California Resources Annual Report 2023

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FY2023 Annual Report · California Resources

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2023
ANNUAL REPORT

$
$

2023

2022

$
$
$
$

$
$
$
$
$

6.75
4.95

7.78
5.13

653
185
468
(289)

690
379
311
(371)

FINANCIAL HIGHLIGHTS

2,801
564
0
564
372

2,707
524
0
524
384

Total Assets
Long-Term Debt, Net
Stockholders’ Equity

Weighted-Average Shares Outstanding - Diluted
Year-End Shares

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

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

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

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

HIGHLIGHTS

3FINANCIAL & OPERATIONAL
2
0
2

Net Mineral Acreage (in thousands):
Developed
Undeveloped
Total

Standardized Measure of Discounted Future Net Cash Flows (in billions)
PV-10 of Cash Flows (in billions)(a)

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)

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

OPERATIONAL HIGHLIGHTS

61.80
98.26
64.33
7.68

294
38
511
417

55
11
147
91

52
11
135
86

65.97
80.41
48.94
8.59

256
35
518
377

77.6
71.9

72.5
68.7

3,967
592
1,864

689
1,178
1,867

684
1,008
1,692

3,998
540
2,219

Closing Share Price

$
$
$
$

43.51

4.1
5.5

6.7
9.2

54.68

2023

2022

$
$
$

$
$

2021

1,889
625
13
612
506

7.37
6.10

660
194
466
(222)

3,846
589
1,688

$
$
$
$
$

$
$

$
$
$
$

$
$
$

83.0
79.3

2021

60
13
159
100

$
$
$
$

56.05
70.43
53.62
4.22

343
41
576
480

4.5
6.2

$
$

699
1,192
1,891

42.71

(a) See www.crc.com, Investor Relations for 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 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. Additionally, the information in this report contains forward-looking statements related to the recently announced Aera merger.

2023 CEO Annual Report Letter

Dear Shareholders,

California Resources Corporation (CRC) is a different kind of energy company. We are committed

to providing innovative energy solutions that will continue to deliver the reliable energy Californians
need while finding pathways to advance California’s decarbonization initiatives. During 2023 we made
remarkable progress to advance our business objectives. CRC has a leading market position with a
clear path to address today’s complex energy challenges and create real value for our shareholders.

We accomplished a lot in 2023:

• Achieved strong financial, operating and safety results. We had strong net income,

improved capital efficiency, low reservoir declines, and delivered sound capital discipline. Net
income was $564 million, or $7.78 per diluted share, net cash provided by operating activities
was $653 million and free cash flow1 was $468 million. Results reflected total net production
of 86 thousand barrels of oil equivalent per day (MBoe/d), of which 60% was oil. We also
achieved the second-best total recordable incident rate in our Company’s history, highlighting
our strong safety culture.

• Delivered robust returns to shareholders. We funded our capital projects with less than
half of our annual cash flow. The other half was returned to shareholders, approximately
$225 million in 2023, and approximately $760 million over the last three years.

• Maintained premier balance sheet. CRC has an exceptional capital structure; it’s the

financial foundation for all that we do. We reduced our debt by $55 million during 2023, exiting
the year with a nearly zero leverage ratio1.

• Enhanced future profitability. We implemented $65 million in annual, sustainable cost

savings. Our talented workforce found additional safe and innovative ways to streamline our
processes and strengthen our margins. This tremendous effort will pay dividends in 2024 and
beyond.

• Advanced California’s decarbonization efforts. Recent progress has allowed us to scale
our carbon management business, which we refer to as Carbon TerraVault (CTV). Through
CTV, we have entered into several Carbon Dioxide Management Agreements (CDMA)2 to
date allowing for the capture and sequestration of nearly 900,000 metric tons of carbon
dioxide (CO2) per year. Our California Direct Air Capture (DAC) Hub was selected to receive
nearly $12 million in funding from the U.S. Department of Energy (DOE), highlighting federal
support for the consortium of organizations across industry, technology, academia, national
labs, community, government, and labor. We are proud to be California’s carbon capture and
storage (CCS) leader.

CRC is “all in” for advancing the energy transition and providing lower carbon solutions to

California. As we continue to help the state achieve its carbon neutrality goal, reality tells us this won’t
happen overnight. Today, California tops the list of the largest U.S. economies, consuming nearly
1.5 million barrels of oil every day3. With less than 25% of this oil produced in our Golden state3,
demand is met with more expensive, higher-carbon intensive foreign barrels that are not produced
according to the leading environmental regulations that we adhere to. CRC is also California’s largest
natural gas producer providing a local option that competes with imported volumes from other parts of
the U.S.

