“Low Carbon Intensity Fuel for Today and Net Zero Fuel for The Future”
2021
ANNUAL
REPORT
CALIFORNIA
RESOURCES
CORPORATION
FINANCIAL & OPERATIONAL
HIGHLIGHTS
Dollar amounts in millions, except share and per-share amounts, as of and for the years ended December 31,
FINANCIAL HIGHLIGHTS
Total Assets
Long-Term Debt, Net
Equity
Net Income (Loss) Attributable to Common
Stock per Share – Diluted
Adjusted Net Income (Loss)(a)
per Share – Diluted
Net Cash Provided by Operating Activities
Capital Investments
Free Cash Flow(a)
Net Cash (Used) Provided by Financing Activities
Total Revenue
Net Income (Loss)
Net Income Attributable to Noncontrolling Interests
Net Income (Loss) Attributable to Common Stock
Adjusted Net Income (Loss)(a)
1
2
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
Reserves:
Oil (MMBbl)
NGLs (MMBbl)
Natural Gas (Bcf)
Total (MMBoe)(b)
OPERATIONAL HIGHLIGHTS
PV-10 of Cash Flows (in billions)(a)
Closing Share Price
2021*
2020 Combined*
2019*
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,889
625
13
612
506
7.37
6.10
660
194
466
(222)
3,846
589
1,688
83.0
79.3
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,559
1,871
105
1,766
(257)
—
—
106
47
59
(58)
3,074
597
1,182
—
83.3
2,634
99
127
(28)
70
(0.57)
1.40
676
455
221
(282)
6,958
5,023
(296)
49.0
49.2
2021*
2020 Combined*
2019*
60
13
159
100
56.05
70.43
53.62
4.22
343
41
576
480
6.2
699
1,192
1,891
42.71
69
13
172
111
43.53
41.89
27.63
2.28
313
41
527
442
2.4
717
1,388
2,105
23.59
$
$
$
$
$
$
80
15
197
128
68.65
64.83
31.71
2.87
483
52
654
644
6.8
673
1,491
2,164
9.03
$
$
$
$
$
$
*Note: 2020 represents the combined successor and predecessor periods as defined in Part II - Item 7 – Basis of Presentation. 2019 represents the predecessor period and 2021 represents the successor period.
(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 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,
2021 was an important year for CRC. It was a year of building upon our strengths and
repositioning for the future. We focused on four key objectives: prioritizing our core assets, reducing
costs, investing with discipline, and maintaining balance sheet strength. By pursuing this strategy, we
were able to deliver our strongest performance in CRC’s history. As the COVID-19 pandemic remained
in the global spotlight, our resilient workforce first and foremost maintained robust and safe operational
performance while generating strong earnings. CRC produced approximately 100 thousand barrels of
oil equivalent per day while registering a 99.9997% oil spill prevention rate and delivering record
financial results. As part of our commitment to prioritize shareholder returns, the company repurchased
approximately $150 million of shares and initiated a quarterly dividend, subject to board authorization
each quarter, of $0.17 per share.
We maintained our low-decline, low carbon intensity oil production by focusing on our core assets
in the San Joaquin Valley and Long Beach area. We streamlined our business by reducing costs and
rationalizing our portfolio. In 2021, we divested the vast majority of our Ventura assets, which had
some of the highest operating expenses in CRC’s portfolio. We plan to continue engaging in active
portfolio management while focusing on optimizing our assets to provide low carbon intensity fuel
today and net zero fuel in the future.
We made strides on our emissions reducing projects through the initiation of our carbon
management business, Carbon TerraVault, and the advancement of our solar initiatives. To further
emphasize our commitment to Environmental, Social and Governance (ESG) leadership, we also
announced a Full-Scope Net Zero goal which includes achieving permanent storage of captured or
removed carbon emissions in a volume equal to our scope 1, 2 and 3 emissions by 2045. We are
proud to be one of the few E&P companies to announce a net zero goal and we already have assets
and scalable projects to make a meaningful impact. This goal, along with our 2030 Sustainability
Goals, aligns CRC with the State of California’s net zero ambitions, and further positions CRC as a
supporter of energy transition in the state.
Looking ahead, CRC will maintain our shareholder return mindset, retain operational excellence in
our core E&P business with a focus on safety, continue to advance our industry leading ESG projects
and preserve our robust financial position with significant liquidity and a strong balance sheet. We are
targeting another year of significant cash flow and advancing our carbon management business.
I look forward to what 2022 brings and I would like to thank the talented women and men of CRC
for their dedication and support of a great organization.
Sincerely,
Mark A. (Mac) McFarland
President and Chief Executive Officer
California Resources Corporation
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
Í
‘
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For the transition period from
to
Commission File Number 001-36478
California Resources Corporation
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
46-5670947
(I.R.S. Employer
Identification No.)
27200 Tourney Road, Suite 200
Santa Clarita, California 91355
(Address of principal executive offices) (Zip Code)
(888) 848-4754
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
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.
Yes ‘ No Í
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
required to submit such files).
Yes Í No ‘
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting
company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
Smaller Reporting Company ‘
Í
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.
Í
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,
2021: $2,467,158,949.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the
Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
Yes Í No ‘
At January 31, 2022, there were 78,744,340 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Definitive Proxy Statement to be filed within 120 days after December 31, 2021 with the Securities and Exchange
Commission in connection with the registrant’s 2022 Annual Meeting of Stockholders are incorporated by reference into Part III of this
Form 10-K.
