issuance costs . . . .

Long-term debt, net . . . . . . . . . . . .

(in millions)
— $

600

600
(8)

592

— SOFR plus 3%-4%
ABR plus 2%-3%
7.125%

600

April 29, 2024

February 1, 2026

600
(11)

589

Fair Value

The estimated fair value of our debt at December 31, 2022 and 2021 was approximately

$574 million and $623 million, respectively. We estimate the fair value of our fixed-rate debt based on
prices from known market transactions as of December 31, 2022 and 2021 (Level 1 inputs on the fair
value hierarchy).

115

Revolving Credit Facility

On October 27, 2020, we entered into a Credit Agreement with Citibank, N.A., as administrative

agent, and certain other lenders. This credit agreement consists of a senior revolving loan facility
(Revolving Credit Facility) with an aggregate commitment of $602 million, which we are permitted to
increase if we obtain additional commitments from new or existing lenders. The aggregate commitment
increased from $492 million as of December 31, 2021 due to $110 million of additional commitments
from new lenders that joined this facility in 2022. Our Revolving Credit Facility also includes a sub-limit
of $200 million for the issuance of letters of credit. As of December 31, 2022, we had approximately
$458 million available for borrowing under the Revolving Credit Facility after taking into account
$144 million of outstanding letters of credit.

The proceeds of all or a portion of the Revolving Credit Facility may be used for our working capital

needs and for other purposes subject to meeting certain criteria.

Security – The lenders have a first-priority lien on a substantial majority of our assets.

Interest Rate – In February 2022, we amended our Revolving Credit Facility to change the
benchmark rate from the London Interbank Offered Rate to the secured overnight financing rate
(SOFR). We can elect to borrow at either an adjusted SOFR rate or an alternate base rate (ABR),
subject to a 1% floor and 2% floor, respectively, plus an applicable margin. The ABR is 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%. The applicable margin is adjusted based on the borrowing base
utilization percentage and will vary from (i) in the case of SOFR loans, 3% to 4% and (ii) in the case of
ABR loans, 2% to 3%. The unused portion of the facility is subject to a commitment fee of 0.50% per
annum. We also pay customary fees and expenses. Interest on ABR loans is payable quarterly in
arrears. Interest on SOFR loans is payable at the end of each SOFR period, but not less than
quarterly.

Amortization Payments – The Revolving Credit Facility does not include any obligation to make

amortizing payments.

Borrowing Base – The borrowing base, currently $1.2 billion, will be redetermined semi-annually

each April and October.

Financial Covenants – Our Revolving Credit Facility includes the following financial covenants:

Ratio

Components

Required Levels

Tested

Consolidated Total Net
Leverage Ratio . . . . . . . . . . . . .

Ratio of Consolidated Total
Debt to Consolidated
EBITDAX(a)

Current Ratio . . . . . . . . . . . . . . Ratio of consolidated current

assets to consolidated current
liabilities(b)

Not greater than 3.00 to
1.00

Quarterly

Not less than 1.00 to
1.00

Quarterly

(a) EBITDAX is calculated as defined in the credit agreement.
(b) The available credit under our Revolving Credit Facility is included in consolidated current assets as part of the

calculation of the current ratio.

Other Covenants – Our Revolving Credit Facility includes covenants that, among other things,
restrict our ability to incur additional indebtedness, grant liens, make asset sales and investments,
repay existing indebtedness, make subsidiary distributions and enter into transactions that would result
in fundamental changes. We are also restricted in the amount of cash dividends we can pay on our
common stock unless we meet certain covenants included in the credit agreement.

116

In April 2022, we amended our Revolving Credit Facility to, among other things, modify the

minimum hedge requirement and the restricted payment and investment covenants contained in the
Revolving Credit Facility. As a result of this amendment, the rolling hedge requirement has been
modified. As amended, our Revolving Credit Facility requires us to maintain hedges on a minimum
amount of crude oil production (determined on (i) the date of delivery of annual and quarterly financial
statements and (ii) the date of delivery of a reserve report delivered in connection with an interim
borrowing base redetermination) of no less than (i) in the event that our Consolidated Total Net
Leverage Ratio (as defined in the Credit Agreement) is greater than 2:1 as of the end of the most
recent fiscal quarter test period, 50% of our reasonably anticipated oil production from our proved
developed producing reserves for each quarter during the period ending the earlier of (1) the maturity
date of the Revolving Credit Facility and (2) 12 months after the delivery of the compliance certificate
for the relevant test period and (ii) in the event that our Consolidated Total Net Leverage Ratio is less
than or equal to 2:1 but greater than 1:1 as of the end of the most recent fiscal quarter test period, 33%
of our reasonably anticipated oil production from our proved developed producing reserves for each
quarter during the period ending the earlier of (1) the maturity date of the Revolving Credit Facility and
(2) 12 months after the delivery of the compliance certificate for the relevant test period. The foregoing
minimum hedge requirements do not apply to the extent that our Consolidated Total Net Leverage
Ratio is less than or equal to 1:1 as of the last day of the most recently ended fiscal quarter test period.

Furthermore, the restricted payment and investments covenants were modified to permit unlimited
investments and/or restricted payments so long as (i) no Default, Event of Default or Borrowing Base
Deficiency shall have occurred and be continuing under the Revolving Credit Facility at the time of
such investment or restricted payment, (ii) the undrawn availability under the Revolving Credit Facility
at such time is not less than 30.0% of the total commitment and (iii) the Consolidated Total Net
Leverage Ratio is less than or equal to 1.5:1.

Events of Default and Change of Control – Our Revolving Credit Facility provides for certain events

of default, including upon a change of control, as defined in the credit agreement, that entitles our
lenders to declare the outstanding loans immediately due and payable, subject to certain limitations
and conditions.

Senior Notes

On January 20, 2021, we completed an offering of $600 million in aggregate principal amount of our

7.125% senior unsecured notes due 2026 (Senior Notes). The net proceeds of $587 million, after
$13 million of debt issuance costs, were used to repay in full our Second Lien Term Loan and EHP
Notes, with the remainder used to repay substantially all of the then outstanding borrowings under our
Revolving Credit Facility. We recognized a $2 million loss on extinguishment of debt, including
unamortized debt issuance costs, associated with these repayments.

Security – Our Senior Notes are general unsecured obligations which are guaranteed on a senior

unsecured basis by certain of our material subsidiaries.

Redemption – On or after February 1, 2023, we may redeem the Senior Notes at any time prior to

the maturity date at a redemption price equal to (i) 104% of the principal amount if redeemed in the
twelve months beginning February 1, 2023, (ii) 102% of the principal amount if redeemed in the twelve
months beginning February 1, 2024 and (iii) 100% of the principal amount if redeemed after
February 1, 2025, in each case plus accrued and unpaid interest.

Other Covenants – Our Senior Notes include covenants that, among other things, restrict our ability
to incur additional indebtedness, issue preferred stock, grant liens, make asset sales and investments,
repay existing indebtedness, make subsidiary distributions and enter into transactions that would result
in fundamental changes.

117

Events of Default and Change of Control – Our Senior Notes provide for certain triggering events,
including upon a change of control, as defined in the indenture, that would require us to repurchase all
or any part of the Senior Notes at a price equal to 101% of the aggregate principal amount plus
accrued and unpaid interest.

Second Lien Term Loan

On October 27, 2020, we entered into a $200 million credit agreement with Alter Domus Products

Corp., as administrative agent, and certain other lenders (Second Lien Term Loan). The proceeds
were used to refinance our Junior DIP Facility and to pay certain costs, fees and expenses related to
the other transactions consummated on the Effective Date.

Security – The lenders had a second-priority lien (junior to the Revolving Credit Facility) on a

substantial majority of our assets, except assets securing the EHP Notes as discussed below.

Interest Rate – We could elect to pay interest at either an adjusted LIBOR rate or ABR rate, subject

to a 1% floor and 2% floor, respectively, plus an applicable margin. The ABR rate was equal to the
highest of (i) the prime rate, (ii) the federal funds rate effective rate plus 0.50%, and (iii) the one-month
adjusted LIBOR rate plus 1%. Prior to the second anniversary of the closing date of the Second Lien
Term Loan, the applicable margin in the case of an ABR rate election was 8% per annum if paid in
cash and 9.50% per annum if paid-in-kind, and the applicable margin in the case of an adjusted LIBOR
rate election was 9% if paid in cash and 10.50% if paid-in-kind. After the second anniversary of the
closing date, the applicable margin was 8% with respect to any ABR loan and 9% with respect to an
adjusted LIBOR loan. Interest on ABR loans was paid quarterly in arrears and interest based on the
adjusted LIBOR rate was due at the end of each LIBOR period, which could be one, two, three or six
months but not less than quarterly. We also paid customary fees and expenses.

Maturity Date – Our Second Lien Term Loan would mature five years after the closing date, subject

to extension.

Redemption – We could elect to redeem all or part of our Second Lien Term Loan, at any time prior
to the maturity date, at redemption price equal to (i) 100% of the principal amount if redeemed prior to
90 days after closing, (ii) 105% of the principal amount if redeemed after 90 days and before the first
anniversary date, (iii) 103% of the principal amount if redeemed on or after the first anniversary date
and before the second anniversary date, (iv) 102% of the principal amount if redeemed on or after the
second anniversary date and before the third anniversary date, (v) 101% of the principal amount if
redeemed on or after the third anniversary date and before the fourth anniversary date, and (vi) at
100% of the principal amount if redeemed in the fifth year.

Financial Covenants – Our Second Lien Term Loan included certain financial covenants that were

to be tested quarterly, including a consolidated total net leverage ratio and current ratio.

Liquidity – We would become subject to a monthly minimum liquidity requirement of $170 million if,
as of the Spring 2021 Scheduled Redetermination (as defined in the Revolving Credit Facility), (a) our
liquidity was less than $247 million and (b) we were not able to obtain at least $51 million in additional
commitments under our Revolving Credit Facility or through capital markets or other junior financing
transactions, for so long as the conditions in (a) and (b) remained unmet.

Other Covenants – Our Second Lien Term Loan included covenants that, among other things,
restricted our ability to incur additional indebtedness, grant liens, make asset sales and investments,
repay existing indebtedness, make subsidiary distributions and enter into transactions that would result
in fundamental changes. We were also restricted in the amount of cash dividends we could pay on our
common stock unless we met certain covenants included in the credit agreement.

118

Our Second Lien Term Loan also required us to maintain hedges on a minimum amount of crude oil
production on terms that were substantially consistent with the requirements of our Revolving Credit facility.

Events of Default and Change of Control – Our Second Lien Term Loan provided for certain events
of default, including upon a change of control, as defined in the credit agreement, that would entitle our
lenders to declare the outstanding loans immediately due and payable, subject to certain limitations
and conditions. We were subject to a cross-default provision that causes a default under this facility if
certain defaults occurred under the Revolving Credit Facility or the EHP Notes.

The Second Lien Term Loan was terminated and repaid with proceeds from our Senior Notes

offering in January 2021 as described above.

EHP Notes

On the Effective Date, our wholly-owned subsidiary, EHP Midco Holding Company, LLC (Elk Hills
Issuer) entered into a Note Purchase Agreement (Note Purchase Agreement) with certain subsidiaries
of Ares and Wilmington Trust, N.A. as collateral agent. The $300 million Notes were issued as partial
consideration for the Class B Preferred Units, Class A Common Units and Class C Common Units in
the Ares JV previously held by ECR (EHP Notes).

The EHP Notes were senior notes due in 2027 and were secured by a first-priority security interest
in all of the assets of Elk Hills Power, any third-party offtake contracts for power generated by Elk Hills
Power, all of the equity interests of Elk Hills Power held by Elk Hills Issuer and all of the equity interests
of Elk Hills Issuer held by its direct parent, EHP Topco Holding Company, LLC, our wholly-owned
subsidiary. We and Elk Hills Power guaranteed, on a joint and several basis, all of the obligations of
Elk Hills Issuer under the EHP Notes. The EHP Notes bore an interest rate of 6.0% per annum through
the fourth anniversary of issuance, increasing to 7.0% per annum after the fourth anniversary of
issuance and to 8.0% per annum after the fifth anniversary of issuance. We were permitted to redeem
the EHP Notes at any time prior to their maturity date without payment of premium or penalty.

The EHP Notes were terminated and repaid with proceeds from our Senior Notes offering in

January 2021 as described above.

Other

At December 31, 2022, all obligations under our Revolving Credit Facility and Senior Notes are

guaranteed by certain of our material wholly owned subsidiaries.

The terms and conditions of all of our indebtedness are subject to additional qualifications and

limitations that are set forth in the relevant governing documents.

At December 31, 2022, we were in compliance with all debt covenants under our credit

agreements.

Principal maturities of debt outstanding at December 31, 2022 are as follows:

As of
December 31, 2022
(in millions)

2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

—
—
—
600
—
—

600

119

NOTE 5 LEASES

Balance sheet information related to our operating leases as of December 31, 2022 and 2021 were

as follows:

Right-of-use assets . . . . . . . . . . . . . . . Other noncurrent assets
Operating lease liabilities . . . . . . . . . . .
Operating lease liabilities . . . . . . . . . . . Other long-term liabilities

Accrued liabilities

$
$

(in millions)
73
18
52

$
$

43
11
37

Classification

2022

2021

We determine if our arrangements contain a lease at inception. A lease is defined as a contract, or
part of a contract, that conveys the right to control the use of identified property, plant or equipment for
a period of time in exchange for consideration. We have operating lease liabilities for carbon
sequestration easements, drilling rigs, vehicles and commercial office space.

We combine lease and nonlease components in determining fixed minimum lease payments for our

drilling rigs and commercial office space. If applicable, fixed minimum lease payments are reduced by
lease incentives for our commercial buildings and increased by mobilization and demobilization fees for
our drilling rigs. Certain of our lease agreements include options to extend or terminate the lease,
which we exercise at our sole discretion. For our existing leases, we did not include these options in
determining our fixed minimum lease payments over the lease term. Our leases do not include options
to purchase the leased property. Lease agreements for our fleet vehicles include residual value
guarantees, none of which are recognized in our financial statements until the underlying contingency
is resolved.

Variable lease costs for our drilling rigs include costs to operate, move and repair the rigs. Variable

lease costs for certain of our commercial office buildings included utilities and common area
maintenance charges. Variable lease costs for our fleet vehicles include other-than-routine
maintenance and other various amounts in excess of our fixed minimum rental fee.

Our lease costs, including amounts capitalized to PP&E, shown in the table below are before joint-

interest recoveries. Lease payments are reduced by joint interest recoveries on our consolidated
statement of operations through our joint-interest billing process.

Operating lease costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term lease costs(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Variable lease costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total operating lease costs . . . . . . . . . . . . . . . . . . . . . . . .
Sublease income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total lease costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Year ended
December 31,
2022

Year ended
December 31,
2021

(in millions)
17
59
6

82
(1)

14
48
4

66
(2)

(a) Contracts with terms of less than one month or less are excluded from our disclosure of short-term lease costs.

We had two contracts treated as finance leases, where the terms ended in 2022. These leases

were not material to our consolidated results of operations for the periods presented.

120

We sublease certain commercial office space to third parties where we are the primary obligor
under the head lease. The lease terms on those subleases never extend past the term of the head
lease and the subleases contain no extension options or residual value guarantees. Sublease income
is recognized based on the contract terms and included as a reduction of operating lease cost under
our head lease. We sold our commercial office space during 2022. Sublease income was not material
to our consolidated financial statements for all periods presented.

Other supplemental information related to our operating and finance leases as of December 31,

2022 and 2021 is provided below:

Year ended
December 31,
2022

Year ended
December 31,
2021

(in millions)

Cash paid for lease liabilities

Lease liabilities associated with operating

activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lease liabilities associated with investing

activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lease liabilities associated with financing

activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

ROU assets obtained in exchange for new operating
lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

— $

2022

2021

Operating Leases
Weighted-average remaining lease term (in years) . . . . . . . . .
Weighted-average discount rate . . . . . . . . . . . . . . . . . . . . . . . .

Finance Leases
Weighted-average remaining lease term (in years) . . . . . . . . .
Weighted-average discount rate . . . . . . . . . . . . . . . . . . . . . . . .

6.43
6.1 %

—
— %

8.25
5.4 %

0.33
4.0 %

The difference in the weighted-average discount rate between operating leases and finance leases

in 2021 primarily relates to lease term.