During the year, our CTV business has grown significantly as we expanded our CO2 storage
capacity in proximity to major California markets by 36%. We are anticipating reaching important
milestones, including the Environmental Protection Agency’s (EPA) release of California’s first final
Class VI well permits for the 26R reservoir, located within the CTV I CCS vault at the Elk Hills Field.
With these anticipated permits, we remain on track for the first CO2 injection by year end 2025. Today,

California stakeholders and market participants are showing tremendous interest in our growing carbon
management business and solutions for hard-to-abate industries. We look forward to reporting on our
progress in the coming months.

In early 2024, we announced a transaction to merge with Aera Energy, LLC. The transaction,
which is expected to close in the second half of 2024, will enhance our shareholder returns, strengthen
our conventional energy business, and continue to provide local, low carbon intensity production to fuel
California. Importantly, it also expands our CO2 sequestration pore space portfolio and helps
decarbonize high emissions sectors of the Golden State’s economy. This is a win for all stakeholders.
We are confident in our ability to integrate Aera’s assets following closing and expect to capture
significant operational synergies to create a more durable new energy business.

As we look to the remainder of 2024, we are focused on maximizing our free cash flow through
continued discipline of our capital investments. We intend to run at one rig for the remainder of the
year. This will allow us to return significant cash to shareholders through our dividends and recently
expanded share repurchase program, while continuing to further reduce debt. We understand the
importance of sustainable returns to shareholders and our commitment to a strong balance sheet is
unwavering.

It is an honor and privilege to work side-by-side each day with the incredibly talented and driven
team at CRC. I am confident that our workforce is aligned with our business strategy. We are executing
our plan to generate long-term value for shareholders while providing needed solutions to meet
California’s present and future energy needs.

Francisco J. Leon
President and Chief Executive Officer
California Resources Corporation

1 Represents a non-GAAP measure. For all historical non-GAAP financial measures please see the Investor Relations page at
www.crc.com for a reconciliation to the nearest GAAP equivalent and other additional information. Free cash flow is equal to net
cash provided (used) by operating activities less capital investments.

2 The CDMA frames the contractual terms between parties by outlining the material economics and terms of the project and
includes conditions precedent to close. The CDMA provides a path for the parties to reach final definitive documents and final
investment decision.

3 Source: CalGEM

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, 2023
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.
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
Yes Í No ‘
reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Date File required to be submitted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period as the
registrant was required to submit such files).
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.

Yes ‘ No Í

Yes Í No ‘

Non-Accelerated Filer ‘

Í
Large Accelerated Filer
Smaller Reporting Company ‘

‘
Accelerated Filer
Emerging Growth Company ‘
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ‘
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the
effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b))
by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the
registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-
based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to
§240.10D-1(b). ‘
Yes ‘ No Í
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
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, 2023: $3,121,405,912.
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.
At January 31, 2024, there were 69,274,418 shares of Common Stock outstanding.

Yes Í No ‘

‘

Portions of the Definitive Proxy Statement to be filed within 120 days after December 31, 2023 with the Securities and
Exchange Commission in connection with the registrant’s 2024 Annual Meeting of Stockholders are incorporated by reference
into Part III of this Form 10-K.

DOCUMENTS INCORPORATED BY REFERENCE

TABLE OF CONTENTS

Part I

Items 1 & 2 BUSINESS AND PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Overview and History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recent Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CYBERSECURITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MINE SAFETY DISCLOSURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Item 1A
Item 1B
Item 1C
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production, Prices and Realizations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Divestitures and Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Carbon TerraVault Joint Venture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share Repurchase Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supply Chain and Inflation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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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36
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61
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63
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67
67
68
70
70
77
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76
79
82
84
86

88
89
89
92

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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138
144

145
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146

146

147
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148

148

148
148

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

149

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.
• 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

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.

Recent Developments

Pending Aera Merger

On February 7, 2024, we entered into a definitive agreement and plan of merger (Merger

Agreement) to combine with Aera Energy, LLC (Aera) in an all-stock transaction (Aera Merger) with an
effective date of January 1, 2024. Aera is a leading operator of mature fields in California, primarily in
the San Joaquin and Ventura basins, with high oil-weighted production.