TABLE OF CONTENTS
Part I
Items 1 & 2 BUSINESS AND PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Overview and History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mineral Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production, Price and Cost History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated Proved Reserves, Future Net Cash Flows and Drilling Locations . . . . . . . . .
Drilling Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Productive Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Carbon Management Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Human Capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marketing Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulation of the Oil and Natural Gas Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production, Prices and Realizations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and Joint Ventures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend Payment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Significant Accounting and Disclosure Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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
6
6
6
8
10
11
13
18
18
19
19
19
21
23
23
28
29
44
44
44
45
48
49
49
50
52
53
53
54
54
54
55
61
62
64
64
66
67
69
70
70
73
2
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
74
75
76
78
80
131
136
137
137
138
138
139
139
140
140
140
140
EXHIBITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
141
Item 9
Item 9A
Item 9B
Item 9C
Part III
Item 10
Item 11
Item 12
Item 13
Item 14
Part IV
Item 15
3
GLOSSARY AND SELECTED ABBREVIATIONS
The following are abbreviations and definitions of certain terms used within this Form 10-K:
• ASC - Accounting Standards Codification.
• ARO - Asset retirement obligation.
• Bbl - Barrel.
• Bbl/d - Barrels per day.
• Bcf - Billion cubic feet.
• Bcfe - Billion cubic feet of natural gas equivalent using the ratio of one barrel of oil, condensate, or NGLs
converted to six thousand cubic feet of natural gas.
• Boe - We convert natural gas volumes to crude oil equivalents using a ratio of six thousand cubic feet
(Mcf) to one barrel of crude oil equivalent based on energy content. This is a widely used conversion
method in the oil and gas industry.
• Boe/d - Barrel of oil equivalent per day.
• Btu - British thermal unit.
• CalGEM - California Geologic Energy Management Division.
• CCS - Carbon capture and storage.
• CO2 - Carbon dioxide.
• DD&A - Depletion, depreciation, and amortization.
• EOR - Enhanced oil recovery.
• EPA - United States Environmental Protection Agency.
• ESG - Environmental, social and governance.
• E&P - Exploration and production.
• Full-Scope Net Zero - Achieving permanent storage of captured or removed carbon emissions in a
JV - Joint venture.
volume equal to all of our scope 1, 2 and 3 emissions by 2045.
• GAAP - United States Generally Accepted Accounting Principles.
• 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.
• MW - Megawatts of power.
• NGLs - Natural gas liquids. Hydrocarbons found in natural gas that may be extracted as purity products
such as ethane, propane, isobutane and normal butane, and natural gasoline.
• NYMEX - The New York Mercantile Exchange.
• OPEC - Organization of the Petroleum Exporting Countries.
• PHMS - Pipeline and Hazardous Materials Safety Administration.
• Proved developed reserves - Reserves that can be expected to be recovered through existing wells
with existing equipment and operating methods.
• Proved reserves - The estimated quantities of natural gas, NGLs, and oil that geological and
engineering data demonstrate with reasonable certainty to be commercially recoverable in future years
from known reservoirs under existing economic conditions, operating methods and government
regulations.
• Proved undeveloped reserves - Proved reserves that are expected to be recovered from new wells on
undrilled acreage that are reasonably certain of production when drilled or from existing wells where a
relatively major expenditure is required for recompletion.
• PSCs - Production-sharing contracts.
4
• PV-10 - Non-GAAP financial measure and represents the year-end present value of estimated
future cash flows from proved oil and natural gas reserves, less future development and
operating costs, discounted at 10% per annum and using SEC Prices. PV-10 facilitates the
comparisons to other companies as it is not dependent on the tax-paying status of the entity.
• SDWA - Safe Drinking Water Act.
• SEC - United States Securities and Exchange Commission.
• SEC Prices - The unweighted arithmetic average of the first day-of-the-month price for each
month within the year used to determine estimated volumes and cash flows for our proved
reserves.
• SOFR - Secured overnight financing rate as administered by the Federal Reserve Bank of New
York.
• Standardized measure - The year-end present value of after-tax estimated future cash flows
from proved oil and natural gas reserves, less future development and operating costs,
discounted at 10% per annum and using SEC Prices. Standardized measure is prescribed by
the SEC as an industry standard asset value measure to compare reserves with consistent
pricing, costs and discount assumptions.
• Working interest - The right granted to a lessee of a property to explore for and to produce and
own oil, natural gas or other minerals in-place. A working interest owner bears the cost of
development and operations of the property.
• WTI - West Texas Intermediate.
5
PART I
ITEMS 1 & 2 BUSINESS AND PROPERTIES
Business Overview and History
We are an independent oil and natural gas exploration and production company operating
properties exclusively within California. We provide ample, affordable and reliable energy in a safe and
responsible manner, to support and enhance the quality of life of Californians and the local
communities in which we operate. We do this through the development of our broad portfolio of assets
while adhering to our commitment to making value-based capital investments. Further, we are
committed to energy transition and have some of the lowest carbon intensity production in the United
States. Through our subsidiary, Carbon TerraVault, we are in the early stages of developing several
carbon capture and sequestration projects in California. Separately, we are evaluating the feasibility of
a carbon capture system to be located at our Elk Hills power plant (CalCapture). We are also pursuing
multiple solar projects for supplying the grid (front-of-the-meter solar) and powering our operations
(behind-the-meter solar). Except when the context otherwise requires or where otherwise indicated, all
references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation
and its consolidated subsidiaries.