Our operating lease payments are as follows:

As of
December 31, 2022
(in millions)

2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Less: Interest

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Present value of lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

21
15
12
12
5
20

(15)

121

NOTE 6 LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

We, or certain of our subsidiaries, 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
December 31, 2022 and 2021 were not material to our 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.

We have certain commitments under contracts, including purchase commitments for goods and
services used in the normal course of business such as pipeline capacity, easements related to oil and
natural gas operations, obligations under long-term service agreements and field equipment.

At December 31, 2022, total purchase obligations on a discounted basis were as follows:

December 31,
2022
(in millions)

2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Present value of purchase obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

61
9
6
6
5
25

112
(19)

122

NOTE 7 DERIVATIVES

We continue to maintain a commodity hedging program primarily focused on crude oil to help

protect our cash flows, margins and capital program from the volatility of commodity prices. We did not
have any commodity derivatives designated as accounting hedges as of and during the years ended
December 31, 2022, 2021 and each of the periods in 2020. 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 accounting hedges. Our Revolving
Credit Facility includes covenants that require us to maintain a certain level of hedges. We have also
entered into incremental hedges above and beyond these requirements and will continue to evaluate
our hedging strategy based on prevailing market prices and conditions. For more information on the
requirements of our Revolving Credit Facility, see Note 4 Debt.

Commodity-Price Risk

As part of our hedging program, we held the following Brent-based crude oil contracts as of

December 31, 2022:

Sold Calls:

Q1
2023

Q2
2023

Q3
2023

Q4
2023

2024

—
Barrels per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average price per barrel . . . . . . . . . . . . . . . $ 57.28 $ 60.00 $ 57.06 $ 57.06 $ —

17,363

17,837

18,322

5,747

Swaps

1,492
Barrels per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average price per barrel . . . . . . . . . . . . . . . $ 69.46 $ 68.53 $ 68.33 $ 70.18 $79.06

26,094

16,620

16,697

16,475

Net Purchased Puts(a)

1,724
Barrels per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average price per barrel . . . . . . . . . . . . . . . $ 76.25 $ 76.25 $ 76.25 $ 76.25 $75.00

17,363

17,837

18,322

5,747

(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.
Net purchased puts – we receive settlement payments for prices below 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.

We use combinations of these positions to meet the requirements of our Revolving Credit Facility

and to increase the efficacy of our hedging program. At December 31, 2022, we had derivative
contracts for an insignificant amount of natural gas volumes.

123

Derivative instruments not designated as hedging instruments are required to be recorded on the
balance sheet at fair value. Noncash derivative gains and losses, along with settlement payments, are
reported in net (loss) gain from commodity derivatives on our consolidated statements of operations as
shown in the table below:

Successor

Predecessor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

January 1, 2020 -
October 31, 2020

(in millions)
Non-cash commodity
derivative gain (loss),
excluding noncontrolling
interest
Non-cash commodity
derivative (loss) gain,
attributable to noncontrolling
. . . . . . . . . . . . . . . . .
interest

. . . . . . . . . . . . . . . . . $

Total non-cash
changes . . . . . . . . . . . . . .
Net (payments) proceeds
on commodity derivatives

Net (loss) gain from
commodity derivatives . . . . . $

Interest-Rate Risk

187 $

(357) $

(138) $

(19)

—

187

(738)

—

(357)

(319)

(2)

(140)

(1)

(551) $

(676) $

(141) $

(17)

108

As of December 31, 2022, we do not have any derivative contracts in place with respect to interest-
rate exposure. In May 2018, we entered into derivative contracts that limited our interest rate exposure
with respect to a notional amount of $1.3 billion of variable-rate indebtedness. These contracts expired
on May 4, 2021. We did not report any gains or losses on these contracts and no settlement payments
were received during the year ended December 31, 2021 or the periods in 2020.

Fair Value of Derivatives

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.

The following tables present the fair values (at gross and net) of our outstanding commodity

derivatives:

December 31, 2022

Gross
Amounts at
Fair Value

Classification

Assets:
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . .

Liabilities:
Current - Fair value of derivative contracts . . . . . . . . . .
Noncurrent - Fair value of derivative contracts . . . . . . .

124

51 $
7

(258)
—
(200) $

Netting

Net Fair Value

(in millions)

(12) $
—

12
—
— $

39
7

(246)
—
(200)

December 31, 2021

Classification

Gross
Amounts at
Fair Value Netting Net Fair Value

Assets:
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(in millions)
(27) $
(11)

33 $
12

Liabilities:
Current - Fair value of derivative contracts . . . . . . . . . . . . . . . . . . . .
Noncurrent - Fair value of derivative contracts . . . . . . . . . . . . . . . . .

(297)
(143)

27
11

(395) $ — $

6
1

(270)
(132)

(395)

Counterparty Credit Risk

As of December 31, 2022, all of our derivative financial instruments were with investment-grade
counterparties. We actively evaluate the creditworthiness of our counterparties, assign credit limits and
monitor exposure against those assigned limits. We believe exposure to credit-related losses as of
December 31, 2022 was not significant. Losses associated with credit risk have been insignificant for
all periods presented. At December 31, 2022, and 2021, we had an insignificant amount of collateral
posted.

NOTE 8 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 BGTF Sierra Aggregator LLC (Brookfield) for the further development of a carbon management
business in California (Carbon TerraVault JV). We hold a 51% interest in the Carbon TerraVault JV
and Brookfield holds a 49% interest. We determined that the Carbon TerraVault JV is a VIE; however,
we share decision-making power with Brookfield on all matters that most significantly impact the
economic performance of the joint venture. Therefore, we account for our investment in the Carbon
TerraVault JV under the equity method of accounting. See Note 1 Nature of Business, Summary of
Significant Accounting Policies and Other for more information on the VIE consolidation model.

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
our share of 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. The remaining $32 million is included in receivable from affiliate on our
consolidated balance sheet as of December 31, 2022. 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 consolidated balance sheet. This contingent liability was $48 million as of
December 31, 2022, including $2 million of interest, and reflects the amount we would be required to
pay should Brookfield exercise its put right.

125

The carrying value of our investment in unconsolidated subsidiary was $13 million as of

December 31, 2022. This carrying value reflects our investment less cumulative losses allocated to us
of $1 million through December 31, 2022. The underlying net assets of the Carbon TerraVault JV were
$314 million as of December 31, 2022 which includes cash on hand and PP&E, net of current liabilities.
The difference between the carrying value of our investment and the carrying value of the underlying
net assets of the joint venture relates to our accounting for the contribution of the 26R reservoir as a
financing arrangement due to the put and call features of the joint venture. The joint venture
recognized the cash contributions by the members and the 26R reservoir at fair value.

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).

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 amounts in an approved budget. The MSA may be terminated by mutual
agreement of the parties, among other events. As of December 31, 2022, we had a $1 million
receivable due to us under the MSA which is included in receivable from affiliate on our consolidated
balance sheet.

NOTE 9 INCOME TAXES

Net income (loss) before income taxes, for all periods presented, was generated from domestic

operations. We recognized an income tax provision (benefit) for the periods presented as follows:

Successor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

Predecessor

January 1, 2020 -
October 31, 2020

(in millions)
Current
Federal
State . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . $

Subtotal . . . . . . . . . . . .

Deferred
Federal
. . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . .

Subtotal . . . . . . . . . . . .

Total income tax
provision (benefit) . . $

10 $
1

141
85

226

—
—

—

(161)
(235)

(396)

237 $

(396)

—
—

—

—
—

—

—
—

—

—
—

—

126

Total income tax provision (benefit) differs from the amounts computed by applying the U.S. federal

income tax statutory rate to pre-tax income (loss) as follows:

Year ended
December 31,
2022

Successor

Year ended
December 31,
2021

Predecessor

November 1, 2020 -
December 31, 2020

January 1, 2020 -
October 31, 2020

U.S. federal statutory tax
rate . . . . . . . . . . . . . . . . . . . .
State income taxes, net
. . .
Exclusion of income
attributable to
noncontrolling interests . . . .
Debt restructuring . . . . . . . .
Changes in tax attributes . .
Executive compensation . .
Change in the U.S. federal
valuation allowance . . . . . .
Other . . . . . . . . . . . . . . . . . .

21 %
9

21 %
(81)

—
—
(2)
—

2
1

(1)
—
(8)
2

(106)
—

(173) %

21 %
—

—
—
—
—

(20)
(1)

— %

21 %
—

(1)
—
—
—

(21)
1

— %

Effective tax rate . . . . . . . . .

31 %

For the year ended December 31, 2022, our effective rate of 31% differed from the U.S. federal
statutory tax rate of 21% primarily due to state taxes and the increase in a valuation allowance for a
capital loss generated from the sale of Lost Hills. For the year ended December 31, 2021, our effective
tax rate of negative 173% differed from the U.S. federal statutory tax rate of 21% primarily due to state
taxes and releasing all of our valuation allowance recorded against our net deferred tax assets given
our anticipated future earnings trends at that time. A portion of the change in our valuation allowance
during 2021 was for the utilization of tax benefits against current year income and the remainder was
recognized as a tax benefit reflecting the projected utilization of our deferred tax assets. We did not
record an income tax provision (benefit) in the period ended December 31, 2020 or the period ended
October 31, 2020.

The tax effects of temporary differences resulting in deferred income tax assets and liabilities at

December 31, 2022 and 2021 were as follows:

2022

2021

Deferred Tax
Assets

Deferred Tax
Liabilities

Deferred Tax
Assets

Deferred Tax
Liabilities

Property, plant and equipment . . . . . . . . .
Postretirement and pension benefit
plans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . .
Net operating loss and tax credit
carryforwards . . . . . . . . . . . . . . . . . . . . . . .
Business interest expense
carryforward . . . . . . . . . . . . . . . . . . . . . . . .
Federal benefit of state income taxes . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Subtotal

. . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowance . . . . . . . . . . . . . . . .

Total deferred taxes . . . . . . . . . . . . . . . . .

(267)

(in millions)

(1)
—

—

—
(31)
(36)

(335)
—

$ (335)

10
148

167
—
77

534
(35)

499

127

122

18
152

177
—
59

616
—

616

(151)

—
—

—

—
(49)
(20)

(220)
—

(220)

Management expects to realize the recorded deferred tax assets primarily through future operating

income and reversal of taxable temporary differences. We assess the realizability of our deferred tax
assets each period by considering whether it is more-likely-than-not that all or a portion of our deferred
tax assets will be realized. At each reporting date new evidence is considered, both positive and
negative, including whether sufficient future taxable income will be generated to permit realization of
existing deferred tax assets. The amount of deferred tax assets considered realizable is not assured
and could be adjusted if estimates change or three-years of cumulative income is no longer present.

Carryforwards

As of December 31, 2022, we had U.S. federal net operating loss carryforwards of $29 million,
which begin to expire in 2037. Our carryforward for disallowed business interest of $794 million does
not expire.

As of December 31, 2022, we had California net operating loss carryforwards of $2.4 billion, which

begin to expire in 2026, and $23 million of tax credit carryforwards, which begin to expire in 2041.

Our ability to utilize a portion of our net operating loss, tax credit and interest expense
carryforwards is subject to an annual limitation since we experienced an ownership change in
connection with our emergence from bankruptcy. We did not recognize a tax benefit for $18 million
U.S. federal net operating loss carryforwards and approximately $2 billion California net operating loss
carryforwards which we expect will expire unused. Additionally, we did not recognize a tax benefit for
$14 million of California tax credit carryforwards which we expect will expire unused.

Unrecognized Tax Benefits

We did not record a liability for unrecognized tax benefits as of December 31, 2022 and 2021.

In the period ended October 31, 2020, we recognized a tax benefit of $101 million for uncertain tax

positions which primarily related to the calculation of the limitation on business interest expense. In
2020, the Internal Revenue Service (IRS) issued final regulations which clarified the calculation of the
limitation on the deduction of business interest expense. Based on our evaluation of these final
regulations, we determined that our income tax returns were filed on at least a more-likely-than-not
basis and accordingly we reversed our liability for uncertain tax positions.

We remain subject to audit by the Internal Revenue Service for calendar years 2019 through 2021

as well as 2018 through 2021 by the state of California.

NOTE 10 STOCK-BASED COMPENSATION

On January 18, 2021, our Board of Directors approved the California Resources Corporation 2021

Long Term Incentive Plan (Long Term Incentive Plan). The shares issuable under the new long-term
incentive plan had been previously authorized by the Bankruptcy Court in connection with our
emergence from Chapter 11 and the terms of the new long-term incentive plan were approved by our
Board of Directors. As a result, the Long Term Incentive Plan became effective on January 18, 2021.
The Long Term Incentive Plan provides for potential grants of stock options, stock appreciation rights,
restricted stock awards, restricted stock units, vested stock awards, dividend equivalents, other stock-
based awards and substitute awards to employees, officers, non-employee directors and other service
providers of the Company and its affiliates. The Long Term Incentive Plan replaces the earlier
Amended and Restated California Resources Corporation Long Term Incentive Plan which was
cancelled upon our emergence from bankruptcy, along with all outstanding stock-based compensation
awards granted thereunder.

128

The Long Term Incentive Plan provides for the reservation of 9,257,740 shares of common stock

for future issuances, subject to adjustment as provided in the Long Term Incentive Plan. Shares of
stock subject to an award under the Long Term Incentive Plan that expires or is cancelled, forfeited,
exchanged, settled in cash or otherwise terminated without the actual delivery of shares (restricted
stock awards are not considered “delivered shares” for this purpose) will again be available for new
awards under the Long Term Incentive Plan. However, (i) shares tendered or withheld in payment of
any exercise or purchase price of an award or taxes relating to awards, (ii) shares that were subject to
an option or a stock appreciation right but were not issued or delivered as a result of the net settlement
or net exercise of the option or stock appreciation right, and (iii) shares repurchased on the open
market with the proceeds from the exercise price of an option, will not, in each case, again be available
for new awards under the Long Term Incentive Plan.

Shares of our common stock may be withheld by us in satisfaction of tax withholding obligations

arising upon the vesting of restricted stock units (RSUs) and performance stock units (PSUs).

Stock-based compensation expense is recorded on our consolidated statements of operations

based on job function of the employees receiving the grants as shown in the table below.

Successor

Year ended
December 31,
2022

Year ended
December 31,
2021

November 1,
2020 -
December 31,
2020

Predecessor
January 1,
2020 -
October 31,
2020

(in millions)
General and administrative
expenses . . . . . . . . . . . . . . . . . . . . . $
Operating costs . . . . . . . . . . . . . . . .

Total stock-based compensation
expense . . . . . . . . . . . . . . . . . . . . $

Income tax benefit

. . . . . . . . . . . . . $

26
4

17
2

— $

— $
—

— $

2
1

—

We paid $6 million for our long-term cash incentive awards for the year ended December 31, 2022.

We did not make any payments for the cash-settled portion of our awards for the year ended
December 31, 2021 or in the Successor period of 2020. We made payments of $8 million for the cash-
settled portion of our long-term incentive awards during the Predecessor period of 2020.

Successor Stock-Based Compensation Plan

Long-Term Stock Settled Awards

Restricted Stock Units

Executives and non-employee directors were granted RSUs, which are in the form of, or equivalent

in value to, actual shares of our common stock. The awards generally vest ratably over three years,
with one third of the granted units vesting on each of the first three anniversaries of the applicable date
of grant. RSUs are settled in shares of our common stock at the end of the third year of the three-year
vesting period.

129

The following table sets forth RSU activity for the year ended December 31, 2022:

Unvested at December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled or Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Unvested at December 31, 2022 . . . . . . . . . . . . . . . . . . . . . . . . .

1,121

Number of Units
(in thousands)
$
1,130
20
$
— $
(29) $

Weighted-
Average Grant-
Date Fair Value

25.28
44.31
—
24.78

25.64

Compensation expense was measured on the date of grant using the quoted market price of our
common stock and is primarily recognized on a straight-line basis over the requisite service periods
adjusted for actual forfeitures, if any.

As of December 31, 2022, the unrecognized compensation expense for our unvested RSUs was

approximately $10 million and is expected to be recognized over a weighted-average remaining
service period of approximately one year.