Pursuant to the Merger Agreement, we have agreed to issue 21,170,357 shares of common stock
(subject to customary adjustments in the event of stock splits, dividend paid in stock and similar items)
plus an additional number of shares determined by reference to the dividends declared by us having a
record date between the effective date and closing as more fully described in the Merger Agreement.
Under the terms of the Merger Agreement, we have also agreed to assume Aera’s outstanding long-
term indebtedness of $950 million at closing. We expect to repay a significant portion of this
indebtedness with cash on hand and borrowings under our Revolving Credit Facility. We intend to
refinance the balance through one or more debt capital markets transactions and, only to the extent
necessary, borrowings under a bridge loan facility provided by Citigroup Global Markets, Inc. (the
Bank). Under the terms of our debt commitment letter with the Bank, it has committed, subject to
satisfaction of customary conditions, to provide us with an unsecured 364-day bridge loan facility in an
aggregate principal amount of $500 million (Bridge Loan Facility).

Closing of the Aera Merger is subject to certain conditions, including, among others, approval of the
stock issuance by our stockholders, expiration of the applicable waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended, prior authorization by the Federal Energy Regulatory
Commission under Section 203 of the Federal Power Act and other customary closing conditions.

Upon completion of the transaction, we currently expect our existing stockholders to own

approximately 77.1% of the combined company and the existing Aera owners to own approximately
22.9% of the combined company, on a fully diluted basis. The Aera Merger is expected to close in the
second half of 2024. Post closing of the Aera Merger, and subject to Board approval, we expect to
increase our quarterly dividend.

Amendment to our Revolving Credit Facility

In connection with the Merger Agreement, on February 9, 2024, we entered into a second amendment

to our Revolving Credit Facility to permit us to incur indebtedness under the Bridge Loan Facility.

Sale of Fort Apache in Huntington Beach

In February 2024, we entered into an agreement to sell our 0.9-acre Fort Apache real estate

property in Huntington Beach, California for approximately $10 million.

Oil and Natural Gas Operations

As of December 31, 2023, our proved reserves totaled an estimated 377 MMBoe, of which

256 MMBbl were crude oil and condensate reserves, 35 MMBbl were NGL reserves and 518 BcF, or
86 MMBoe, were natural gas reserves.

As of December 31, 2023, we held approximately 1.7 million net mineral acres, the largest privately

owned mineral acreage position in California. Our operated asset base spans 97 distinct fields with
approximately 9,000 net operated wells. We had average net production of approximately 86 MBoe/d
(60% oil) for the year ended December 31, 2023.

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

December 31, 2023:

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

1,111

89 %

49 %

— %

430

45 %

117

1,692

97 %

77 %

42
—

4.0

165
35
456
276

5
1

26.5

91
—
5
92

—
—

—

—
—
—
—

50
—

—

—
—
57
9

—
—

—

—
—
—
—

97
1

30.5

256
35
518
377

60 %

99 %

— %

68 %

—

(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 8 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 330 MMcf/d. Additionally, our Elk Hills power plant
generates electricity to power our oil and gas operations at the Elk Hills field, and offers excess power
to the California Independent System Operator (CAISO) wholesale energy marketplace. We also
market power plant capacity in excess of our internal needs to the CAISO Resource Adequacy (RA)
marketplace. 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 800,000 acres in the San Joaquin
basin, or over 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 our 90-acre Huntington Beach field, which is currently a

producing oil field with average daily net production of 3 MBoe/d. At our Huntington Beach field we
have begun the plugging and abandonment work of approximately 50 wells in 2024. We are working
towards the longer-term remediation of this property to provide flexibility for real estate sales in the
future. Refer to Recent Developments above for information on an agreement to sell a one-acre parcel
of land in Huntington Beach.

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. We are in the process of pursuing permits to facilitate
production growth and develop this resource, leveraging the existing infrastructure already in place.

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. We expect the sale
of our remaining Ventura basin asset could occur in 2024.

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, 2023.

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

457
420

811
691

20
15

15
13

(in thousands)

6
6

—
—

255
242

226
188

2
1

140
116

740
684

1,192
1,008

Gross(c) . . . .
Net(d) . . . . . .
(a) Reflects remaining mineral acreage retained in the Ventura Basin and nearby areas. See Part II, Item 8 – Financial

1,268
1,111

142
117

481
430

35
28

1,932
1,692

6
6

Statements and Supplementary Data, Note 8 Divestitures and Acquisitions for more information on our Ventura Basin
divestiture.