We qualified for and adopted fresh start accounting in connection with our emergence from
bankruptcy on October 27, 2020, at which point we became a new entity for financial reporting
purposes. We adopted an accounting convenience date of October 31, 2020 for the application of fresh
start accounting. As a result of the application of fresh start accounting and the effects of the
implementation of our joint plan of reorganization (the Plan), the financial statements after October 31,
2020 may not be comparable to the financial statements prior to that date. Accordingly, “black-line”
financial statements are presented to distinguish between Predecessor and Successor companies.
References to “Predecessor” refer to the Company for periods ending on or prior to October 31, 2020
and references to “Successor” refer to the Company for periods subsequent to October 31, 2020.
See Part II, Item 8 – Financial Statements and Supplementary Data, Note 14 Chapter 11
Proceedings and Note 15 Fresh Start Accounting for additional information on the terms of the Plan,
our emergence from bankruptcy and application of fresh start accounting.
Business Strategy
Our strategy is to continue to develop our oil and natural gas assets and while pursuing
opportunities in the emerging industries of decarbonization and energy transition. To accomplish our
strategy, we have developed the following key priorities:
• Maintain our oil production with a self-funded capital program focused on low-risk, high
return investments. The lower base decline of our conventional assets and more efficient
capital requirements compared to many of our peers provides us with a significant advantage.
We are targeting investing up to approximately 50% of our operating cash flow back into our
exploration and production business over the next several years. Our capital allocation priorities
focus on enhancing the value of our oil and gas assets while protecting our balance sheet,
maintaining mechanical integrity of our infrastructure and sustaining our base oil production.
With the premium Brent-based pricing for our oil, we intend to continue our focus on crude oil
projects which have a higher return than our natural gas projects.
• Preserve balance sheet strength and return capital to our shareholders. We maintain a
robust hedging strategy to help protect our cash flow from operations from volatility in the
commodities market. Additionally, we are committed to maintaining low leverage and a strong
liquidity position. Over the next several years, we are targeting investing approximately 25% of
our operating cash flow for shareholder returns and other strategic opportunities. In 2021, we
adopted a dividend policy by which we expect to pay a quarterly dividend of $0.17 per share of
our common stock, subject to final quarterly approval by our Board of Directors. We have also
adopted a $350 million share repurchase program that is expected to run through December 31,
2022. We have repurchased 4,089,988 shares as of December 31, 2021 at an average price of
$36.08 per share.
6
• Maintain our commitment to safety and sustainability and demonstrate leadership on
ESG practices in the E&P space. We are committed to exceptional environmental and safety
performance and have some of the lowest carbon intensity production among oil and natural
gas producers in the United States. We recently announced a Full-Scope Net Zero goal and are
seeking to permanently store captured or removed carbon emissions equal to our Scope 1, 2
and 3 emissions by 2045, which aligns us with the state of California’s 2045 net zero ambitions
and puts us ahead of the net zero goals in the Paris Agreement. We intend to achieve this goal
through our existing and future decarbonization projects, including Carbon TerraVault. We strive
to create a culture of safety and achieved a 99.9997% oil spill prevention rate in 2021 and
registered a workforce total recordable incident rate of 0.43 per 100 employees and contractors.
As part of our commitment to this priority, our annual incentive compensation metrics for our
management team include specific ESG targets for safety, environmental stewardship and
sustainability project milestones. For 2022, 30% of our management team’s annual incentive
related to company performance is tied to ESG related metrics.
• Advancing decarbonization and other emissions reducing projects. Over the next several
years, we are targeting investing approximately 25% of our operating cash flows in carbon
management projects. These projects include Carbon TerraVault, which is in the early stages of
permitting and developing several carbon capture and permanent storage projects in suitable
reservoirs. Separately, we are evaluating the feasibility of our CalCapture project which utilizes
the Elk Hills power plant as the emissions source for CO2 EOR in our Elk Hills field. We are also
pursuing multiple front-of-the-meter and behind-the-meter solar projects.
7
Operations
As of December 31, 2021, our proved reserves totaled an estimated 480 MMBoe, of which 343
MMBbl were crude oil and condensate reserves, 41 MMBbl were NGL reserves and 576 BcF, or 96
MMBoe, were natural gas reserves.
As of December 31, 2021, we held approximately 1.9 million net mineral acres, the largest
non-governmental mineral acreage position in California. Our operated asset base spans 99 distinct
fields with approximately 10,000 operated wells. We had average net production of approximately 100
MBoe/d (60% oil) for the year ended December 31, 2021. Our average net revenue interest was 85%
as of December 31, 2021. From time to time, we will assess our robust portfolio of assets for
divestitures.
The following table highlights key information about our operations as of and for the year ended
December 31, 2021:
Mineral Acreage
Net mineral acreage
(thousands) . . . . . . . . . . . .
Average net mineral
acreage held in fee (%)
Number of producing
fields we operate . . . . . . .
Average net revenue
interest (%)(b) . . . . . . . . . .
Average drilling rigs(c) . .
Net wells drilled and
completed . . . . . . . . . . . .
. .
Proved reserves
Oil (MMBbl) . . . . . . . . . . . .
NGLs (MMBbl)
. . . . . . . . .
Natural gas (Bcf) . . . . . . . .
. . . . . . . . .
Total (MMBoe)
Oil percentage of proved
reserves . . . . . . . . . . . . . . .
San
Joaquin
Basin
Los
Angeles
Basin
Ventura
Basin
Sacramento
Basin
Other(a)
Total
Operations
1,260
78 %
42
91 %
2
109.4
203
41
481
324
30
45 %
5
69 %
—
6.5
138
—
11
140
11
3 %
2
85 %
—
—
2
—
1
2
472
118
1,891
40 %
50
81 %
—
—
—
—
83
14
97 %
—
100 %
—
—
—
—
—
—
69 %
99
85 %
2
115.9
343
41
576
480
63 %
99 %
100 %
— %
— %
71 %
Production
Total net production
(MMBoe) . . . . . . . . . . . . . .