Performance Stock Units

Executives were granted PSUs which are earned upon the attainment of specified 60-trading day
volume weighted average prices for shares of our common stock generally during a three-year service
period commencing on the grant date. Once units are earned, the earned units are not reduced for
subsequent decreases in stock price. For the duration of the three-year period, a minimum of 0% and a
maximum of 100% of the PSUs granted could be earned. The grant date fair value and associated
equity compensation expense was measured using a Monte Carlo simulation model which runs a
probabilistic assessment of the number of units that will be earned based on a projection of our stock
price during the three-year service period. Although certain events may accelerate vesting, earned
PSUs generally vest on the third anniversary of the grant date, and are settled in shares of our
common stock at the three-year anniversary of the grant date. PSU grants made to certain executives
in 2021 have been fully earned.

The following table sets forth PSU activity for the year ended December 31, 2022:

Unvested at December 31, 2021 . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled or Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Unvested at December 31, 2022 . . . . . . . . . . . . . . . . . . . . . .

Weighted-
Average Grant-
Date Fair Value

Number of Units

(in thousands)

$
944
4
$
(1) $

947

20.14
31.76
19.31

20.19

130

The range of assumptions used in the valuation of PSUs granted during 2022 and 2021 were as

follows:

Successor

2022

2021

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Expected volatility(a)
Risk-free interest rate(b)
Dividend yield(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forecast period (in years)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.59% - 2.55%
— %
2 - 3

60.00% 60.00% - 65.00%
0.16% - 0.60%
— %
2 - 3

(a) Expected volatility was calculated using the historic volatility of a peer group due to our limited trading history since our

emergence from bankruptcy. For awards granted after June 2021, expected volatility included the historic volatility of our
stock, excluding our first two trading months.

(b) Based on the U.S. Treasury yield for a two- or three-year term at the grant date.
(c) A dividend adjusted stock price (assumed reinvestment of dividends during the performance period) was used.

Compensation expense is recognized on a straight-line basis over the requisite service periods
adjusted for actual forfeitures, if any. Events that accelerate the vesting of an award have no effect on
the requisite service period until such an event becomes probable.

As of December 31, 2022, the unrecognized compensation expense for our unvested PSUs was
approximately $7 million and is expected to be recognized over a weighted-average remaining service
period of approximately one year.

Long-Term Cash Incentive Awards

On June 30, 2022 and 2021, we granted performance cash-settled awards to approximately 500
non-executive employees where half of the award is variable with payouts ranging from 75% to 150%
of the grant value. The variable portion of the award is determined based upon the attainment of
specified 60-trading day volume weighted average prices for shares of our common stock preceding
each vesting date. These awards vest ratably over a three-year service period, with one third of the
grants vesting on each of the first three anniversaries of the grant date. The fair value of the awards is
adjusted on a quarterly basis for the cumulative change in the value determined using a Monte Carlo
simulation model which runs a probabilistic assessment of our stock price for each of the three-year
service periods.

The assumptions used in the valuation of our cash awards as of December 31, 2022 were as

follows:

2022 Awards 2021 Awards

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility(a)
Risk-free interest rate(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forecast period (in years) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

55%
4.32%
— %
2.5

46%
4.57%
— %
1.5

(a) Expected volatility for the 2022 awards was calculated using the historic volatility of a peer group which included our stock,
excluding our first two trading months. Expected volatility for the 2021 awards was calculated using the historical volatility of
our stock.

(b) Based on the U.S. Treasury yield for the 2.5 and 1.5 year remaining terms.
(c) A dividend adjusted stock price (assumed reinvestment of dividends during the performance period) was used.

As of December 31, 2022, the unrecognized compensation expense for all of our unvested cash-
settled awards was $16 million and is expected to be recognized over a weighted-average remaining
service period of approximately 2.3 years. The value of awards forfeited during the year ended
December 31, 2022 was approximately $2 million.

131

Predecessor Stock-Based Compensation Plan

As a result of our bankruptcy as described in Note 15 Chapter 11 Proceedings, the outstanding

stock-based awards granted under our Amended and Restated California Resources Corporation
Long-Term Incentive Plan (Amended LTIP) were cancelled on our Effective Date.

In 2019, our stockholders approved the Amended LTIP, which provided for the issuance of stock,

incentive and non-qualified stock options, restricted stock awards, restricted stock units, stock
appreciation rights, stock bonuses, performance-based awards and other awards to executives,
employees and non-employee directors. Shares of our common stock were permitted to be withheld by
us in satisfaction of tax withholding obligations arising upon the exercise of stock options or the vesting
of restricted stock units. Further, shares of our common stock were permitted to be withheld by us in
payment of the exercise price of employee stock options, which also counted against the authorized
shares specified above. The maximum number of authorized shares of our common stock that were
available for issuance pursuant to the Amended LTIP was 7,275,000 shares.

In the second quarter of 2020, our then Board of Directors approved the following changes to
awards previously granted during 2020: (i) the previously established target amounts under the 2020
variable compensation programs remained unchanged, but any unvested amounts under such
programs were revised to only be eligible for cash settlement, and (ii) as a condition to receiving any
award under our 2020 variable compensation programs, participants waived participation in our 2020
annual incentive program and forfeited all stock-based compensation awards previously granted in
2020. At the time of the amendments, there were no changes to any stock-based compensation
awards granted prior to February 2020; however, as a result of our bankruptcy, the outstanding stock-
based awards under our Amended LTIP were cancelled on our Effective Date.

The cancellation of the stock-based compensation awards granted under the Amended LTIP prior

to 2020 resulted in the recognition of all previously unrecognized compensation expense for equity-
based awards under the Amended LTIP and the elimination of the liability related to cash-based
awards under the Amended LTIP.

Restricted Stock Units

As part of the Amended LTIP, executives and other employees were granted restricted stock units
(RSUs). RSUs were service based and, depending on the terms of the awards, were settled in cash or
stock at the time of vesting. The awards either (i) vested ratably over three years, with one third of the
granted units becoming vested on the day before each of the first three anniversaries of the applicable
date of grant, or (ii) cliff vested upon the third anniversary of the applicable date of grant. Our RSUs
had nonforfeitable dividend rights, and any dividends or dividend equivalents declared during the
vesting period were paid as declared.

For cash- and stock-settled RSUs, compensation value was initially measured on the date of grant

using the quoted market price of our common stock. Compensation expense for cash-settled RSUs
was adjusted on a monthly basis for the cumulative change in the value of the underlying stock. For the
Predecessor period of 2020, the weighted-average fair value of each stock-settled RSU granted was
$6.20. Compensation expense for the stock-settled RSUs were recognized on a straight-line basis over
the requisite service periods, adjusted for actual forfeitures. All outstanding RSUs were cancelled for
no consideration as a result of our emergence from bankruptcy.

132

Performance Stock Units

Our performance stock units (PSUs) were restricted stock unit awards with performance targets
with payouts ranging from 0% to 200% of the target award. Up to the target amount of the PSUs were
eligible to be settled in cash or stock, and any amount of the PSUs earned in excess of the target
amounts of such PSUs were to be settled in cash. These awards accrued dividend equivalents as
dividends are declared during the vesting period, which were paid upon certification for the number of
earned PSUs. Compensation expense was adjusted quarterly, on a cumulative basis, for any changes
in the number of share equivalents expected to be paid based on the relevant performance criteria. For
the Predecessor period of 2020, the weighted-average fair value of each stock-settled PSU granted
was $6.20. All outstanding PSUs were cancelled for no consideration as a result of our emergence
from bankruptcy.

Stock Options

We granted stock options to certain executives under our Amended LTIP. These options permitted
the purchase of Predecessor common stock at exercise prices no less than the fair market value of the
stock on the date the options were granted, with the majority of options being granted at 10% above
fair market value. The options had terms of seven years and vested ratably over three years, with one
third of the granted options becoming exercisable on the day before each of the first three
anniversaries of the applicable date of grant, subject to certain restrictions including continued
employment. For the Predecessor period of 2020, the weighted-average fair value of each option
granted was $6.82. All outstanding stock options were cancelled for no consideration as a result of our
emergence from bankruptcy.

Employee Stock Purchase Plan

Successor Employee Stock Purchase Plan

In May 2022, our shareholders approved a new California Resources Corporation Employee Stock

Purchase Plan (ESPP), which took effect in July 2022. The ESPP provides our employees with the
ability to purchase shares of our common stock at a price equal to 85% of the closing price of a share
of our common stock as of the first or last day of each fiscal quarter, whichever amount is less. The
maximum number of shares of our common stock which may be issued pursuant to the ESPP is
subject to certain annual limits and has a cumulative limit of 1,250,000 shares.

As of December 31, 2022, 16,480 shares were issued under our ESPP.

Predecessor Employee Stock Purchase Plan

On May 26, 2020, our California Resources Corporation 2014 Employee Stock Purchase Plan was

terminated by our then Board of Directors. No additional Predecessor shares were issued under the
plan after March 31, 2020.

NOTE 11 STOCKHOLDERS’ EQUITY

As a result of our bankruptcy as described in Note 15 Chapter 11 Proceedings, all of our

Predecessor common and preferred stock, including contracts on our equity were cancelled on the
Effective Date pursuant to the Plan and 83,319,660 shares of new common stock were issued at
emergence.

133

The following is a summary of changes in our common shares outstanding:

Balance, December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares issued for warrant exercises . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares issued under stock-based compensation arrangements . . . . . . . . . . . .
Treasury stock - shares repurchased . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Balance, December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Shares issued for warrant exercises . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares issued under ESPP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock - shares repurchased . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Balance, December 31, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Share Repurchase Program

Common Shares
Outstanding

83,319,660
51,377
18,173
(4,089,988)

79,299,222

312
16,480
(7,366,272)

71,949,742

Our Board of Directors has authorized a Share Repurchase Program to acquire up to $850 million
of our common stock through December 31, 2023. 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:

Year ended December 31, 2021 . . .
Year ended December 31, 2022 . . .

Total Number of
Shares Purchased
(number of shares)
4,089,988
7,366,272

Dollar Value of
Shares Purchased
(in millions)
$148
$313

Average Price Paid
per Share
($ per share)
$36.08
$42.47

Total . . . . . . . . . . . . . . . . . . . . . . . . . .

11,456,260

$461

$40.19

See Note 17 Subsequent Events for more or information on an increase and extension to our Share

Repurchase Program.

Dividends

Our Board of Directors declared a cash dividend of $0.17 per share of common stock for the fourth

quarter of 2021 and each of the first three quarters of 2022. On November 2, 2022, our Board of
Directors approved an increase in our dividend policy to an expected total annual dividend of $1.13 per
share. Dividends are payable to shareholders in quarterly increments, subject to the quarterly approval
of our Board of Directors. Our Board of Directors approved a quarterly cash dividend on November 2,
2022 in the amount of $0.2825 per share of common stock. For the years ended December 31, 2022
and 2021, we paid $59 million and $14 million in dividends, respectively. There were no cash dividends
declared in the Predecessor or Successor period of 2020.

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. See Note 17 Subsequent Events for information on future cash dividends.

134

Noncontrolling Interests

BSP JV

Our development joint venture with Benefit Street Partners (BSP JV) contemplated that BSP
contributed funds to the development of our oil and natural gas properties in exchange for preferred
interests in the BSP JV. In September 2021, BSP’s preferred interest was automatically redeemed in full
under the terms of the joint venture agreement. Prior to the redemption, we made aggregate distributions
to BSP of $50 million in 2021 which reduced noncontrolling interest on our consolidated balance sheet
and was reported as a financing cash outflow on our consolidated statement of cash flows.

BSP’s preferred interest was reported in equity on our consolidated balance sheets and BSP’s
share of net income (loss) was reported in net income attributable to noncontrolling interests in our
consolidated statements of operations for all periods prior to redemption. Upon redemption, we
reallocated the remaining balance of $7 million in noncontrolling interest and increased our additional
paid-in capital by the same amount.

Ares JV

See Note 15 Chapter 11 Proceedings for information on our Ares JV and Settlement Agreement.

Warrants

On the Effective Date, we issued warrants exercisable for an aggregate 4,384,182 shares of
Successor common stock. The warrants are exercisable at an exercise price of $36 per share until
October 2024. The Warrant Agreement contains customary anti-dilution adjustments in the event of
any stock split, reverse stock split, stock dividend, equity awards under our Management Incentive
Plan or other distributions. The warrant holder may elect, in its sole discretion, to pay cash or to
exercise on a cashless basis, pursuant to which the holder will not be required to pay cash for shares
of common stock upon exercise of the warrant but will instead receive fewer shares. See Note 16
Fresh Start Accounting for additional information.

As of December 31, 2022, we had outstanding warrants exercisable into 4,295,434 shares of our

common stock.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) consists of unrealized gains (losses) associated

with our pension and postretirement benefit plans. The components of Accumulated Other
Comprehensive Income (Loss) at December 31, 2022 and 2021 consisted of the following:

Total
(in millions)

December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

Other comprehensive income before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

December 31, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

(8)

80
—

13
(4)

135

The elimination of Predecessor equity balances as part of fresh start accounting resulted in a
reclassification of $23 million of accumulated other comprehensive loss to additional paid-in capital
upon emergence from bankruptcy. See Note 16 Fresh Start Accounting for additional information.

NOTE 12 EARNINGS PER SHARE

Basic and diluted earnings per share (EPS) were calculated using the treasury stock method for the
Successor periods and the two-class method, which is required when there are participating securities,
for the Predecessor periods. Certain of our restricted and performance stock unit awards outstanding
prior to our emergence from bankruptcy were considered participating securities because they had
non-forfeitable dividend rights at the same rate as our pre-emergence common stock. Our restricted
and performance stock unit awards granted subsequent to our emergence from bankruptcy, as
described in Note 10 Stock-Based Compensation, are not considered participating securities since the
dividend rights on unvested shares are forfeitable.

Under the two-class method, undistributed earnings allocated to participating securities are
subtracted from net income attributable to common stock in determining net income available to
common stockholders. In loss periods, no allocation is made to participating securities because
participating securities do not share in losses.

For basic EPS, the weighted-average number of common shares outstanding excludes underlying

shares related to equity-settled awards and warrants. For diluted EPS, the basic shares outstanding
are adjusted by adding potential common shares, if dilutive. Under the treasury stock method, we
assume that proceeds from the exercise of options, warrants and similar instruments are used to
purchase common stock at average market price of our stock each period. For PSUs, we use the
60-trading day volume weighted-average prices of our common stock to determine the percentage
earned for each period and the number of potential common shares included in diluted EPS. An
insignificant number of potential common shares were not earned, and therefore were not treated as
issued in our diluted EPS calculation for the year ended December 31, 2022.

136

The following table presents the calculation of basic and diluted EPS.

Year ended
December 31,
2022

Successor
Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

Predecessor

January 1, 2020 -
October 31, 2020

(in millions, except per share
amounts)
Numerator for Basic and
Diluted EPS

Net income (loss)
. . . . . . . . .
Less: Net income attributable
to noncontrolling interests . . .

Net income (loss) attributable
to common stock . . . . . . . . . .
Less: Net income allocated
to participating securities . . .
Modification of noncontrolling
interest(a)
. . . . . . . . . . . . . . . .

524

625 $

(125)

—

524

—

(13)

612

—

612

(123)

—

1,996

(107)

1,889

(22)

138

Net (loss) income available
to common stockholders . . . .

524

$ (123)

2,005

Denominator for Basic EPS

Weighted-average common
shares . . . . . . . . . . . . . . . . . .

Potential dilutive common
shares:

Restricted Stock Units . . . .
Performance Stock
Units . . . . . . . . . . . . . . . . . .
Warrants . . . . . . . . . . . . . . .

Denominator for Diluted
Earnings per Share

Weighted-average shares -
diluted . . . . . . . . . . . . . . . . . . .

EPS

75.5

82.0

83.3

49.4

0.7

0.7
0.7

0.5

0.5
—

—

—
—

0.2

—
—

77.6

83.0

83.3

49.6

Basic . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . .

40.59
40.42
(a) Modification of noncontrolling interest relates to the deemed redemption of ECR’s noncontrolling interest in the Ares JV in the
third quarter of 2020. For more information on the Ares JV and the Settlement Agreement, see Note 15 Chapter 11 Proceedings.