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

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

At December 31, 2023, 77% of our total net mineral interest position was held in fee and the
remainder was leased. Of our leased acreage, approximately 87% 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 2,000 net

mineral acres will expire in 2024, 21,000 net mineral acres will expire in 2025 and 14,000 net mineral
acres will expire in 2026. These leases represent 4% of our total net undeveloped acreage and 2% of
our total net acreage as of December 31, 2023 and these expirations, should they occur, would not
have a material adverse impact on us. Historically, we have not dedicated any significant portion of our
capital program to prevent lease expirations and do not expect to do so in the future.

Production, Price and Cost History

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

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

Year Ended December 31,
2022

2021

2023

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) - Average Monthly Settled

52
11
135
86

55
11
147
91

65.97 $
80.41 $
48.94 $
8.59 $

61.80 $
98.26 $
64.33 $
7.68 $

82.22 $
77.62 $

98.89 $
94.23 $

60
13
159
100

56.05
70.43
53.62
4.22

70.79
67.91

Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $

2.74 $

6.64 $

3.84

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

26.24 $

23.75 $

19.39

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

Elk Hills
2022

2023

2021

2023

Wilmington
2022

2021

Average daily net production

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

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

16
8
68

17
8
75

17
10
81

16
—
—

15
—
—

16
—
—

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 18% of our total production for the year ended December 31, 2023.

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:

2023

Year ended December 31,
2022

2021

(in millions)

($ per Boe)

(in millions)

($ per Boe)

(in millions)

($ per Boe)

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

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

822

26.24

785

(71)

(2.25)

(74)

751

23.99

711

23.75

705

(2.23)

(66)

21.52

639

19.39

(1.83)

17.56

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

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

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

Year ended December 31,
2022

2021

2023

(MBoe/d)
Average Daily Net Production . . . . . . . . . . . . . . . . . . . .
Partners’ share under PSC-type contracts . . . . . . . . .
Working interest and royalty holders’ share . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Average Daily Gross Production . . . . . . . . . . . . . . . . .

86
7
7
1

101

91
8
6
1

106

100
8
8
1

117

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 SEC.

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

gas reserves and PV-10 as of December 31, 2023. 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 $82.84 per barrel was adjusted for gravity, quality and transportation
costs. For natural gas volumes, the average NYMEX gas price of $2.64 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, 2023 were $80.97 per barrel for oil, $50.00 per barrel for NGLs and $4.57 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, 2023

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) . . . . . . . . . . . . . . . . . . .

136
34
389

235

29
1
67

165
35
456

276

87
—
5

4
—
—

91
—
5

—
—
—

—

—
—
—

—

—
—
—

—

—
—
51

—
—
6

—
—
57

223
34
445

331

33
1
73

256
35
518

377

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

Reserves to production ratio
12
(years)(b)
(a) As of December 31, 2023, approximately 18% of proved developed oil reserves, 7% of proved developed NGLs reserves,
10% of proved developed natural gas reserves and, overall, 15% 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, 2023 divided by total production for the year ended December 31,

2023.

Changes to Proved Reserves

The components of the changes to our proved reserves during the year ended December 31, 2023

were as follows:

San Joaquin
Basin

Los Angeles
Basin(a)

Ventura
Basin
(in MMBoe)

Sacramento
Basin

Total

Balance at December 31, 2022 . . . . . . . . . . . . . . .
Revisions related to price . . . . . . . . . . . . . . . . . .
Revisions related to performance . . . . . . . . . . . .
Revisions due to California regulatory changes
and court challenges . . . . . . . . . . . . . . . . . . . . . .
Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . .
Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Balance at December 31, 2023 . . . . . . . . . . . . . . .

295
(6)
20

(1)
3
1
(12)
(24)

276

113
(5)
1

(11)
1
—
—
(7)

—
—
—

—
—
—
—

—

9
(2)
2

—
1
—
—
(1)

417
(13)
23

(12)
5
1
(12)
(32)

377

(a)

Includes proved reserves related to PSCs of 76 MMBoe and 92 MMBoe at December 31, 2023 and 2022, respectively.

Revisions related to price – We had net negative price-related revisions of 13 MMBoe primarily
resulting from a lower commodity price environment in 2023 compared to 2022. Negative price-related
revisions of 22 MMBoe were partially offset by 9 MMBoe of positive revisions from operating cost
efficiencies.

Revisions related to performance – We had 23 MMBoe of net positive performance-related

revisions which included positive performance-related revisions of 38 MMBoe and negative
performance-related revisions of 15 MMBoe. Our positive performance-related revisions primarily
related to better-than-expected well performance. 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. The majority of
these revisions were located in the San Joaquin basin.