Average daily net
production (MBoe/d) . . . . .
(a) Reflects retained non-operating interest in the Ventura Basin and nearby areas. Our other interests include unproved
19
27
75
—
—
7
1
3
3
1
36
100
locations. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more
information on our Ventura Basin divestiture.
(b) The average net revenue interest represents our interest in oil, natural gas and NGL production as a percentage of gross
production. Our revenue interest considers royalties and similar burdens and third-party working interests.
(c) We operated three drilling rigs in the San Joaquin basin and one drilling rig in the Los Angeles basin at December 31, 2021.
San Joaquin Basin
The San Joaquin basin contains some of the largest oil fields in the United States based on
cumulative production and proved oil and natural gas reserves. Commercial petroleum development
began in the 1800s. The basin contains multiple stacked formations throughout its areal extent, and we
believe that this basin provides appealing opportunities for re-development of existing wells, as well as
new discoveries and unconventional play potential. The geology of the San Joaquin basin continues to
yield stratigraphic and structural trap discoveries.
We hold substantially all the working, surface and mineral interests in the Elk Hills field, which is our
largest producing asset in the San Joaquin Basin and one of the largest fields in the continental United
States.
8
At Elk Hills we operate efficient natural gas processing facilities, including a state-of-the-art
cryogenic gas plant, with a combined gas processing capacity of over 520 MMcf/d. Additionally, our Elk
Hills power plant generates sufficient electricity to operate the field, and sells excess power to the
wholesale market and a utility. Our operations at Elk Hills also include an advanced central control
facility and remote automation control on over 95% of the producing wells.
We have a large ownership interest in several of the largest existing oil fields in the San Joaquin
basin including Buena Vista and Coles Levee. We have also been successfully developing steamfloods
in our Kern Front operations.
We believe our extensive 3D seismic library, which covers approximately 800,000 acres in the San
Joaquin basin, or approximately 50% of our gross mineral acreage in this basin, gives us a competitive
advantage in field development and further exploration.
Los Angeles Basin
This basin is a northwest-trending plain about 50 miles long and 20 miles wide. Most of the
significant discoveries in the Los Angeles basin date back to the 1920s. The Los Angeles basin has
one of the highest concentrations per acre of crude oil in the world. The basin contains multiple
stacked formations throughout its depths, and we believe that the Los Angeles basin provides a
considerable inventory of existing field re-development opportunities as well as new play discovery
potential. Large active oil fields in this basin include the Wilmington and Huntington Beach fields,
where we have significant operations. Most of our Wilmington production is subject to a set of contracts
similar to production-sharing contracts (PSCs) under which we first recover the capital and operating
costs we incur on behalf of the state and the city of Long Beach and then receive our share of profits.
See Production, Price and Cost History below for more information on our PSCs.
Sacramento Basin
The Sacramento basin is a deep, thick sequence of sedimentary deposits of natural gas within an
elongated northwest-trending structural feature covering about 7.7 million acres. Exploration and
development in the basin began in 1918. Our significant mineral acreage position in the Sacramento
basin gives us the option for future development and rapid production growth in an attractive natural
gas price environment.
Ventura Basin
During the fourth quarter of 2021, we divested a vast majority of our assets in the Ventura basin.
Other than a de minimis non-operated asset, our remaining Ventura basin assets are expected to be
sold in the first half of 2022.
Other
Other than the basins described above, we also have mineral interests in undeveloped acreage
throughout California including in the Salinas basin and the Santa Maria basin.
9
Mineral Acreage
The following table summarizes our gross and net developed and undeveloped mineral acreage as
of December 31, 2021.
San Joaquin
Basin
Los Angeles
Basin
Ventura
Basin
Sacramento
Basin
Other(a)
Total
Developed(b)
Gross(c) . . . .
Net(d) . . . . . .
Undeveloped(e)
Gross(c) . . . .
Net(d) . . . . . .
Total
462
422
1,027
838
(in thousands)
10
10
2
1
267
250
270
222
21
16
17
14
2
1
144
117
762
699
1,460
1,192
1,489
1,260
2,222
Gross(c) . . . .
Net(d) . . . . . .
1,891
(a) Reflects remaining mineral acreage to be retained in the Ventura Basin and nearby areas. See Part II, Item 8 – Financial
Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more information on our Ventura Basin
divestiture.
537
472
146
118
38
30
12
11
(b) Mineral acres spaced or assigned to productive wells.
(c) Total number of mineral acres in which interests are owned.
(d) Net mineral acreage includes acreage reduced to our fractional ownership interest and interests under our PSCs.
(e) Mineral acres on which wells have not been drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether the mineral acreage contains proved reserves.
At December 31, 2021, 69% of our total net mineral interest position was held in fee and the
remainder was leased. Of our leased acreage, approximately 59% is held by production and the
remainder is subject to lease expiration if initial wells are not drilled within a specified period of time.
The primary terms of our leases range from one to twenty years. The terms of these leases are
typically extended upon achieving commercial production for so long as such production is maintained.
Work programs are designed to ensure that the economic potential of any leased property is evaluated
before expiration. In some instances, we may relinquish leased acreage in advance of the contractual
expiration date if the evaluation process is complete and there is no longer a commercial reason for
leasing that acreage. In cases where we determine we want to take the additional time required to fully
evaluate undeveloped acreage, we have generally been successful in obtaining extensions.