7.46 $
7.37 $

(1.48)
(1.48)

6.94
6.75

$
$

137

The following table presents potentially dilutive weighted-average common shares which were

excluded from the denominator for diluted earnings per share:

Year ended
December 31,
2022

Successor
Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

Predecessor

January 1, 2020 -
October 31, 2020

(in millions)
Shares issuable upon exercise
of warrants which were issued
at emergence from
bankruptcy . . . . . . . . . . . . . . . . .
Shares issuable upon exercise
of warrants in connection with
our Alpine JV . . . . . . . . . . . . . . .
Shares issuable upon settlement
of RSUs . . . . . . . . . . . . . . . . . . . .
Shares issuable upon
settlement of PSUs . . . . . . . . . .
Shares issuable upon exercise
of stock options . . . . . . . . . . . . .

Total antidilutive shares . . . . .

—

4.4

—

4.4

—

4.4

—

1.3

0.2

0.8

1.7

4.0

NOTE 13 PENSION AND POSTRETIREMENT BENEFIT PLANS

We have various qualified and non-qualified benefit plans for our salaried and union and nonunion

hourly employees.

Defined Contribution Plans

All of our employees are eligible to participate in our tax-qualified, defined contribution retirement

plan that provides for periodic cash contributions by us based on annual cash compensation and
employee deferrals.

Certain salaried employees participate in supplemental plans that restore benefits lost due to

government limitations on qualified plans. As of December 31, 2022 and 2021, we recognized
$24 million and $30 million in other long-term liabilities for these supplemental plans, respectively.

We expensed $18 million in 2022, $19 million in 2021, $4 million in the Successor period of 2020
and $28 million in the Predecessor period of 2020 under the provisions of these defined contribution
and supplemental plans.

Defined Benefit Plans

Participation in defined benefit pension plans sponsored by us is limited. During 2022,

approximately 60 employees accrued benefits under these plans, all of whom were union employees.

Pension costs for the defined benefit pension plans, determined by independent actuarial

valuations, are funded by us through payments to trust funds, which are administered by independent
trustees.

138

Postretirement Benefit Plans

We provide postretirement medical and dental benefits for our eligible former employees and their
dependents. Our former employees are required to make monthly contributions for the coverage, but
the benefits are primarily funded by us as claims are paid during the year.

In 2021, we adopted a postretirement benefit design change, which terminated the employer cost
sharing for post age 65 retiree health benefits effective as of January 1, 2022. Our retiree health care
benefits provided up to age 65 to current and future retirees who meet certain eligibility requirements
were not affected by this change. As a result of this change, our postretirement medical benefit
obligation was remeasured as of September 30, 2021. The remeasurement resulted in a decrease to
the benefit obligation of $65 million with a corresponding increase to accumulated other
comprehensive income. The benefit from the change in plan design will be recognized in our statement
of operations over the average remaining years of future service for active employees as a component
of other non-operating expenses, net.

Obligations and Funded Status of our Defined Benefit Plans

The following table shows the amounts recognized on our balance sheets related to pension and

postretirement benefit plans, as well as plans that we or our subsidiaries sponsor (in millions):

December 31, 2022

December 31, 2021

Pension

Postretirement

Pension

Postretirement

Amounts recognized on the
balance sheet

Other assets . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . .
Other long-term liabilities . . . . . .

Amounts recognized in
accumulated other comprehensive
income (loss), net of tax . . . . . . . . .

2
—
—

— $
(4)
(33)

(37) $

— $
—
(15)

(15) $

—
(4)
(44)

(48)

79 $

(2) $

139

The following table shows the funding status of our pension and post-retirement benefit plans along

with a reconciliation of our benefit obligations and changes in fair value of plan assets (in millions):

Year ended
December 31,
2022

Year ended
December 31,
2021

Pension
Changes in the benefit obligation
Benefit obligation - beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost - benefits earned during the period . . . . . . . . . . . . . . . . .
Interest cost on projected benefit obligation . . . . . . . . . . . . . . . . . . . . .
Actuarial (gain) loss(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Benefit obligation - end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Changes in plan assets
Fair value of plan assets - beginning of year . . . . . . . . . . . . . . . . . . . . . .
Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Fair value of plan assets - end of year . . . . . . . . . . . . . . . . . . . . . . . . . . .

44 $
1
1
(12)
(4)

30 $

29 $
(5)
12
(4)

32 $

47
1
1
2
(7)

32
2
2
(7)

Net benefit asset (liability) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2 $

(15)

Postretirement
Changes in the benefit obligation (in millions)
Benefit obligation - beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost - benefits earned during the period . . . . . . . . . . . . . . . . .
Interest cost on projected benefit obligation . . . . . . . . . . . . . . . . . . . . .
Actuarial (gain) loss(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan amendment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Benefit obligation - end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Changes in plan assets
Fair value of plan assets - beginning of year . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Fair value of plan assets - end of year . . . . . . . . . . . . . . . . . . . . . . . . . . .

49 $
2
1
(12)
(2)
—

38 $

1 $
2
(2)

1 $

129
4
3
(17)
(5)
(65)

—
6
(5)

Net benefit liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(37) $

(48)

(a) The gain reflected in the changes in the pension benefit obligation for the year ended December 31, 2022 was primarily due

to the increase in the discount rate from 2.79% to 5.19% and other valuation assumption changes.

(b) The gain reflected in the changes in the postretirement benefit obligation for the year ended December 31, 2022 was

primarily due to the increase in the discount rate from 2.75% to 5.20%.

140

The following table sets for the details of our obligations and assets related to our defined benefit

pension plans for the years ended December 31:

(in millions)
Projected benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accumulated benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Fair value of plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

30 $
27 $
32 $

44
39
29

2022

2021

Components of Net Periodic Benefit Cost

We record the service cost component of net periodic pension cost with other employee

compensation and all other components, including settlement costs, are reported as other non-operating
income (expenses), net on our consolidated statements of operations. The following table set forth the
components of our net periodic pension and postretirement benefit costs (in millions):

Successor

Predecessor

Year ended
December 31,
2022

Year ended
December 31, November 1, 2020 -
December 31, 2020

2021

January 1, 2020 -
October 31, 2020

Pension
Net periodic benefit costs
Service cost - benefits
earned during the
period . . . . . . . . . . . . . . . $
Interest cost on
projected benefit
obligation . . . . . . . . . . . .
Expected return on plan
assets . . . . . . . . . . . . . . .
Amortization of net
actuarial loss . . . . . . . . .
Settlement costs . . . . . .

Net periodic benefit
costs . . . . . . . . . . . . . . . . $

Postretirement
Net periodic benefit costs
Service cost - benefits
earned during the
period . . . . . . . . . . . . . . . $
Interest cost on
projected benefit
obligation . . . . . . . . . . . .
Amortization of prior
service cost credit . . . . .
Amortization of net
actuarial gain/loss . . . . .
Settlement costs . . . . . .

Net periodic benefit
costs . . . . . . . . . . . . . . . . $

1 $

(1)

—
—

(1)

—
—

1 $

—

—
—

—

2 $

(5)

—
—

(1)

—
—

(2) $

141

—

—
—

(1)

1
1

—

—
1

Components of accumulated other comprehensive income (loss) (AOCI) are presented net of tax.

The following table presents the changes in plan assets and benefit obligations recognized in other
comprehensive (loss) income attributable to common stock (in millions):

Successor

Predecessor

Year ended
December 31,
2022

Year ended
December 31,
2021

November 1, 2020 -
December 31,
2020

January 1, 2020 -
October 31, 2020

Pension

Net actuarial gain

(loss) . . . . . . . . . . . . $

Settlement costs . . . .
Amortization of net

actuarial
gain/loss . . . . . . . . .

Total . . . . . . . . . . . . . . . . $

Postretirement

Net actuarial gain

4 $
—

—

4 $

(1) $
—

—

(1) $

(1) $
—

—

(1) $

(loss) . . . . . . . . . . . . $

9 $

17 $

(7) $

Net prior service

credit . . . . . . . . . . . .
Settlement costs . . . .
Amortization of prior

service cost
credit . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . $

—
—

(4)

5 $

65
—

(1)

81 $

—
—

—

(7) $

(1)
1

(2)

—
1

—

(1)

Settlement costs related to our pension and postretirement plans in the Predecessor period of 2020

were associated with early retirements.

The following tables sets forth the valuation assumptions, on a weighted-average basis, used to

determine our benefit obligations and net periodic benefit cost:

Year ended
December 31,
2022

Year ended
December 31,
2021

Pension
Benefit Obligation Assumptions

Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate of compensation increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Net Periodic Benefit Cost Assumptions

Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assumed long-term rate of return on assets . . . . . . . . . . . . . . . . . . .
Rate of compensation increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

5.19%
4.00%

2.79%
5.50%
4.00%

2.79%
4.00%

2.42%
6.25%
4.00%

142

October 1,
2021 -
December 31,
2021

January 1,
2021 -
September 30,
2021

2022

Postretirement(a)
Benefit Obligation Assumptions

Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . .

Net Periodic Benefit Cost Assumptions

Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . .

5.20%

2.75%

2.69%

2.92%

(a) Our plan design change on September 30, 2021 resulted in a remeasurement of our postretirement benefit obligations.

For pension plans and postretirement benefit plans that we or our subsidiaries sponsor, we based
the discount rate on the FTSE Above Median yield curve in 2022 and the Aon AA Above Median yield
curve in 2021. The weighted-average rate of increase in future compensation levels is consistent with
our past and anticipated future compensation increases for employees participating in pension plans
that determine benefits using compensation. The assumed long-term rate of return on assets is
estimated with regard to current market factors but within the context of historical returns for the asset
mix that exists at year end.

In 2022 and 2021, we used the Society of Actuaries Pri-2012 mortality assumptions reflecting the
MP-2021 scale which plan sponsors in the U.S. use in the actuarial valuations that determine a plan
sponsor’s pension and postretirement obligations.

The postretirement benefit obligation was determined by application of the terms of medical and
dental benefits, including the effect of established maximums on covered costs, together with relevant
actuarial assumptions and healthcare cost trend rates projected at an assumed U.S. Consumer Price
Index (CPI) increase of 2.52% and 2.57% as of December 31, 2022 and 2021, respectively. Under the
terms of our postretirement plans, participants other than certain union employees pay for all medical
cost increases in excess of increases in the CPI. For those union employees, we projected that, as of
December 31, 2022, health care cost trend rates would be 7.00% in 2023 decreasing until they reach
4.50% in 2033 and remain at 4.50% thereafter. For those union employees, we projected that, as of
December 31, 2021, health care cost trend rates would be 6.00% in 2022 decreasing until they reach
4.50% in 2029 and remain at 4.50% thereafter.

The actuarial assumptions used could change in the near term as a result of changes in expected
future trends and other factors that, depending on the nature of the changes, could cause increases or
decreases in the plan assets and liabilities.

Fair Value of Plan Assets

We employ a total return investment approach that uses a diversified blend of equity and fixed-
income investments to optimize the long-term return of plan assets at a prudent level of risk. Equity
investments were diversified across U.S. and non-U.S. stocks, as well as differing styles and market
capitalizations. Other asset classes, such as private equity and real estate, may have been used with
the goals of enhancing long-term returns and improving portfolio diversification. In 2022 and 2021, the
target allocation of plan assets was 50% and 65% equity securities and 50% and 35% debt securities,
respectively. Investment performance was measured and monitored on an ongoing basis through
quarterly investment portfolio and manager guideline compliance reviews, annual liability
measurements and periodic studies. Our postretirement benefit plan assets of $1 million are invested
in mutual funds (Level 1 on the fair value hierarchy) with target allocations of 40% equities and 60%
debt securities.

143

17
1
4
10

2
3
2

5
2
5
5

The fair values of our pension plan assets by asset category are as follows:

Asset Class
Comingled funds

Fair Value Measurements at
December 31, 2022
Level 3
Level 2

Total

Level 1

(in millions)

Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodities . . . . . . . . . . . . . . . . . . . . . . . .
U.S. equity . . . . . . . . . . . . . . . . . . . . . . . . . .
International equity . . . . . . . . . . . . . . . . . . .

—
—
—
—

Total pension plan assets . . . . . . . . . . . . . . . .

— $

17
1
4
10

—
—
—
—

— $

Asset Class
Cash equivalents . . . . . . . . . . . . . . . . . . . . . . .
Commingled funds

Fixed income . . . . . . . . . . . . . . . . . . . . . . . .
U.S. equity . . . . . . . . . . . . . . . . . . . . . . . . . .
International equity . . . . . . . . . . . . . . . . . . .

Mutual funds

Bond funds . . . . . . . . . . . . . . . . . . . . . . . . . .
Value funds . . . . . . . . . . . . . . . . . . . . . . . . .
Growth funds . . . . . . . . . . . . . . . . . . . . . . . .
Guaranteed deposit account . . . . . . . . . . . . . .

Total pension plan assets . . . . . . . . . . . . . . . .

Expected Contributions and Benefit Payments

Fair Value Measurements at
December 31, 2021
Level 3
Level 2

Total

Level 1

(in millions)
— $

— $

—
—
—

5
2
5
—

2
3
2

—
—
—
—

—
—
—

—
—
—
5

In 2023, we do not expect to contribute to our pension plans and expect to contribute $5 million to
our postretirement benefit plan. Estimated future undiscounted benefit payments by the plans, which
reflect expected future service, as appropriate, are as follows:

Pension
Benefits

Postretirement
Benefits

For the years ended December 31,
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2028 to 2032 Payouts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

$
$
$
$
$
$

(in millions)
7
2
2
2
2
10

$
$
$
$
$
$

5
4
4
3
3
12

NOTE 14 REVENUE

Revenue from customers is recognized when obligations under the terms of a contract are satisfied.

See Note 1 Nature of Business, Summary of Significant Accounting Policies and Other for
disaggregated revenue by commodity type.

144

Commodity Sales Contracts

We consider our performance obligations to be satisfied upon delivery (and transfer of control) of

the commodity. In certain instances, transportation and processing fees are incurred by us prior to
delivery to customers. We record these transportation and processing fees as transportation costs on
our consolidated statements of operations.

Our contracts with customers are generally less than a year and based on index prices. We
recognize revenue in the amount that we expect to receive once we are able to adequately estimate
the consideration (i.e., when market prices are known). Our contracts with customers typically require
payment within 30 days following the month of delivery.

Electricity

The electrical output of our Elk Hills power plant that is not used in our operations is sold to the
wholesale power market and a utility under a power purchase and sales agreement (PPA) through
December 2023, which includes a monthly capacity payment plus a variable payment based on the
quantity of power purchased each month. Revenue is recognized when obligations under the terms of
a contract are satisfied; generally, this occurs upon delivery of the electricity. Revenue is measured as
the amount of consideration we expect to receive based on the average index or California
Independent System Operator (CAISO) market pricing with payment due the month following delivery.
Payments under our PPA are settled monthly. We consider our performance obligations to be satisfied
upon delivery of electricity or as the contracted amount of energy is made available to the customer in
the case of capacity payments.

Sales of Purchased Natural Gas

To transport our natural gas as well as third-party volumes, we have entered into firm pipeline

commitments. In addition, we may from time-to-time enter into natural gas purchase and sale
agreements with third parties to take advantage of market dislocations. We report sales of purchased
natural gas in total operating revenues and associated purchased natural gas expense related to our
trading activities in total operating expenses on our consolidated statements of operations. We
consider our performance obligations to be satisfied upon transfer of control of the commodity.

NOTE 15 CHAPTER 11 PROCEEDINGS

The commencement of the Chapter 11 Cases, as described in Note 1 Nature of Business,

Summary of Significant Accounting Policies and Other, constituted an event of default that accelerated
our obligations under the following agreements: (i) Credit Agreement, dated as of September 24, 2014,
among JPMorgan Chase Bank, N.A., as administrative agent, and the lenders that are party thereto
(2014 Revolving Credit Facility), (ii) Credit Agreement, dated as of August 12, 2016, among The Bank
of New York Mellon Trust Company, N.A., as collateral and administrative agent, and the lenders that
are party thereto (2016 Credit Agreement), (iii) Credit Agreement, dated as of November 17, 2017,
among The Bank of America Mellon Trust Company, N.A., as administrative agent, and the lenders
that are party thereto (2017 Credit Agreement), and (iv) the indentures governing our 8% Senior
Secured Second Lien Notes due 2022 (Second Lien Notes), 5.5% Senior Notes due 2021 (2021
Notes) and 6% Senior Notes due 2024 (2024 Notes). This resulted in the automatic and immediate
acceleration of all of our outstanding pre-petition long-term debt. Any efforts to enforce payment
obligations related to the acceleration of our long-term debt were automatically stayed by the
commencement of our Chapter 11 Cases, and the creditors’ rights of enforcement were subject to the
applicable provisions of the Bankruptcy Code.