Revisions due to California regulatory changes and court challenges – We had 12 MMBoe of

negative revisions to our proved reserves 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 Los Angeles Basin.
See Regulation of the Industries in Which We Operate, Regulation of Exploration and Production
Activities.

Extensions – We added 5 MMBoe from extensions resulting from successful drilling and workovers

in the San Joaquin, Los Angeles and Sacramento basins.

Divestitures – We had a reduction of 12 MMBoe which related to our Round Mountain Unit

divestiture. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Divestitures
and Acquisitions for more information on this transaction.

Proved Undeveloped Reserves

The total changes to our proved undeveloped reserves during the year ended December 31, 2023

were as follows:

Balance at December 31, 2022 . . . . . . . . . . . . . . .
Revisions related to price . . . . . . . . . . . . . . . . . . .
Revisions related to performance . . . . . . . . . . . .
Revisions due to California regulatory changes
and court challenges . . . . . . . . . . . . . . . . . . . . . . .
Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . .
Transfers to proved developed reserves . . . . . . .

Balance at December 31, 2023 . . . . . . . . . . . . . . .

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin
(in MMBoe)

Sacramento
Basin

Total

38
(2)
4

(1)
1
1
—

16
1
—

(11)
1
—
(3)

—
—
—

—
—
—
—

—

—
—
—

—
1
—
—

54
(1)
4

(12)
3
1
(3)

Revisions related to price – We had 1 MMBoe of net negative price-related revisions. Negative
price-related revisions of 3 MMBoe were offset by 2 MMBoe of positive cost recovery barrels under our
PSCs.

Revisions related to performance – We had 4 MMBoe of net positive performance-related revision,

which included positive revisions of 9 MMBoe, partially offset by negative revisions of 5 MMBoe. Our
positive performance-related revisions of 9 MMBoe primarily related to proved undeveloped reserves
which were added to our five-year development plan in 2023. The majority of these revisions were
located in the San Joaquin basin.

Revisions due to California regulatory changes and court challenges – We removed 12 MMBoe

from proved undeveloped reserves due to the uncertainty of the outcome of the referendum and
potential impact of Senate Bill No. 1137 as discussed above. The majority of these revisions were
located in the Los Angeles basin. See Regulation of the Industries in Which We Operate, Regulations
of Exploration and Production Activities.

Extensions – We added 3 MMBoe of proved undeveloped reserves through extensions as a result
of successful drilling and workover programs in the San Joaquin, Los Angeles and Sacramento basins.

Transfers to proved developed reserves – We converted 3 MMBoe of proved undeveloped reserves

to proved developed reserves in the Los Angeles basin. This resulted in a conversion rate of
approximately 6% of our beginning-of-year proved undeveloped reserves, with an investment of
approximately $65 million of drilling and completion capital. We plan to increase our active rig count in
the second half of 2024 assuming the resumption of permitting of new wells and sidetracks. We believe
we will have sufficient capital to develop all year end 2023 proved undeveloped reserves within five
years of their original booking date. For more information on the 2024 Capital Program, see Part II,
Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,
Liquidity and Capital Resources and for more information on permitting, refer to Regulation of the
Industries in Which We Operate, Regulations of Exploration and Production Activities.

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, 2023
(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)

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

4,069
1,464

5,533

(a) The average realized prices for estimating our PV-10 of cash flow as of December 31, 2023 were $80.97 per barrel for oil,

$50.00 per barrel for NGLs and $4.57 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,
2023 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 Director of Reserves is the technical person who is primarily responsible for overseeing the
preparation of our reserves estimates. He has over 15 years of experience in the upstream oil and gas
industry, with projects ranging from appraisal of primary production reservoirs to enhanced oil recovery
floods. He holds a Bachelor of Science degree in Petroleum Engineering from the Colorado School of
Mines.

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 2023. The
Reserves Committee annually reports its findings to the Audit Committee.

Audits of Reserves Estimates

Netherland, Sewell & Associates, Inc. (NSAI) was engaged to provide independent audits of our
reserves estimates for our fields. For the year ended December 31, 2023, NSAI audited 88% of our
total proved reserves.

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

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

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.
Our independent reserve engineers issued an unqualified audit opinion on the applicable portions of
our proved reserves as of December 31, 2023, which is attached as Exhibit 99.1 to this Form 10-K and
incorporated herein by reference.

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

22 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

2023
Productive