If we are not able to establish production or otherwise extend lease terms, approximately 72,000
net mineral acres will expire in 2022, 46,000 net mineral acres will expire in 2023 and 34,000 net
mineral acres will expire in 2024. These leases represent 13% of our total net undeveloped acreage
and 8% of our total net acreage as of December 31, 2021 and these expirations, should they occur,
would not have a material adverse impact on us. Historically, we have not dedicated any significant
portion of our capital program to prevent lease expirations and do not expect to do so in the future.
10
Production, Price and Cost History
The following table sets forth information regarding our production volumes, average realized and
benchmark prices and operating costs per Boe for the periods presented.
For additional information on production and prices, see information set forth in Part II, Item 7 –
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Production,
Prices and Realizations.
Successor
Predecessor
Year Ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year Ended
December 31,
2019
Average daily production
Oil (MBbl/d)
. . . . . . . . . . . . . .
NGLs (MBbl/d) . . . . . . . . . . . .
Natural gas (MMcf/d) . . . . . . .
Total daily production
(MBoe/d)(a)
. . . . . . . . . . . . . . .
Total production
(MMBoe)(a) . . . . . . . . . . . . . . .
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) . . . . .
Operating costs per Boe
Operating costs . . . . . . . . . . .
$
$
$
$
$
$
$
$
60
13
159
100
36
56.05
70.43
53.62
4.22
70.79
67.91
3.61
19.39
63
12
165
103
6
45.37
45.65
38.00
3.21
47.10
44.21
2.86
18.19
$
$
$
$
$
$
$
$
70
13
174
112
34
43.19
41.21
25.70
2.11
42.43
38.44
1.95
14.95
$
$
$
$
$
$
$
$
80
15
197
128
47
68.65
64.83
31.71
2.87
64.18
57.03
2.67
19.16
$
$
$
$
$
$
$
$
(a) See Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, Production,
Prices and Realizations for more information on our production activity.
Oil, natural gas and NGL production for our two largest fields are presented in the table below:
2021
Elk Hills
2020
2019
2021
Wilmington
2020
2019
Average daily production
Oil (MBbl/d) . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .
NGLs (MBbl/d)
. . . . . . . . . . . . . . .
Natural gas (MMcf/d)
Total daily production (MBoe/d) . . . . . . .
17
10
81
40
18
10
90
43
22
12
103
51
16
—
—
16
21
—
1
21
20
—
1
20
11
Our operating costs include (1) variable costs that fluctuate with production levels and (2) fixed costs
that typically do not vary with changes in production levels or well counts, especially in the short term. The
substantial majority of our near-term fixed costs become variable over the longer term because we manage
them based on the field’s stage of life and operating characteristics. For example, portions of labor and
material costs, energy, workovers and maintenance expenditures correlate to well count, production and
activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are
managed down as fields mature in a manner that correlates to production and commodity price levels. A
certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded
as fixed in the early phases of a program. However, as the production from a certain area matures, well
count increases and daily per well production drops, such support costs can be reduced and consolidated
over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as
property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with
commodity prices. We can quickly scale our operating costs in response to prevailing market conditions.
We believe that a significant portion of our operating costs are variable over the lifecycle of our fields.
Our share of production and reserves from operations in the Wilmington field in the Los Angeles basin is
subject to contractual arrangements similar to PSCs that are in effect through the economic life of the
assets. Under such contracts we are obligated to fund all capital and operating costs. We record a share of
production and reserves to recover a portion of such capital and operating costs and an additional share for
profit. Our portion of the production represents volumes: (i) to recover our partners’ share of capital and
operating costs that we incur on their behalf, (ii) for our share of contractually defined base production, and
(iii) for our share of remaining production thereafter. We generate returns through our defined share of
production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and
reserves reported from these arrangements are based on our economic interest as defined in the contracts.
Our share of production and reserves from these contracts decreases when product prices rise and
increases when prices decline, assuming comparable capital investment and operating costs. However, our
net economic benefit is greater when product prices are higher. These PSCs represented 15% of our total
production for the year ended December 31, 2021.
In line with industry practice for reporting PSCs, we report 100% of operating costs under such contracts
in operating costs on our consolidated statements of operations as opposed to reporting only our share of
those costs. We report the proceeds from production designed to recover our partners’ share of such costs
(cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes
produced, including cost recovery, which is less than the total volumes produced under the PSCs. This
difference in reporting full operating costs but only our net share of production equally inflates our revenue
and operating costs per barrel and has no effect on our net results.
The following table presents our operating costs after adjustment for excess costs attributable to PSCs
for the periods presented:
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
(in millions)
($ per Boe)
(in millions)
($ per Boe)
(in millions)
($ per Boe)
(in millions)
($ per Boe)
$
705
$
19.39 $
114
$
18.19
$
511
$
14.95 $
895
$
19.16
(66)
$
(1.83) $
(8)
$
(1.33)
(28)
$
(0.81)
(68)
$
(1.46)
$
639
$
17.56 $
106
$
16.86
$
483
$
14.14 $
827
$
17.70
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.
12
Estimated Proved Reserves, Future Net Cash Flows and Drilling Locations
The information with respect to our estimated reserves presented below has been prepared in
accordance with the rules and regulations of the United States Securities and Exchange Commission
(SEC).