145

Upon the Effective Date, the balances of the 2016 Credit Agreement, 2017 Credit Agreement,
Second Lien Notes, 2021 Notes and 2024 Notes were cancelled pursuant to the terms of the Plan,
resulting in a gain of approximately $4 billion included in “Reorganization items, net” on our
consolidated statement of operations for the period ended October 31, 2020. Our 2014 Revolving
Credit Facility was repaid in full with proceeds from our debtor-in-possession facilities described below
and terminated.

Debtor-in-Possession Credit Agreements

On July 23, 2020, we entered into a Senior Secured Superpriority DIP Credit Agreement with JP

Morgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement), which
provided for the senior DIP facility in an aggregate principal amount of up to $483 million (Senior DIP
Facility). The Senior DIP Facility included a $250 million revolving facility which was primarily used by
us to (i) fund working capital needs, capital expenditures and additional letters of credit during the
pendency of the Chapter 11 Cases and (ii) pay certain costs, fees and expenses related to the
Chapter 11 Cases and the Senior DIP Facility. Following a hearing, the Bankruptcy Court entered a
final order on August 14, 2020, which approved the Senior DIP Facility on a final basis. The Senior DIP
Facility also included (i) a $150 million letter of credit facility which was used to redeem letters of credit
outstanding under the 2014 Revolving Credit Facility as issued under the Senior DIP Facility, and (ii)
$83 million of term loan borrowings which were used to repay a portion of the 2014 Revolving Credit
Facility. The Senior DIP Facility allowed for the issuance of an additional $35 million of letters of credit.

On July 23, 2020, we entered into a Junior Secured Superpriority DIP Credit Agreement with Alter
Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement), which provided for
a junior DIP facility in an aggregate principal amount of $650 million (Junior DIP Facility and together
with the Senior DIP Facility, the DIP Facilities). The proceeds of the Junior DIP Facility were used to
(i) refinance in full all remaining obligations under the 2014 Revolving Credit Facility and (ii) pay certain
costs, fees and expenses related to the Chapter 11 Cases and the Junior DIP Facility.

The Senior DIP Credit Agreement and Junior DIP Credit Agreement both contained

representations, warranties, covenants and events of default that are customary for DIP facilities of
their type, including certain milestones applicable to the Chapter 11 Cases, compliance with an agreed
budget, hedging on not less than 25% of our share of expected crude oil production for a specified
period, and other customary limitations on additional indebtedness, liens, asset dispositions,
investments, restricted payments and other negative covenants, in each case subject to exceptions.

Borrowings under the Senior DIP Facility bore interest at the London interbank offered rate (LIBOR)

plus 4.5% for LIBOR loans and the alternative base rate (ABR) plus 3.5% for alternative base rate
loans. We also agreed to pay an upfront fee equal to 1.0% on the commitment amount of the Senior
DIP Facility and quarterly commitment fees of 0.5% on the undrawn portion of the Senior DIP Facility.

Borrowings under the Junior DIP Facility bore interest at a rate of LIBOR plus 9.0% for LIBOR loans

and ABR plus 8.0% for alternate base rate loans. We also agreed to pay an upfront fee equal to 1.0%
of the commitment amount funded on the closing date and a fronting fee to a fronting lender.

Certain of our subsidiaries, including each of the debtors in the Chapter 11 Cases, guaranteed all
obligations under the Senior DIP Credit Agreement and Junior DIP Credit Agreement. We also granted
liens on substantially all of our assets, whether now owned or hereafter acquired to secure the
obligations under the Senior DIP Credit Agreement and Junior DIP Credit Agreement.

146

The Senior DIP Facility was repaid in full and terminated on the Effective Date using proceeds
borrowed under our new Revolving Credit Facility discussed in Note 4 Debt. The Junior DIP Facility
was also repaid in full and terminated on the Effective Date using (i) $200 million from the Second Lien
Term Loan discussed in Note 4 Debt and (ii) $450 million from the Subscription Rights Offering
discussed below.

Ares JV Settlement Agreement and Noncontrolling Interest

In February 2018, our wholly-owned subsidiary California Resources Elk Hills, LLC (CREH) entered
into a midstream JV with ECR, a portfolio company of Ares, with respect to the Elk Hills power plant (a
550-megawatt natural gas fired power plant) and a 200 MMcf/day cryogenic gas processing plant.
These assets were held by the joint venture entity, Elk Hills Power, LLC (Ares JV or Elk Hills Power),
and each of CREH and ECR held an equity interest in this entity. Our consolidated statements of
operations for the Predecessor reflect the operations of the Ares JV, with ECR’s share of net income
(loss) reported in net income attributable to noncontrolling interests. Distributions to ECR reduced the
carrying amount of noncontrolling interests on our consolidated balance sheets and are reported as a
financing cash outflow for the Predecessor on our consolidated statements of cashflows. ECR’s
redeemable noncontrolling interests were reported in mezzanine equity due to an embedded optional
redemption feature.

Prior to our Effective Date, we held 50% of the Class A common interest and 95.25% of the Class C

common interest in the Ares JV. ECR held 50% of the Class A common interest, 100% of the Class B
preferred interest and 4.75% of the Class C common interest. The Ares JV was required to distribute
each month its excess cash flow over its working capital requirements first to the Class B holders and
then to the Class C common interests, on a pro-rata basis.

We entered into a Settlement Agreement with ECR and Ares which, among other things, granted us
the right (Conversion Right) to acquire all (but not less than all) of the equity interests of Elk Hills Power
owned by ECR in exchange for the EHP Notes, 17.3 million shares of common stock and
approximately $2 million in cash. The Conversion Right was exercised on the Effective Date. See Note
4 Debt for more information on the EHP Notes.

Although certain provisions in the Settlement Agreement were not effective until certain conditions
were met, such as the Bankruptcy Court entering a final order, we determined that the amended terms
were substantively different such that the existing Class A common, Class B preferred and Class C
common member interests held by ECR were treated as redeemed in exchange for new member
interests issued at fair value in the third quarter of 2020. The estimated fair value of the new member
interests was lower than the carrying value of the existing member interests by $138 million. In
accordance with GAAP, the modification of noncontrolling interest was recorded to additional paid-in
capital and was included in our earnings per share calculations. See Note 12 Earnings per Share for
adjustments to net income (loss) attributable to common stock of the Predecessor which includes a
modification of noncontrolling interest.

We exercised the Conversion Right on the Effective Date and issued the EHP Notes in the
aggregate principal amount of $300 million, new common stock comprising approximately 20.8%
(subject to dilution) of our outstanding common stock at that time and approximately $2 million in cash
(Conversion). Upon the Conversion, Elk Hills Power became our indirect wholly-owned subsidiary, and
Ares and its affiliates ceased to have any direct or indirect interest in Elk Hills Power. In connection
with the Conversion, Elk Hills Power’s limited liability company agreement was amended and restated.

147

The following table presents the changes in noncontrolling interests for our consolidated joint

ventures during the Predecessor period ended October 31, 2020, including both our BSP JV and Ares
JV.

Balance, December 31, 2019 . . . . . . . . . $
Net income (loss) attributable to
noncontrolling interests . . . . . . . . . . . . . . .
Distributions to noncontrolling interest
holders . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Modification of noncontrolling interest . . .
Acquisition of noncontrolling interest . . . .
Fair value adjustment of noncontrolling
interest in fresh start accounting . . . . . . .

— $

(3)
—
—

—

Balance, October 31, 2020 . . . . . . . . . . . $

— $

(34)
—
—

Equity Attributable to Noncontrolling
Interests
BSP JV

Ares JV

Mezzanine Equity -
Redeemable
Noncontrolling Interest
Ares JV

Total

802

Total
(in millions)
93
$

(37)
—
—

(67)
(138)
(691)

—

— $

(67)
(138)
(691)

—

In connection with the Conversion, on the Effective Date, we entered into a Sponsor Support
Agreement dated the Effective Date (Support Agreement) pursuant to which, among other things, the
parties agreed that Elk Hills Power will be our primary provider of electricity to, and will be the primary
processor of our natural gas produced from, the Elk Hills field, which is consistent with our current
practice.

On the Effective Date, in connection with the Conversion, we terminated: (a) the Commercial
Agreement, dated as of February 7, 2018, by and between Elk Hills Power and CREH and (b) the
Master Services Agreement, dated as of February 7, 2018, by and between Elk Hills Power and
CREH.

Rights Offering and Backstop

Pursuant to the Plan, we issued subscription rights to holders of our 2017 Credit Agreement, 2016

Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes (Rights Offering). These
subscription rights entitled holders to purchase up to $450 million of newly issued shares of common
stock at $13 per share upon our emergence from bankruptcy. Certain holders of our pre-emergence
indebtedness agreed to backstop the Rights Offering and purchase additional shares in the event the
Rights Offering was not fully subscribed in exchange for a premium. The Rights Offering closed on the
Effective Date and we issued 38.1 million shares of common stock pursuant to the Rights Offering at
that time, including 3.5 million common shares issued to the backstop parties as a premium.

Emergence

The following transactions occurred on October 27, 2020, the effective date of the Plan, where we
issued an aggregate of 83.3 million shares of new common stock, reserved 4.4 million shares for future
issuance upon exercise of the warrants described in Note 11 Stockholders’ Equity and reserved
9.3 million shares for future issuance under our management incentive plan described in Note 10
Stock-Based Compensation:

• We acquired all of the member interests in the Ares JV held by ECR in exchange for the
EHP Notes, 17.3 million shares of new common stock and approximately $2 million in
cash;

148

• Holders of secured claims under the 2017 Credit Agreement received 22.7 million shares
of new common stock in exchange for those claims, and holders of deficiency claims
under the 2017 Credit Agreement and all outstanding obligations under the 2016 Credit
Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received 4.4 million shares
of new common stock in exchange for those claims;

•

In connection with the Subscription Rights and Backstop Commitment Agreement,
34.6 million shares of new common stock were issued in exchange for $446 million (net
of a $4 million allocation adjustment credit paid to certain backstop parties), the gross
proceeds of which were used to pay down our Junior DIP Facility;

• We issued 3.5 million shares as consideration for the backstop commitment premium;

and

• We issued an aggregate of 821,000 shares to the lenders under our Junior DIP Facility

as an exit fee.

All existing equity interests of the Predecessor, including contracts on equity, were cancelled and

their holders received no recovery.

As a condition to our emergence, we repaid the outstanding balance of our debtor-in-possession

financing with proceeds from our equity offering, Second Lien Term Loan and our new Revolving
Credit Facility. For more information on our post-emergence indebtedness, see Note 4 Debt.

On October 27, 2020, all but one of our existing directors resigned and seven new non-employee

directors were appointed to our Board of Directors (Board) in connection with our emergence from
bankruptcy. In addition, our former Chief Executive Officer and director Todd A. Stevens departed on
December 31, 2020.

NOTE 16 FRESH START ACCOUNTING

Fresh Start Accounting

We adopted fresh start accounting upon emergence from bankruptcy because (1) the holders of
existing voting shares prior to emergence received less than 50% of our new voting shares following
our emergence from bankruptcy and (2) the reorganization value of our assets immediately prior to the
confirmation of the Plan was less than the post-petition liabilities and allowed claims, which were
included in liabilities subject to compromise as of our emergence date.

For financial reporting purposes, fresh start accounting was applied as of October 31, 2020, an
accounting convenience date, to coincide with the timing our normal month-end close process. We
evaluated and concluded that events between October 28, 2020 and October 31, 2020 were not
significant and the use of an accounting convenience date was appropriate.

Under fresh start accounting, the reorganization value of the emerging entity was assigned to
individual assets and liabilities based on their estimated relative fair values. Reorganization value
represents the fair value of our total assets prior to the consideration of liabilities and is intended to
approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The
reorganization value was derived from our enterprise value, which was the estimated fair value of our
long-term debt, asset retirement obligations and shareholder’s equity at emergence. In support of the
Plan, our enterprise value was estimated and approved by the Bankruptcy Court to be in the range of
$2.2 billion to $2.8 billion.

149

This valuation analysis was prepared using reserve information, development schedules, other
financial information and financial projections, and applying standard valuation techniques, including
net asset value analysis, precedent transactions analyses and comparable public company analyses.
We engaged third-party valuation advisors to assist in determining the value of our Elk Hills power
plant, cryogenic gas processing plant, certain real estate and warrants. Using these valuations along
with our own internal estimates and assumptions for the value of our proved oil and natural gas
reserves, we estimated our enterprise value to be $2.5 billion for financial reporting purposes.

The following is a summary of our valuation approaches and assumptions for significant
non-current assets and liabilities, which excludes our working capital where our carrying value
approximated fair value.

Property, Plant and Equipment

Our principal assets are our oil and natural gas properties. In valuing our proved oil and natural gas

properties we used an income approach. Our estimated future revenue, operating costs and
development plans were developed internally by our reserve engineers. We applied a discount rate
using a market-participant weighted average cost of capital which utilized a blended expected cost of
debt and expected returns on equity for similar industry participants. We used a risk-adjusted discount
rate for our proved undeveloped locations only. We estimated futures prices to calculate future
revenue, as reported on the ICE Brent for oil and NGLs and NYMEX Henry Hub for natural gas as of
October 31, 2020, adjusted for pricing differentials and without giving effect to derivative transactions.
Operating costs and realized prices for periods after the forward price curve becomes illiquid were
adjusted for inflation. No value was ascribed to unproved locations.

The fair value of our Elk Hills power plant, cryogenic gas processing facility (CGP-1) and
commercial building in Bakersfield were estimated using a cost approach. The cost approach
estimates fair value by considering the amount required to construct or purchase a new asset of equal
utility at current prices, with adjustments for asset function, age, physical deterioration and
obsolescence. We also considered the history of major capital expenditures.

We internally valued our surface acreage based on recent market data.

Right of Use Assets and Lease Liabilities

The fair value of ROU assets and associated lease liabilities were measured at the present value of

the remaining fixed minimum lease payments as if the leases were new leases at emergence. We
used our incremental borrowing rate as the discount rate in determining the present value of the
remaining lease payments. Based upon the corresponding lease term, our incremental borrowing rates
ranged from 4% to 5%.

Pension and Postretirement Benefit Plans

The valuations of our pension liabilities and postretirement benefit obligations were performed by a

third-party actuary. Valuation assumptions, including discount rates, expected future returns on plan
assets, rates of future salary increases, rates of future increases in medical costs, turnover and
mortality rates were developed in consultation with the third-party actuary based on current market
conditions, current mortality rates and our expectation for future salary increases.

Long-term Debt Obligations

The fair value of our post-emergence long-term debt approximated carrying value based on the

terms of the debt instruments and stated interest rates.

150

Asset Retirement Obligations

The fair value of our asset retirement obligations was estimated using a discounted cash flow

approach for existing idle and currently producing wells and facilities. We estimated an average
plugging and abandonment cost by field based on historical averages. We also factored in our testing
plans related to idle well management and estimated failure rates to determine the timing of the cash
flows. We utilized a credit adjusted risk free rate as our discount rate which was based on our credit
rating and expected cost of borrowing at our emergence date. Our asset retirement obligations were
reduced to our working interest share and factored in cost recovery related to our PSCs.

Warrants

The fair value of the warrants was estimated using a Black-Scholes model, a commonly used
option pricing model. The Black-Scholes was used to estimate the fair value of our warrants with a
stock price equal to book equity value per share, strike price, time to expiration, risk-free rate, equity
volatility, which was based on a peer group of energy companies and dividend yield, which we
estimated to be zero.

Reorganization Value

The following table summarizes our enterprise value upon emergence (in millions):

Fair value of total equity upon emergence . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Fair value of long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Unrestricted cash(a)

Total Enterprise Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

1,345
725
593
(163)

2,500

(a)

Includes $118 million of cash used to temporarily collateralize letters of credit at our emergence date.

The following table reconciles our enterprise value to our reorganization value, or total asset value,

upon emergence (in millions):

Enterprise value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Add: Unrestricted cash(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Add: Current liabilities(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Add: Other long-term liabilities(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Reorganization value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

2,500
163
396
231
(2)

3,288

Includes $118 million of cash used to temporarily collateralize letters of credit.

(a)
(b) Excludes asset retirement obligations of $50 million in current liabilities and $543 million in other long-term liabilities.

151

Consolidated Balance Sheet

The following consolidated balance sheet, with accompanying explanatory notes, illustrates the

effects of the transactions contemplated by the Plan (Reorganization Adjustments) and fair value
adjustments resulting from the adoption of fresh start accounting (Fresh Start Adjustments) as of
October 31, 2020 (in millions):

Predecessor

Reorganization
Adjustments

Fresh Start
Adjustments

Successor

CURRENT ASSETS

Cash . . . . . . . . . . . . . . . . . . . . . . .$
Trade receivables . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . .
. . . . . .
Other current assets, net

Total current assets . . . . . . . . .

PROPERTY, PLANT AND
EQUIPMENT . . . . . . . . . . . . . . . . . . .

Accumulated depreciation,
depletion and amortization . . . . .

Total property, plant and
equipment, net . . . . . . . . . . . . .
OTHER ASSETS . . . . . . . . . . . . . . .

106 $
149
61
104

420

22,918

(18,588)

4,330
77

97 (1) $
—
—
(2) (2)

—

—
—
—
—

—

(20,236) (12)

18,588 (12)

—
18 (3)

(1,648)

(4) (13)

TOTAL ASSETS . . . . . . . . . . . . . . . .$

4,827 $

113

(1,652)

CURRENT LIABILITIES

Debtor-in-possession financing . .
Accounts payable . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . .
Total current liabilities . . . . . . . .
LONG-TERM DEBT, NET . . . . . . . .
OTHER LONG-TERM LIABILITIES
LIABILITIES SUBJECT TO
COMPROMISE . . . . . . . . . . . . . . . . .
MEZZANINE EQUITY

Redeemable noncontrolling
interests . . . . . . . . . . . . . . . . . . . .

EQUITY

Predecessor preferred stock . . . . .
Predecessor common stock . . . . . .
Predecessor additional paid-in
. . . . . . . . . . . . . . . . . . . . . . .
capital
Successor preferred stock . . . . . . .
Successor common stock . . . . . . .
Successor additional paid-in
capital
. . . . . . . . . . . . . . . . . . . . . . .
Successor warrants . . . . . . . . . . . .
Accumulated deficit . . . . . . . . . . . . .
Accumulated other comprehensive
loss . . . . . . . . . . . . . . . . . . . . . . . . . .

Total equity attributable to
common stock . . . . . . . . . . . . . . .

Equity attributable to
noncontrolling interests . . . . . . . . .
Total equity . . . . . . . . . . . . . . . . .
TOTAL LIABILITIES AND EQUITY $

(733) (4)
—
(16) (5)

(749)
723 (6)

—

(4,516) (7)

(691) (8)

—
—

(5,149) (9)

1 (10)

1,253 (10)
15 (10)
9,226 (11)

—

5,346

—
5,346
113

733
215
233
1,181
—
725

4,516

691

—
—

5,149
—
—

—
—
(7,481)

(23)

(2,355)

69
(2,286)
4,827 $

152

—
—
14 (14)
14
—
49 (15)

—

—
—

—
—
—

—
—
(1,745) (16)

23 (17)

(1,722)

7 (18)

(1,715)
(1,652)

203
149
61
102

515

2,682

—

2,682
91

3,288

—
215
231
446
723
774

—

—
—

—
—
1

1,253
15
—

—

1,269

76
1,345
3,288

Reorganization Adjustments

(1) Net change in cash upon our emergence included the following transactions (in millions):

Proceeds from Revolving Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Proceeds from Subscription Rights and Backstop Commitment, net
. . . . . . . .
Proceeds from Second Lien Term Loan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayment of debtor-in-possession facilities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of legal, professional and other fees . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt issuance costs for the Revolving Credit Facility . . . . . . . . . . . . . . . . . . . . .
Debt issuance costs for the Second Lien Term Loan . . . . . . . . . . . . . . . . . . . . .
Acquisition of noncontrolling interest as part of the Settlement Agreement
. . .
Distribution to noncontrolling interest holder . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of accrued interest and bank fees . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

225
446
200
(733)
(15)
(18)
(2)
(2)
(3)
(1)

Our cash balance of $203 million at October 31, 2020 included $158 million of restricted cash, of
which $118 million was used to temporarily collateralize letters of credit, $22 million was held for
distributions to a JV partner and $18 million was reserved for legal and professional fees related
to our Chapter 11 Cases.

(2) Represents the write-off of unamortized insurance premiums for our directors and officers

policy, which was cancelled as a result of changing the composition of our Board of Directors.

(3) Represents the capitalization of debt issuance costs for our Revolving Credit Facility.

(4) Represents the payoff of $733 million of debtor-in-possession financing including $83 million of
borrowings that were outstanding under our Senior DIP Facility and $650 million of borrowings
that were outstanding under our Junior DIP Facility. Refer to Note 15 Chapter 11 Proceedings
for more information on our debtor-in-possession credit agreements.

(5) Reflects the payment of $15 million for legal, professional and other fees related to our

bankruptcy proceedings upon emergence and $1 million for accrued interest and bank fees.

(6) Our exit financing at emergence included the following:

Revolving Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Second Lien Term Loan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EHP Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Long-term debt (principal amount) . . . . . . . . . . . . . . . . . . . . . . . $

Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

For additional information on our Successor debt, refer to Note 4 Debt.

October 31, 2020
($ in millions)

225
200
300

725
(2)

723

153

(7) Our liabilities subject to compromise at emergence included the following (in millions):

Long-term debt (principal amount):

2017 Credit Agreement
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 Credit Agreement
Second Lien Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest

Total liabilities subject to compromise . . . . . . . . . . . . . . . . . . . . . . . . . . . $

1,300
1,000
1,808
100
144
164

4,516

(8) Represents the acquisition of the noncontrolling interest in our Ares JV. In accordance with the
Settlement Agreement, we exercised a conversion right upon our emergence from bankruptcy,
allowing us to acquire all (but not less than all) of the equity interests in the Ares JV held by
ECR in exchange for the EHP Notes, 17.3 million shares of common stock and approximately
$2 million in cash.

(9) Represents the elimination of Predecessor additional paid-in capital.

(10) Represents the fair value of 83.3 million shares of Successor common stock and Warrants

issued in accordance with the Plan as follows (in millions):

Par value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Additional paid-in capital
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

1
1,253
15

1,269

(11) Represents the decrease in accumulated deficit resulting from reorganization adjustments and

the reclassification from Predecessor additional paid-in capital.

Fresh Start Adjustments

(12) Represents fair value adjustments to property, plant and equipment (PP&E), including the

elimination of Predecessor accumulated depreciation, depletion and amortization.

The fair value of our PP&E at emergence consisted of the following:

Proved oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Facilities and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total PP&E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

2,409
273

2,682

(13) Represents an adjustment to our right of use assets as if our lease agreements were new

leases on our emergence date.

(14) Represents a $20 million fair value adjustment to the current portion of asset retirement

obligations partially offset by a $5 million decrease in our liability for self-insured medical. Also
included are fair value adjustments for our postretirement benefits and a remeasurement of the
current portion of our lease liability.

154

(15) Represents a $36 million fair value adjustment related to the long-term portion of asset
retirement obligations and $8 million related to environmental and other abandonment
obligations. The adjustment also includes $5 million related to remeasuring our long-term lease
liability as if our contracts were new leases.

(16) Represents the elimination of Predecessor accumulated deficit.

(17) Represents the elimination of Predecessor accumulated other comprehensive loss.

(18) Represents a fair value adjustment of the noncontrolling interest in the BSP JV based on

discounted expected future cash flows.

155

NOTE 17 SUBSEQUENT EVENTS

Dividends

Share Repurchase Program

On February 23, 2023 our Board of Directors increased the Share Repurchase Program by

$250 million to $1.1 billion and extended the program through June 30, 2024.

Income Taxes

In February 2023, the original tax treatment of the Lost Hills divestiture was amended. As a result,

we are no longer limited on the realization of the tax loss and will release our $35 million valuation
allowance in the first quarter of 2023. See Note 3 Divestitures and Acquisitions for more information on
our Lost Hills divestiture and Note 9 Income Taxes for more information on our valuation allowance.

Stock-Based Compensation

In February 2023, certain of our executives were granted an aggregate of 329,000 RSUs and

493,000 PSUs. The PSUs cliff vest on either the second or the third anniversary of the grant date. The
RSUs vest ratably over either two or three years, with units vesting on the anniversary date of each
grant, generally subject to continued employment through the applicable vesting dates.

Supplemental Oil and Gas Information (Unaudited)

The following table sets forth our net operating and non-operating interests in quantities of proved

developed and undeveloped reserves of oil (including condensate), NGLs and natural gas and
changes in such quantities. Estimated reserves include our economic interests under PSCs in our
Long Beach operations in the Wilmington field. All of our proved reserves are located within the state of
California.

156

PROVED DEVELOPED AND UNDEVELOPED RESERVES

Balance at December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of previous estimates(c) . . . . . . . . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Balance at December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . .

Revisions of previous estimates(c) . . . . . . . . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Balance at December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . .

Balance at December 31, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . .

PROVED DEVELOPED RESERVES
December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

December 31, 2022(d)

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

PROVED UNDEVELOPED RESERVES
December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

December 31, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Oil(a)
(MMBbl)
483
(164)
—
20
(1)
(25)

313

50
1
4
(3)
(22)

343

(38)
6
11
(8)
(20)

294

357

266

282

251

126

NGLs
(MMBbl)

Natural
Gas
(Bcf)

Total(b)
(MMBoe)
644
(185)
—
25
(2)
(40)

442

73
1
5
(5)
(36)

480

(44)
6
16
(8)
(33)

417

493

382

405

363

654
(86)
—
24
(3)
(62)

527

108
—
6
(7)
(58)

576

(36)
—
26
(1)
(54)

511

543

460

510

458

111

151

52
(7)
—
1
—
(5)

5
—
—
(1)
(4)

—
—
1
—
(4)

(a) Includes proved reserves related to economic arrangements similar to PSCs of 92 MMBbl, 111 MMBbl, 85 MMBbl and

125 MMBbl at December 31, 2022, 2021, 2020 and 2019, respectively.

(b) Natural gas volumes have been converted to Boe based on the equivalence of energy content of six Mcf of natural gas to

one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

economically recoverable reserves in all of our operations, because the extra margin extends their expected lives and
renders more projects economic. Partially offsetting this effect, higher prices decrease our share of proved cost recovery
reserves under arrangements similar to production-sharing contracts at our Long Beach operations in the Wilmington field
because fewer reserves are required to recover costs. Conversely, when prices drop, we experience the opposite effects.
Performance-related revisions can include upward or downward changes to previous proved reserves estimates due to
the evaluation or interpretation of recent geologic, production decline or operating performance data.

(d) Approximately 19% of proved developed oil reserves, 7% of proved developed NGLs reserves, 10% of proved developed
natural gas reserves and, overall, 16% of total proved developed reserves at December 31, 2022 are non-producing. A
majority of our non-producing reserves relate to steamfloods and waterfloods where full production response has not yet
occurred due to the nature of such projects.

157

2022

Revisions of previous estimates – We had net positive price-related revisions of 6 MMBoe primarily

resulting from a higher commodity price environment in 2022 compared to 2021. The price revision
reflects the extended economic lives of our fields, estimated using 2022 SEC pricing. Additionally, we
have experienced higher vendor-related pricing and compensation-related cost increases due to
inflation.

We had 16 MMBoe of net negative performance-related revisions which included negative

performance-related revisions of 31 MMBoe and positive performance-related revisions of 15 MMBoe.
Our negative performance-related revisions primarily were due to wells and incremental waterflood
response that underperformed forecasts and removal of proved undeveloped locations due to
unsuccessful drilling results in certain areas. Our positive performance-related revisions primarily
related to better-than-expected well performance and addition of proved undeveloped locations due to
positive drilling results in certain areas. The majority of these revisions were located in the San Joaquin
and Los Angeles basins.

We had 34 MMBoe of negative revisions to our proved reserves due to the impact of California
regulatory changes and court challenges on our development plans. Of this amount, negative revisions
of 20 MMBoe of proved reserves were due to the uncertainty of the outcome of the referendum and
potential impact of Senate Bill No. 1137. The majority of these volumes are in the LA Basin. Negative
revisions of 14 MMBoe to our proved reserves were due to challenges to Kern County’s ability to issue
well permits in reliance on an existing EIR for CEQA purposes. The volumes affected by these court
challenges are in Kern County. See Part I, Item 1 & 2 Business and Properties, Regulation of the
Industries in Which We Operate, Regulation of Exploration and Production Activities.

Extensions and discoveries – We added 16 MMBoe from extensions and discoveries resulting from

successful drilling and workovers in the San Joaquin and Los Angeles basins.

Acquisitions and Divestitures – We had a reduction of 8 MMBoe which primarily related to our Lost
Hills divestiture. See Note 3 Divestitures and Acquisitions for more information on these transactions.

2021

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

We had 9 MMBoe of net positive performance-related revisions which included positive

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

Extensions and discoveries – We added 5 MMBoe from extensions and discoveries resulting from

successful drilling and workovers in the San Joaquin and Los Angeles basins.

158

Acquisitions and Divestitures – We had a reduction of 11 MMBoe in connection with our Ventura

divestiture and added 6 MMBoe in connection with our acquisition of the working interest in certain
wells from MIRA. See Note 3 Divestitures and Acquisitions for more information on these transactions.

2020

Revisions of previous estimates – We had negative price-related revisions of 72 MMBoe primarily
resulting from a lower commodity price environment in 2020 compared to 2019. The net price revision
reflects the shortened economic lives of our fields, as estimated using 2020 SEC pricing, which for oil
was significantly lower than current prices, partially offset by our lower operating costs.

We had 61 MMBoe of net negative performance-related revisions which included negative

performance-related revisions of 73 MMBoe and positive performance-related revisions of 12 MMBoe.
Our negative performance-related revisions are primarily related to wells that underperformed their
forecasts. A significant factor for this underperformance was a reduction in our capital program in 2020
due to the extremely low commodity price environment and constraints during our bankruptcy process.
This led to higher overall decline rates due to injection curtailments, capacity limitations and reduced
well maintenance. Our positive performance-related revisions of 12 MMBoe primarily related to better-
than-expected well performance.

We removed 52 MMBoe of proved undeveloped reserves, all of which were no longer included in
our development plans because they did not meet internal investment thresholds at lower SEC prices.
The majority of these revisions were located in the San Joaquin and Los Angeles basins.

Extensions and discoveries – We added 25 MMBoe from extensions and discoveries,

approximately half of which resulted from the booking of proved undeveloped reserves in connection
with fresh start accounting. Successful drilling and workovers in the San Joaquin and Los Angeles
basins also contributed to the increase.

CAPITALIZED COSTS

Capitalized costs relating to oil and natural gas producing activities and related accumulated

depreciation, depletion and amortization (DD&A) were as follows:

Successor

December 31,
2022
(in millions)

December 31,
2021
(in millions)

Proved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,972

Total capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depreciation, depletion and amortization . . . . . . . . . . .

2,974
(394)

Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2,580

2,626
8

2,627
(219)

2,408

159

COSTS INCURRED

Costs incurred relating to oil and natural gas activities include capital investments, exploration
(whether expensed or capitalized), acquisitions and asset retirement obligations but exclude corporate
items. The following table summarizes our costs incurred:

Successor

Predecessor

Property acquisition costs
Proved properties(a) . . . . . . $
Unproved properties . . . . .
Exploration costs . . . . . . . . .
Development costs(b) . . . . . .

Costs incurred . . . . . . . . . . $

Year ended
December 31,
2022

Year ended
December 31,
2021
(in millions)

— $
—
4
389

393 $

53 $
—
7
210

270 $

November 1, 2020 -
December 31, 2020

January 1, 2020 -
October 31, 2020

— $
—
1
7

(in millions)

—
—
10
35

(a) Acquisition costs relates to our acquisition of MIRA’s working interests in certain wells in 2021.
(b) Development costs include a $24 million increase in ARO in 2022 (including assets held for sale). Development costs

include a $19 million increase in ARO in 2021. There were no costs incurred for development costs related to ARO in 2020.