The following tables summarize our estimated proved oil (including condensate), NGLs and natural
gas reserves and PV-10 as of December 31, 2021. Our estimated volumes and cash flows were
calculated using the unweighted arithmetic average of the first-day-of-the-month price for each month
within the year (SEC Prices), unless prices were defined by contractual arrangements. For oil volumes,
the average Brent spot price of $69.47 per barrel was adjusted for gravity, quality and transportation
costs. For natural gas volumes, the average NYMEX gas price of $3.60 per MMBtu was adjusted for
energy content, transportation fees and market differentials. All prices are held constant throughout the
lives of the properties. The average realized prices for estimating our proved reserves as of
December 31, 2021 were $68.73 per barrel for oil, $52.81 per barrel for NGLs and $3.99 per Mcf for
natural gas.
Estimated reserves include our economic interests under PSCs in our Long Beach operations in the
Wilmington field. Refer to Part II, Item 8 – Financial Statements, Supplemental Oil and Gas Information
for additional information on our proved reserves.
As of December 31, 2021
San Joaquin
Basin
Los Angeles
Basin
Ventura Basin
Sacramento
Basin
Total
Proved developed reserves
Oil (MMBbl) . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .
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) . . . . . . . . . . . . . . . . . . .
171
38
418
279
32
3
63
45
203
41
481
324
109
—
8
110
29
—
3
30
138
—
11
140
2
—
1
2
—
—
—
—
2
—
1
2
—
—
83
14
—
—
—
—
—
—
83
14
282
38
510
405
61
3
66
75
343
41
576
480
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserves to production ratio
13
(years)(b)
(a) As of December 31, 2021, approximately 22% of proved developed oil reserves, 8% of proved developed NGLs reserves,
16% of proved developed natural gas reserves and, overall, 19% of total proved developed reserves are non-producing. A
majority of our non-producing reserves relate to steamfloods and waterfloods where full production response has not yet
occurred due to the nature of such projects.
20
14
12
2
(b) Calculated as total proved reserves as of December 31, 2021 divided by total production for the year ended December 31,
2021.
13
Changes to Proved Reserves
The components of the changes to our proved reserves during the year ended December 31, 2021
were as follows:
Balance at December 31, 2020 . . . . . . . . . . . . . . . .
Revisions related to price . . . . . . . . . . . . . . . . . . . .
Revisions related to performance . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and divestitures . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at December 31, 2021 . . . . . . . . . . . . . . . .
San Joaquin
Basin
Los Angeles
Basin(a)
Ventura
Basin
Sacramento
Basin
Total
317
30
(8)
5
1
6
(27)
324
(in MMBoe)
12
2
—
—
—
(11)
(1)
105
25
17
—
—
—
(7)
140
2
8
7
—
—
—
—
(1)
14
442
64
9
5
1
(5)
(36)
480
(a)
Includes proved reserves related to PSCs of 111 MMBoe and 85 MMBoe at December 31, 2021 and 2020, respectively.
Revisions related to price – We had positive price-related revisions of 64 MMBoe primarily resulting
from a higher commodity price environment in 2021 compared to 2020. The net price revision reflects
the extended economic lives of our fields, estimated using 2021 SEC pricing, partially offset by our
higher operating costs.
Revisions related to performance – We had 9 MMBoe of net positive performance-related revisions
which included positive performance-related revisions of 21 MMBoe and negative performance-related
revisions of 12 MMBoe. Our positive performance-related revisions of 21 MMBoe primarily related to
better-than-expected well performance and addition of proved undeveloped locations due to positive
drilling results in certain areas. The positive revision also included proved undeveloped reserves added
to our five-year development plan in 2021. Our negative performance-related revisions primarily relate
to wells and incremental waterflood response that underperformed forecasts and removal of proved
undeveloped locations due to unsuccessful drilling results in certain areas. The majority of these
revisions were located in the San Joaquin and Los Angeles basins.
Extensions and discoveries – We added 5 MMBoe from extensions and discoveries resulting from
successful drilling and workovers in the San Joaquin and Los Angeles basins.
Acquisitions and Divestitures – We had a reduction of 11 MMBoe in connection with our Ventura
divestiture. We added 6 MMBoe in connection with our acquisition of the working interest in certain
wells from Macquarie Infrastructure and Real Assets Inc. (MIRA). See Part II, Item 8 – Financial
Statements and Supplementary Data, Note 3 Divestitures and Acquisitions for more information on
these transactions.
14
Proved Undeveloped Reserves
The total changes to our proved undeveloped reserves during the year ended December 31, 2021
were as follows:
Balance at December 31, 2020 . . . . . . . . . . . . . . . . .
Revisions related to price . . . . . . . . . . . . . . . . . . . . .
Revisions related to performance . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers to proved developed reserves . . . . . . . . .
Balance at December 31, 2021 . . . . . . . . . . . . . . . . .
San Joaquin
Basin
Los Angeles
Basin
Ventura
Basin
(in MMBoe)
Sacramento
Basin
Total
39
2
6
3
—
(5)
45
19
(1)
13
—
—
(1)
30
—
—
—
—
—
—
—
2
—
(2)
—
—
—
—
60
1
17
3
—
(6)
75
Revisions related to price – We had 1 MMBoe of net positive price-related revisions. Positive price-
related revisions of 2 MMBoe were offset by 1 MMBoe of negative cost recovery barrels in our PSCs.
Revisions related to performance – We had 17 MMBoe of net positive performance-related revision
which included 19 MMBoe positive performance-related revisions and negative performance-related
revisions of 2 MMBoe. Our positive performance-related revisions of 19 MMBoe primarily related to better-
than-expected well performance and the addition of proved undeveloped locations due to positive drilling
results in certain areas. The positive revision also included proved undeveloped reserves which were added
to our five-year development plan in 2021. Our negative performance-related revisions primarily related to
unsuccessful drilling results in certain areas. The majority of these revisions were located in the San
Joaquin and Los Angeles basins.