RESULTS OF OPERATIONS

Our oil and natural gas producing activities, which exclude items such as asset dispositions, corporate

overhead and interest, were as follows:

Year ended
December 31,
2022

Successor
Year ended
December 31,
2021

Predecessor

November 1, 2020 -
December 31, 2020

January 1, 2020 -
October 31, 2020

(millions)
$ 1,901 $ 57.51 $ 1,729 $ 47.55 $

(millions)

($/Boe)

(millions)

($/Boe)

785

23.75

705

19.39

175

111
—
43
4

1.09

0.64

5.29

3.36
—
1.30
0.12

190

103
—
50
7

0.94

0.68

5.23

2.83
—
1.38
0.19

235 $ 37.49
18.19
114

4
—
8
1

1.12

0.94

4.95

0.64
—
1.28
0.16

($/Boe)

(millions)
$ 1,196 $ 34.98
14.95

511

299

106
1,733
33
10

1.11

0.58

8.75

3.10
50.69
0.97
0.29

Revenues(a)
Operating costs(b)
General and
administrative
expenses
Other operating
expenses(c)
Depreciation, depletion
and amortization
Taxes other than on
income
Asset impairment
Accretion expense
Exploration expenses

Pretax income
Income tax expense(d)

726
(189)

21.96
(5.72)

615
(144)

16.91
(3.96)

64
(18)

10.21
(2.87)

(1,554)
435

(45.46)
12.72

Results of operations

537 $ 16.24 $

471 $ 12.95 $

46 $

7.34

$ (1,119) $ (32.74)

(a) Revenues include oil, natural gas and NGL sales, cash settlements on our commodity derivatives and other revenue

related to our oil and natural gas operations.

(b) Operating costs are the costs incurred in lifting the oil and natural gas to the surface and include gathering, processing,

field storage and insurance on proved properties.

Income taxes are calculated on the basis of a stand-alone tax filing entity. The combined U.S. federal and California
statutory tax rate was 26%. The effective tax rate for 2022 and 2021 includes the benefit of enhanced oil recovery and
marginal well tax credits.

160

STANDARDIZED MEASURE, INCLUDING YEAR-TO-YEAR CHANGES THEREIN, OF DISCOUNTED FUTURE
NET CASH FLOWS

For purposes of the following disclosures, discounted future net cash flows were computed by applying to our
proved oil and natural gas reserves the unweighted arithmetic average of the first-day-of-the-month price for each
month within the years ended December 31, 2022, 2021 and 2020, respectively. The realized prices used to
calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were
determined using the current cost environment applied to expectations of future operating and development
activities. Future income tax expense was computed by applying, generally, year-end statutory tax rates (adjusted
for permanent differences and tax credits) to the estimated net future pre-tax cash flows, after allowing for the
deductions for intangible drilling costs and tax DD&A. The cash flows were discounted using a 10% discount
factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at
December 31, 2022, 2021 and 2020. Such assumptions, which are prescribed by regulation, have not always
proven accurate in the past. Other valid assumptions would give rise to substantially different results.

Standardized Measure of Discounted Future Net Cash Flows

December 31,
2022

Successor
December 31,
2021

December 31,
2020

(in millions)
Future cash inflows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Future costs
Operating costs(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Development costs(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Future income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Future net cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ten percent discount factor

35,190

28,031

15,532

(15,294)
(1,973)
(4,843)

13,080
(6,354)

(13,508)
(2,607)
(3,124)

8,792
(4,243)

(9,389)
(2,392)
(701)

3,050
(1,118)

Standardized measure of discounted future net cash flows . . . . $

6,726

4,549

1,932

(a)
(b)

Includes general and administrative expenses related to our field operations and taxes other than on income.
Includes asset retirement costs.

Changes in the Standardized Measure of Discounted Future Net Cash Flows from Proved
Reserve Quantities

Successor

2022

2021

2020

(in millions)
Beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

4,549

1,932

5,231

Sales of oil and natural gas, net of production and other operating
costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in price, net of production and other operating costs . . . . . .
Previously estimated development costs incurred . . . . . . . . . . . . . . . .
Change in estimated future development costs . . . . . . . . . . . . . . . . . .
Extensions, discoveries and improved recovery, net of costs . . . . . . .
Revisions of previous quantity estimates(a) . . . . . . . . . . . . . . . . . . . . . .
Accretion of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net change in income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases and sales of reserves in place . . . . . . . . . . . . . . . . . . . . . . .
Change in timing of estimated future production and other . . . . . . . . .

Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

(1,156)
3,814
228
306
509
(1,041)
573
(869)
(141)
(46)

2,177

(543)
3,414
185
(401)
115
1,114
226
(1,131)
(15)
(347)

2,617

(1,257)
(3,940)
519
1,032
122
(1,407)
650
1,124
(25)
(117)

(3,299)

End of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

6,726

4,549

1,932

(a)

Includes revisions related to performance and price changes.

161

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

Balance at
Beginning of
Period

Charged
(Credited) to
Costs and
Expenses

Charged
(Credited) to
Other
Accounts

Deductions

Balance at
End of
Period

(in millions)

2022 (Successor)

Deferred tax valuation
allowance . . . . . . . . . . . . . . $

Other asset valuation
allowance . . . . . . . . . . . . . . $

2021 (Successor)

Deferred tax valuation
allowance . . . . . . . . . . . . . . $

Other asset valuation
allowance . . . . . . . . . . . . . . $

November 1, 2020 -
December 31, 2020
(Successor)

Deferred tax valuation
allowance . . . . . . . . . . . . . . $

Other asset valuation
allowance . . . . . . . . . . . . . . $

January 1, 2020 -
October 31, 2020
(Predecessor)

Deferred tax valuation
allowance . . . . . . . . . . . . . . $

Other asset valuation
allowance . . . . . . . . . . . . . . $

— $

35 $

— $

1 $

— $

549 $

(526) $

(23) $

— $

—

511 $

35 $

3 $

— $

549

— $

—

646 $

(571) $

436 $

— $

511

22 $

(22) $

— $

—

162

ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE

None.

ITEM 9A CONTROLS AND PROCEDURES

Management’s Annual Assessment of and Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over

financial reporting. Our system of internal control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated
financial statements for external purposes in accordance with generally accepted accounting
principles. Our internal control over financial reporting includes those policies and procedures that:
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that our receipts and expenditures are being made only in
accordance with authorizations of our management and directors; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of
our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect

misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the
risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.

Our management has assessed the effectiveness of our internal control system as of December 31,

2022 based on the criteria for effective internal control over financial reporting described in Internal
Control – Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Based on this assessment, our management believes that, as of
December 31, 2022, our system of internal control over financial reporting is effective.

Our independent auditors, KPMG LLP, have issued a report on our internal control over financial

reporting, which is set forth in Item 8 – Financial Statements and Supplementary Data.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer (CEO) and Chief Financial Officer

(CFO), has evaluated the effectiveness 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 amended (Exchange Act)), as of
the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, our CEO and
CFO have concluded that, as of December 31, 2022, our disclosure controls and procedures are effective
and are designed to provide reasonable assurance that information we are required to disclose in reports
that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the
time periods specified in the rules and forms of the Securities and Exchange Commission (SEC), and that
such information is accumulated and communicated to our management, including our CEO and CFO, as
appropriate, to allow timely decisions regarding required disclosure.

163

Changes in Internal Control

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f)

and 15d-15(f) of the Exchange Act of 1934) identified in management’s evaluation pursuant to Rules
13a-15(d) or 15d-15(d) of the Exchange Act during the three months ended December 31, 2022 that
have materially affected, or are reasonably likely to materially affect, our internal control over financial
reporting.

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that
any controls and procedures, no matter how well designed and operated, can provide only reasonable
assurance of achieving the desired control objectives.

ITEM 9B OTHER INFORMATION

Management Team Realignment

On February 24, 2023, the Company announced that Francisco J. Leon, the Company’s current
Executive Vice President and Chief Financial Officer, will succeed Mark A. (Mac) McFarland as the
Company’s President and Chief Executive Officer, and is expected to join the Company’s Board of
Directors, effective at the Company’s 2023 Annual Meeting of Stockholders. Mr. McFarland will
continue to serve as a non-executive member of the Company’s Board of Directors and chair of the
board of the Company’s Carbon TerraVault subsidiary. The Company has an ongoing search for a
Chief Financial Officer to succeed Mr. Leon.

Mr. Leon, age 46, has been the Company’s Executive Vice President and Chief Financial Officer

since August 2020. Prior to that, he served as the Company’s Executive Vice President, Corporate
Development & Strategic Planning from January 2018 to August 2020 and as the Company’s Vice
President – Portfolio Management and Strategic Planning from December 2014 to January 2018.
Mr. Leon holds an M.B.A. from the University of Texas, Austin and a bi-national Bachelor of Arts
degree in International Business from San Diego State University and CETYS Universidad in Mexico.

The Company entered into a new employment agreement with Mr. Leon (the “CEO Employment

Agreement”) in connection with his anticipated promotion to the position of President and Chief
Executive Officer, which will supersede the employment agreement previously maintained by the
Company and Mr. Leon, dated June 8, 2021, for his position of Executive Vice-President and Chief
Financial Officer of the Company. The CEO Employment Agreement will initially govern his role as the
Company’s Executive Vice-President and Chief Financial Officer but will automatically begin covering
his new role as President and Chief Executive Officer in connection with his anticipated promotion on
the date of the Company’s 2023 Annual Meeting of Stockholders.

The CEO Employment Agreement provides for an initial two-year term beginning on February 23,

2023 (the “Effective Date”) and will automatically renew for an additional one-year term on each
anniversary of the Effective Date unless the Company or Mr. Leon provides 90 days’ written notice to
the other that no such automatic renewal shall occur.

164

The CEO Employment Agreement provides that Mr. Leon will receive an annual base salary of
$750,000. Mr. Leon will also be eligible to receive: (i) an annual cash bonus with a target value equal to
120% of his annual base salary; (ii) participation in those benefit plans and programs of the Company
available to similarly situated executives; and (iii) at the same time as other executive officers of the
Company receive 2023 annual equity award grants, annual long-term incentive awards (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 600% of his base
salary as in effect on the applicable grant date. The performance stock unit awards will vest over a
three-year cliff vesting period beginning on the date of grant, and the restricted stock units will vest in
three equal installments over a three-year vesting period beginning on the date of grant. In addition to
his annual 2023 LTIP awards described above, Mr. Leon will also receive two separate awards
pursuant to the LTIP in 2023: (i) an award of restricted stock units valued at $1,200,000 and (ii) an
award of performance units valued at $1,800,000, each award of which will vest over a two-year
vesting period.

The CEO Employment Agreement also provides for certain severance payments and benefits to be
provided to Mr. Leon upon his termination of employment by the Company without “Cause” (including a
termination of employment at the expiration of the term because the Company elected not to renew the
CEO Employment Agreement) or the executive’s resignation for “Good Reason,” death or “Disability”
(each quoted term as defined in the CEO Employment Agreement). Upon Mr. Leon’s termination of
employment for any reason, the CEO Employment Agreement provides that the Company shall pay all
unpaid base salary, any unreimbursed business expenses incurred prior to the date on which the
employment terminates (as applicable, the “Termination Date”), and all benefits to which he is entitled
under the terms of any applicable benefit plan (collectively, the “Accrued Benefits”).

Upon Mr. Leon’s termination of employment by the Company without Cause (including a

termination of employment at the expiration of the term because the Company elected not to renew the
Employment Agreement), or by Mr. Leon for Good Reason, Mr. Leon will receive payment of any
earned but unpaid annual bonus for the calendar year preceding the calendar year in which the
Termination Date occurs and, so long as Mr. Leon executes a release of claims in favor of the
Company and its affiliates and abides by the restrictive covenants within the CEO Employment
Agreement, Mr. Leon shall receive severance payments, generally payable in monthly installments
following the Termination Date consisting of: (i) cash payments equal to a predetermined multiple of
annual base salary plus target annual bonus awards for the year in which the termination occurs (the
multiple being two (2.0) times, increased to two and one-half (2.5) times if such termination of
employment occurs within the one (1)-year period following a qualifying Change in Control (such term
as defined in the CEO Employment Agreement); (ii) a pro-rata annual bonus for the calendar year in
which the Termination Date occurs, based on actual performance levels earned for the applicable
calendar year, (iii) reimbursement for the difference between the amount Mr. Leon pays to effect
continued coverage (including coverage for his spouse and eligible dependents) under the Company’s
group health plans pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as
amended, and Mr. Leon’s contribution amount that similarly situated executives of the Company pay
for the same or similar coverage under such group health plans, during the portion, if any, of the
24-month period for following the Termination Date that Mr. Leon elects to continue coverage, and
(iv) full vesting of the restricted stock units and performance stock units previously granted to Mr. Leon
during the 2021 calendar year under the LTIP and his original employment agreement.

If Mr. Leon’s employment is terminated due to death or Disability, then he will receive (i) the

Accrued Benefits, (ii) payment of any earned but unpaid annual bonus for the calendar year preceding
the calendar year in which the termination of employment occurs, and (iii) a pro-rata portion of the
annual bonus for the calendar year in which the Termination Date occurs, based on actual
performance for such calendar year and payable at the time such bonuses are paid to similarly situated
executives of the Company.

165

The foregoing description of the CEO Employment Agreement is qualified in its entirety by

reference to the full and complete text of the CEO Employment Agreement, which is attached here as
Exhibit 10.25 and incorporated herein by reference.

Retention Awards

In order to incentivize the retention of certain key employees, on February 24, 2023, the Company
entered into individual Retention Bonus Agreements with the following named executive officers: Jay
A. Bys, Shawn M. Kerns and Michael L. Preston. Each Retention Bonus Agreement provides for the
grant of a retention bonus in an aggregate amount that is equal to the annual base salary in effect for
that employee at the time of grant. The retention bonus will be subject to installment vesting over an
eighteen-month period, with twenty percent becoming vested on the six-month anniversary of the date
of grant, an additional twenty percent becoming vested on the twelve-month anniversary of the date of
grant, and the remaining sixty percent of the award becoming vested on the eighteen-month
anniversary of the date of grant. Vested portions of the retention bonus will become immediately
payable following the vesting date. During the retention period, if a participating employee is terminated
by the Company without cause or due to the employee’s death or disability, any remaining unvested
bonus award will immediately become vested and will be paid to the employee.

The foregoing description of the retention bonus awards are qualified in their entirety by reference

to the full and complete text of the form Retention Bonus Agreement that will govern each retention
bonus award, which is attached hereto as Exhibit 10.28 and incorporated herein by reference.

ITEM 9C DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

166

PART III

ITEM 10 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated by reference from our Proxy Statement for the 2023

Annual Meeting of Stockholders, which will be filed with the SEC within 120 days of the fiscal year ended
December 31, 2022 (2023 Proxy Statement). See the list of our executive officers and related information below.

Our board of directors has adopted a code of business conduct applicable to all officers, directors and
employees, which is available on our website (www.crc.com). We intend to satisfy the disclosure requirement
under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our code of business conduct
by posting such information on our website at the address specified above.

EXECUTIVE OFFICERS

Executive officers are appointed annually by the Board of Directors. The following table sets forth our current

executive officers:

Name

Employment History

Age at
February 24, 2023

Mark A. (Mac)
McFarland

Francisco J. Leon

Shawn M. Kerns

Michael L. Preston

Jay A. Bys

Chris D. Gould

President, Chief Executive Officer and Director since 2021; Chairman
of the Board and Interim Chief Executive Officer 2020 to 2021; GenOn
Energy Executive Chairman since December 2018; GenOn Energy
President and Chief Executive Officer 2017 to 2018; Luminant Holdings
Chief Executive Officer and Executive Vice President, Corporate
Development 2013 to 2016; Luminant Holdings Chief Commercial
Officer 2008 to 2013.

Executive Vice President and Chief Financial Officer since 2020;
Executive Vice President - Corporate Development and Strategic
Planning 2018 to 2020; Vice President - Portfolio Management and
Strategic Planning 2014 to 2018; Occidental Director - Portfolio
Management 2012 to 2014; Occidental Director of Corporate
Development and M&A 2010 to 2012; Occidental Manager of Business
Development 2008 to 2010.

Executive Vice President and Chief Operating Officer since 2021;
Executive Vice President - Operations and Engineering 2018 to 2021;
Executive Vice President - Corporate Development 2014 to 2018;
Vintage Production California President and General Manager 2012 to
2014; Occidental of Elk Hills General Manager 2010 to 2012;
Occidental of Elk Hills Asset Development Manager 2008 to 2010.

Executive Vice President, Chief Strategy Officer and General Counsel
since 2019; Executive Vice President, General Counsel and Corporate
Secretary 2014 to 2019; Occidental Oil and Gas Vice President and
General Counsel 2001 to 2014.