Extensions and discoveries – We added 3 MMBoe of proved undeveloped reserves through
extensions and discoveries, as a result of successful drilling and workover programs in the San
Joaquin and Los Angeles basins.
Transfers to proved developed reserves – We converted 6 MMBoe of proved undeveloped reserves to
proved developed reserves in the San Joaquin and Los Angeles basins. This resulted in a conversion rate
of approximately 10% of our beginning-of-year proved undeveloped reserves, with an investment of
approximately $64 million of drilling and completion capital. We believe we will have sufficient capital to
develop all year end 2021 proved undeveloped reserves within five years of their original booking date.
PV-10, Standardized Measure and Reserve Replacement Ratio
PV-10 of cash flows is a non-GAAP financial measure and represents the year-end present value of
estimated future cash inflows from proved oil and natural gas reserves, less future development and
operating costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC
Prices. Calculation of PV-10 does not give effect to derivative transactions. Our PV-10 is computed on the
same basis as our standardized measures of future net cash flows, the most comparable measure under
GAAP, but does not include the effects of future income taxes on future net cash flows. Neither PV-10 nor
Standardized Measure should be construed as the fair value of our oil and natural gas reserves.
Standardized Measure is prescribed by the SEC as an industry standard asset value measure to compare
reserves with consistent pricing, costs and discount assumptions. PV-10 facilitates the comparisons to other
companies as it is not dependent on the tax-paying status of the entity.
Standardized measure of discounted future net cash flows . . . . . . . . . . . .
Present value of future income taxes discounted at 10% . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PV-10 of cash flows(a)
$
$
4,549
1,624
6,173
(a) The average realized prices for estimating our PV-10 of cash flow as of December 31, 2021 were $68.73 per barrel for oil,
$52.81 per barrel for NGLs and $3.99 per Mcf for natural gas.
As of December 31, 2021
(in millions)
15
Reserves Evaluation and Review Process
Our estimates of proved reserves and related discounted future net cash flows as of December 31,
2021 were made by our technical personnel, comprised of reservoir engineers and geoscientists, with
the assistance of operational and financial personnel and are the responsibility of management. The
estimation of proved reserves is based on the requirement of reasonable certainty of economic
producibility and management’s funding commitments to develop the reserves. Reserves volumes are
estimated by forecasts of production rates, operating costs and capital investments. Price differentials
between specified benchmark prices and realized prices and specifics of each operating agreement
are then applied against the SEC Price to estimate the net reserves. Operating and capital costs are
forecast using the current cost environment applied to expectations of future operating and
development activities related to the proved reserves. See Part II, Item 7 – Management’s Discussion
and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates for further
discussion of uncertainties inherent in the reserve estimates.
Proved developed reserves are those volumes that are expected to be recovered through existing
wells with existing equipment and operating methods, for which the incremental cost of any additional
required investment is relatively minor. Proved undeveloped reserves are those volumes that are
expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required.
Our Vice President of Reserves has primary responsibility for overseeing the preparation of our
reserves estimates. With over 25 years of technical and leadership experience in the oil and gas
industry, she has been involved with all stages of petroleum exploration and development from
appraisal of new discoveries to enhanced recovery methods in mature fields. She holds a Master of
Business Administration from Pepperdine University, as well as bachelor’s and master’s degrees in
Geology from the University of California, Santa Barbara.
We have an Oil and Gas Reserves Review Committee (Reserves Committee), consisting of senior
corporate officers, which reviewed and approved our oil and natural gas reserves for 2021. The
Reserves Committee annually reports its findings to the Audit Committee.
Audits of Reserves Estimates
Ryder Scott and Netherland, Sewell & Associates, Inc. (NSAI) were engaged to provide
independent audits of our reserves estimates for our fields. For the year ended December 31, 2021,
Ryder Scott audited 47% of our total proved reserves. NSAI audited 35% of our total proved reserves.
Our independent reserve engineers examined the assumptions underlying our reserves estimates,
adequacy and quality of our work product and estimates of future production rates. They also
examined the appropriateness of the methodologies employed to estimate our reserves as well as their
categorization, using the definitions set forth by the SEC, and found them to be appropriate. As part of
their process, they developed their own independent estimates of reserves for those fields that they
audited. When compared on a field-by-field basis, some of our estimates were greater and some were
less than the estimates of our independent reserve engineers. Given the inherent uncertainties and
judgments in estimating proved reserves, differences between our estimates and those of our
independent reserve engineers are to be expected. The aggregate difference between our estimates
and those of the independent reserve engineers was less than 10%, which was within the Society of
Petroleum Engineers (SPE) acceptable tolerance.
16
In the conduct of the reserves audits, our independent reserve engineers did not independently
verify the accuracy and completeness of information and data furnished by us with respect to
ownership interests, crude oil and natural gas production, well test data, historical costs of operation
and development, product prices, or any agreements relating to current and future operations of the
fields and sales of production. However, if anything came to the attention of our independent auditors
that brought into question the validity or sufficiency of any such information or data, they would not rely
on such information or data until it had resolved its questions relating thereto or had independently
verified such information or data. Our independent reserve engineers determined that our estimates of
reserves have been prepared in accordance with the definitions and regulations of the SEC as well as
the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the SPE, including the criteria of “reasonable certainty,” as it pertains to expectations
about the recoverability of reserves in future years, under existing economic and operating conditions.
Both of our independent reserve engineers issued an unqualified audit opinion on the applicable
portions of our proved reserves as of December 31, 2021, which are attached as Exhibit 99.1 and 99.2,
respectively, to this Form 10-K and incorporated herein by reference.