Executive Vice President and Chief Commercial Officer since 2021;
Private Energy Advisor 2019 to 2020 and 2015 to 2016; GenOn Energy
and affiliate companies Chief Commercial Officer 2017 to 2018;
Luminant Energy Vice President Origination and Capital Management
2007 to 2014; TXU, Enserch Energy various positions 1997 to 2007.

Executive Vice President and Chief Sustainability Officer since 2021;
Exelon Corporation Senior Vice President Corporate Strategy and
Chief Innovation and Sustainability Officer 2010 to 2021; Exelon
Corporation Vice President, Corporate Financial Planning and Analysis
2008 to 2010.

167

ITEM 11 EXECUTIVE COMPENSATION

The information required by this item is incorporated by reference from our 2023 Proxy Statement.

Pursuant to the rules and regulations under the Exchange Act, the information in the Compensation
Discussion and Analysis – Compensation Committee Report section shall not be deemed to be
“soliciting material,” or to be “filed” with the SEC, or subject to Regulation 14A or 14C under the
Exchange Act or to the liabilities under Section 18 of the Exchange Act, nor shall it be deemed
incorporated by reference into any filing under the Securities Act of 1933.

ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

AND RELATED STOCKHOLDER MATTERS

The information required by this item is incorporated by reference from our 2023 Proxy Statement.

See also Part II, Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities – Securities Authorized for Issuance Under Equity
Compensation Plans.

ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR

INDEPENDENCE

The information required by this item is incorporated by reference from our 2023 Proxy Statement.

ITEM 14 PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is KPMG LLP, Los Angeles, CA, Auditor ID: 185.

The information required by this item is incorporated by reference from our 2023 Proxy Statement.

168

PART IV

ITEM 15 EXHIBITS

The agreements included as exhibits to this report are included to provide information about their terms and not

to provide any other factual or disclosure information about us or the other parties to the agreements. The
agreements contain representations and warranties by each of the parties to the applicable agreement that were
made solely for the benefit of the other agreement parties and:

•

should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the
parties if those statements prove to be inaccurate;

have been qualified by disclosures that were made to the other party in connection with the negotiation of
the applicable agreement, which disclosures are not necessarily reflected in the agreement;

• may apply standards of materiality in a way that is different from the way the Company and investors may

view materiality; and

• were made only as of the date of the applicable agreement or such other date or dates as may be specified

in the agreement and are subject to more recent developments.

(a) (1) and (2). Financial Statements

Reference is made to Item 8 of the Table of Contents of this report where these documents are listed.

(a) (3). Exhibits
Exhibit
Number
2.1

2.2

3.1

3.2

3.3

4.1

4.2

4.3

10.1

Exhibit Description
Separation and Distribution Agreement, dated as of November 25, 2014, between Occidental
Petroleum Corporation and California Resources Corporation (filed as Exhibit 2.1 to the Registrant’s
Current Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
Amended Debtors’ Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code (filed as
Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed October 19, 2020 and incorporated
herein by reference).
Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as
Exhibit 3.1 to the Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and
incorporated herein by reference).
Certificate of Amendment of Amended and Restated Certificate of Incorporation of California
Resources Corporation (filed as Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on
May 6, 2022 and incorporated by reference).
Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2 to the
Registrant’s Registration Statement on Form 8-A filed October 27, 2020 and incorporated herein by
reference).
Description of Registrant’s Securities (filed as Exhibit 4.1 to the Registrant’s Annual Report on
Form 10-K filed March 11, 2021 and incorporated herein by reference).
Indenture, dated January 20, 2021, by and among California Resources Corporation, the Guarantors
and Wilmington Trust, National Association (filed as Exhibit 4.1 to the Registrant’s Current Report on
Form 8-K filed January 21, 2021 and incorporated herein by reference).
First Supplemental Indenture, dated January 20, 2021, by and among California Resources
Corporation, the Guarantors, Elk Hills Power, LLC, EHP Midco Holding Company, LLC, EHP Topco
Holding Company, LLC and Wilmington Trust, National Association (filed as Exhibit 4.2 to the
Registrant’s Current Report on Form 8-K filed January 21, 2021 and incorporated herein by
reference).
Contractors’ Agreement, by and between the City of Long Beach, Humble Oil & Refining Company,
Shell Oil Company, Socony Mobil Oil Company, Inc., Texaco, Inc., Union Oil Company of California,
Pauley Petroleum, Inc., Allied Chemical Corporation, Richfield Oil Corporation and Standard Oil
Company of California (filed as Exhibit 10.12 to Amendment No. 2 to the Registrant’s Registration
Statement on Form 10 filed August 20, 2014, and incorporated herein by reference).

169

Exhibit
Number

10.2

10.3

10.4

10.5

10.6

10.7

10.8

10.9

10.11

10.12

10.13

10.14

Exhibit Description

Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated
November 5, 1991, by and among the State of California, by and through the State Lands
Commission, the City of Long Beach, Atlantic Richfield Company and ARCO Long Beach, Inc. (filed
as Exhibit 10.10 to Amendment No. 2 to the Registrant’s Registration Statement on Form 10 filed
August 20, 2014 and incorporated herein by reference.
Amendment to the Agreement for Implementation of an Optimized Waterflood Program for the Long
Beach Unit, dated January 16, 2009, by and among the State of California, by and through the State
Lands Commission, the City of Long Beach, and Oxy Long Beach, Inc. (filed as Exhibit 10.11 to
Amendment No. 2 to the Registrant’s Registration Statement on Form 10 filed August 20, 2014, and
incorporated herein by reference).
Intellectual Property License Agreement, dated November 25, 2014, between Occidental Petroleum
Corporation and California Resources Corporation (filed as Exhibit 10.7 to the Registrant’s Current
Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
Area of Mutual Interest Agreement, dated November 25, 2014, between Occidental Petroleum
Corporation and California Resources Corporation (filed as Exhibit 10.5 to the Registrant’s Current
Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
Confidentiality and Trade Secret Protection Agreement, dated November 25, 2014, by and between
Occidental Petroleum Corporation and California Resources Corporation, dated November 24, 2014
(filed as Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed on December 1, 2014, and
incorporated herein by reference).
Credit Agreement, dated as of October 27, 2020, by and among California Resources Corporation, as
the Borrower, the several lenders from time to time parties thereto and Citibank, N.A., as
Administrative Agent, Collateral Agent and an Issuing Bank (filed as Exhibit 10.1 to the Registrant’s
Current Report on Form 8-K filed November 2, 2020 and incorporated herein by reference).
Warrant Agreement, dated as of October 27, 2020, by and between California Resources Corporation
and American Stock Transfer & Trust Company, LLC, as Warrant Agent (filed as Exhibit 10.4 to the
Registrant’s Current Report on Form 8-K filed November 2, 2020 and incorporated herein by
reference).
Registration Rights Agreement, dated as of October 27, 2020, by and among California Resources
Corporation and the holders party thereto (filed as Exhibit 10.1 to the Registrant’s Registration
Statement on Form 8-A filed October 27, 2020 and incorporated herein by reference).
First Amendment to the Credit Agreement, dated as of May 7, 2021, by and among California
Resources Corporation, as the Borrower, the several lenders from time to time parties thereto and
Citibank, N.A., as Administrative Agent, Collateral Agent and an Issuing Bank (filed as Exhibit 10.1 to
the Registrant’s Current Report on Form 8-K filed May 10, 2021 and incorporated herein by
reference.)
Second Amendment to the Credit Agreement, dated as of February 11, 2022, by and among
California Resources Corporation, as the Borrower, the several lenders from time to time parties
thereto and Citibank, N.A., as Administrative Agent, Collateral Agent and an Issuing Bank (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed February 16, 2022 and incorporated
herein by reference.)
Third Amendment to the Credit Agreement, dated as of April 29, 2022, by and among California
Resources Corporation, as the Borrower, the credit parties party thereto, the several lenders
from time to time parties thereto and Citibank, N.A. as administrative agent (filed as Exhibit 10.2 to
the Registrant’s Quarterly Report on Form 10-Q filed May 5, 2022 and incorporated herein by
reference).
The following are management contracts and compensatory plans required to be identified
specifically as responsive to Item 601(b)(10)(iii)(A) of Regulation S-K pursuant to Item 15(b) of
Form 10-K.
Form of Indemnification Agreement by and between California Resources Corporation and its
directors and executive officers (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K
filed October 27, 2020 and incorporated herein by reference).
California Resources Corporation 2021 Long Term Incentive Plan (filed as Exhibit 10.1 to the
Registrant’s Current Report on Form 8-K filed January 22, 2021 and incorporated herein by
reference).

170

Exhibit
Number

10.15

10.16

10.17

10.18

10.19

10.20

10.21

10.22

10.23

10.24

10.25*

10.26*

10.27*

10.28*
10.29

21*
23.1*
23.2*
23.3*
31.1*
31.2*
32.1*

99.1*

99.2*

Exhibit Description

Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit
Award for Non-Employee Directors Grant Agreement (filed as Exhibit 10.45 to the Registrant’s
Annual Report on Form 10-K filed March 11, 2021 and incorporated herein by reference).
Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit
Award Term and Conditions (filed as Exhibit 10.46 to the Registrant’s Annual Report on Form 10-K
filed March 11, 2021 and incorporated herein by reference).
Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit
Award Term and Conditions (filed as Exhibit 10.47 to the Registrant’s Annual Report on Form 10-K
filed March 11, 2021 and incorporated herein by reference).
Form of California Resources Corporation 2021 Long Term Incentive Plan Performance Stock Unit
Award Term and Conditions (filed as Exhibit 10.48 to the Registrant’s Annual Report on Form 10-K
filed March 11, 2021 and incorporated herein by reference).
Employment Agreement by and between Mark A. McFarland and California Resources Corporation,
dated March 22, 2021 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed
March 22, 2021 and incorporated herein by reference).
Employment Agreement by and between Shawn M. Kerns and California Resources Corporation,
dated June 8, 2021 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed
June 11, 2021 and incorporated herein by reference).
Employment Agreement by and between Francisco J. Leon and California Resources Corporation,
dated June 8, 2021 (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed
June 11, 2021 and incorporated herein by reference).
Employment Agreement by and between Michael L. Preston and California Resources Corporation,
dated June 8, 2021 (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed
August 5, 2021 and incorporated herein by reference).
Employment Agreement by and between Jay A. Bys and California Resources Corporation, dated
June 8, 2021 (filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed August 5,
2021 and incorporated herein by reference).
Employment Agreement by and between Chris Gould and California Resources Corporation, dated
June 8, 2021 (filed as Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q filed August 5,
2021 and incorporated herein by reference).
Employment Agreement by and between Francisco J. Leon and California Resources Corporation,
dated February 23, 2023.
2023 Form of California Resources Corporation 2021 Long Term Incentive Plan Restricted Stock Unit
Award Term and Conditions.
2023 Form of California Resources Corporation 2021 Long Term Incentive Plan Performance Stock
Unit Award Term and Conditions.
Form of Cash Retention Bonus Agreement.
California Resources Corporation Employee Stock Purchase Plan (filed as Exhibit 10.1 to the
Registrant’s Current Report on Form 8-K filed on May 6, 2022 and incorporated herein by reference).
List of Subsidiaries of California Resources Corporation.
Consent of Independent Registered Public Accounting Firm.
Consent of Independent Petroleum Engineers, Ryder Scott Company, L.P.
Consent of Independent Petroleum Engineers, Netherland, Sewell & Associates, Inc.
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
Ryder Scott Company, L.P. Estimated Future Reserves Attributable to Certain Leasehold and Royalty
Interests as of December 31, 2022.
Netherland, Sewell & Associates, Inc. Estimated Future Reserves Attributable to Certain Leasehold
and Royalty Interests as of December 31, 2022.

171

Exhibit
Number

101.INS*
101.SCH*
101.CAL*
101.LAB*
101.PRE*
101.DEF*
104

Exhibit Description

Inline XBRL Instance Document.
Inline XBRL Taxonomy Extension Schema Document.
Inline XBRL Taxonomy Extension Calculation Linkbase Document.
Inline XBRL Taxonomy Extension Label Linkbase Document.
Inline XBRL Taxonomy Extension Presentation Linkbase Document.
Inline XBRL Taxonomy Extension Definition Linkbase Document.
Cover Page Interactive Data File (formatted in inline XBRL and contained in Exhibits 101).

* - Filed herewith.

172

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

February 24, 2023

By:

/s/ Mark A. (Mac) McFarland

Mark A. (Mac) McFarland
President,
Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed

below by the following persons on behalf of the registrant and in the capacities and on the dates
indicated.

Title

Date

/s/ Mark A. (Mac) McFarland

President,

February 24, 2023

Mark A. (Mac) McFarland

Chief Executive Officer and Director

/s/ Francisco J. Leon

Francisco J. Leon

/s/ Noelle M. Repetti

Noelle M. Repetti

/s/ Tiffany (TJ) Thom Cepak

Tiffany (TJ) Thom Cepak

/s/ Andrew B. Bremner

Andrew B. Bremner

/s/ Douglas E. Brooks

Douglas E. Brooks

/s/ James N. Chapman

James N. Chapman

/s/ Nicole Neeman Brady

Nicole Neeman Brady

/s/ Julio M. Quintana

Julio M. Quintana

/s/ William B. Roby

William B. Roby

/s/ A. Alejandra Veltmann

A. Alejandra Veltmann

Executive Vice President and

February 24, 2023

Chief Financial Officer

Senior Vice President and Controller and February 24, 2023

Principal Accounting Officer

Chair of the Board

February 24, 2023

Director

February 24, 2023

Director

February 24, 2023

Director

February 24, 2023

Director

February 24, 2023

Director

February 24, 2023

Director

February 24, 2023

Director

February 24, 2023

173

[THIS PAGE INTENTIONALLY LEFT BLANK]

Annual Meeting

Investor Relations

California Resources Corporation’s annual meeting
of stockholders will be held virtually at 11:00 a.m.
Pacific Time on April 28, 2023. You will not be able
to attend the annual meeting physically. If you wish
to attend the annual meeting, you must follow the
instructions under “Attending the Annual Meeting”
in the proxy statement.

Auditors

KPMG LLP, Los Angeles, California

Transfer Agent & Registrar

American Stock Transfer and Trust Company, LLC
Shareholder Services
6201 15th Avenue, Brooklyn, New York 11219
(866) 659-2647
crc@astfinancial.com
www.astfinancial.com

Company financial information, public disclosures
and other information are available through our
website at www.crc.com. We will promptly deliver
free of charge, upon request, an annual report on
Form 10-K to any stockholder requesting a copy.
Requests should be directed to our Investor Relations
team at our corporate headquarters address or sent
to CRC_IR@crc.com.

Stock Exchange Listing

California Resources Corporation’s common stock
is listed on the New York Stock Exchange (NYSE).
The symbol is CRC.

Officers

Mark A. (Mac) McFarland
President and Chief Executive Officer

Board of Directors

Tiffany (TJ) Thom Cepak
Chair of the Board. Director since 2020

Jay A. Bys
Executive Vice President
and Chief Commercial Officer

Chris D. Gould
Executive Vice President
and Chief Sustainability Officer

Shawn M. Kerns
Executive Vice President
and Chief Operating Officer

Francisco J. Leon
Executive Vice President
and Chief Financial Officer

Michael L. Preston
Executive Vice President,
Chief Strategy Officer
and General Counsel

Andrew B. Bremner
Member of the Compensation Committee and
Sustainability Committee. Director since 2021

Douglas E. Brooks
Member of the Audit Committee. Director since 2020

James N. Chapman
Chair of the Compensation Committee and
Member of the Nominating and Governance Committee.
Director since 2020

Mark A. (Mac) McFarland
President, Chief Executive Officer. Director since 2020

Nicole Neeman Brady
Member of the Sustainability Committee and
Compensation Committee. Director since 2021

Julio M. Quintana
Chair of the Nominating and Governance Committee and
Member of the Audit Committee. Director since 2020

William B. Roby
Chair of the Sustainability Committee and
Member of the Audit Committee. Director since 2020

This Annual Report is printed on Forest Stewardship
Council®-certiﬁed paper that contains wood from
well-managed forests and other responsible sources.

Alejandra (Ale) Veltmann
Chair of the Audit Committee and
Member of the Nominating and Governance Committee.
Director since 2021