Ryder Scott qualifications – The primary technical engineer responsible for our audit has more than
44 years of petroleum engineering experience, the majority of which has been in the estimation and
evaluation of reserves. He serves on the Ryder Scott Executive Committee and the Board of Directors
and is a registered Professional Engineer in the state of Texas.
NSAI qualifications – The primary technical engineer primarily responsible for our audit has more
than 20 years of petroleum engineering experience, with the majority spent evaluating California
properties, and is a registered Professional Engineer in the state of Texas.
Drilling Locations
The table below sets forth our total gross identified drilling locations by basin for our proved
undeveloped reserves as of December 31, 2021, excluding injection wells.
San Joaquin Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Los Angeles Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proved Drilling Locations
401
262
663
We use production data and experience gained from our development programs to identify and
prioritize our drilling inventory. Drilling locations are included in our reserves only after we have
adopted a development plan to drill them within a five-year time frame of the original reserve booking.
As a result of rigorous technical evaluation of geologic and engineering data, we can estimate with
reasonable certainty that reserves from these locations will be commercially recoverable in accordance
with SEC guidelines. Management considers the availability of local infrastructure, drilling support
assets, state and local regulations and other factors it deems relevant in determining such locations.
Our year-end development plans and associated proved undeveloped reserves are consistent with
SEC guidelines for development within five years. We believe we will have sufficient capital to develop
all year-end 2021 proved undeveloped reserves within five years of their original booking date.
17
Drilling Statistics
The following table sets forth information on our net exploration and development wells drilled and
completed during the periods indicated, regardless of when drilling was initiated. The information
should not be considered indicative of future performance, nor should it be assumed that there is
necessarily any correlation among the number of productive wells drilled, quantities of reserves found
or economic value. We refer to gross wells as the total number of wells in which interests are owned,
including outside operated wells. Net wells represent wells reduced to our fractional interest.
San Joaquin
Basin
Los Angeles
Basin
Ventura
Basin
Sacramento
Basin
Total Net
Wells
2021
Productive
Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
Development
—
109.4
Dry
Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
Development
2020
Productive
Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
Development
Dry
Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
Development
—
—
—
4.0
—
—
2019
Productive
Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
Development
0.3
117.5
Dry
Exploratory . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . .
Development
—
—
—
6.5
—
—
—
4.5
—
—
—
25.2
—
—
—
—
—
—
—
—
—
—
—
2.0
—
—
—
—
—
—
—
0.4
—
—
—
2.4
—
—
—
115.9
—
—
—
8.9
—
—
0.3
147.1
—
—
The following table sets forth information on our development wells where drilling was either in
progress or pending completion as of December 31, 2021.
Gross . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net
15.0
12.3
1.0
1.0
—
—
—
—
16.0
13.3
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 89% as of December 31, 2021. Wells are categorized based on the
primary product they produce.
18
The following table sets forth our productive oil and natural gas wells (both producing and capable
of production) as of December 31, 2021, excluding wells that have been idle for more than five years:
As of December 31, 2021
Productive Oil
Wells
Productive Natural Gas
Wells
Gross(a)
Net(b)
Gross(a)
Net(b)
7,577
1,725
56
—
9,358
44
6,732
1,635
56
—
8,423
51
152
—
—
755
907
8
141
—
—
696
837
5
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 2022 capital plan
does not allocate any capital towards exploration drilling. Although we do not anticipate exploration
drilling in the near term, we do have a portfolio of 65 exploration prospects in the San Joaquin and
Sacramento basins that we may pursue in the future. We also have an extensive 3D and 2D seismic
library that we use to develop and refine exploration prospects.
Carbon Management Business
In November 2021, our Board of Directors announced a Full Scope Net Zero Goal. As part of this
strategy, we intend to pursue CCS projects and believe our existing assets are well positioned to
support the development of these projects. In addition, our operations are in close proximity to
significant sources of carbon dioxide (CO2) emissions in California.
Through our subsidiary, Carbon TerraVault, we are in the early stages of developing several CCS
projects in California. Currently, we have applied for permits for two initial permanent CCS projects at
the Elk Hills Field. We are also in discussions with potential emitters to enter into joint venture or other
commercial arrangements with respect to Carbon TerraVault. Once completed, we expect that our
Carbon TerraVault CCS projects will inject CO2 captured from industrial sources into depleted
underground oil and natural gas reservoirs and permanently store CO2 deep underground. Separately,
we are also evaluating the feasibility of a carbon capture system to be located at our Elk Hills power
plant.
While all of these projects are in early stages and we do not consider the financial impact of our
carbon sequestration activities to be material to our operating and financial results for the year ended
December 31, 2021, we expect that the size and scope of our projects providing these and similar
services and capital spent on such projects will continue to grow given our strategy of expansion into
these services. For more information about the risks involved in our CCS projects, see Part I, Item 1A –
Risk Factors.
Human Capital
Our employees are our most important asset and we strive to provide a safe and healthy
workplace, development opportunities and financial rewards so that our employees remain engaged
and focused on providing safe, affordable and abundant energy for the communities in California.
19
Employee development opportunities are provided to enhance leadership development and expand
career opportunities. A copy of our policies are provided to all employees, who also undergo
mandatory annual training on the policies. Employer sponsored training reinforces our company-wide
commitment to operate in accordance with all applicable laws, rules and regulations and to sustain a
diverse and empowered workforce comprising our employees and those of our suppliers, vendors and
joint ventures. We provide our employees industry competitive base wages and incentive
compensation opportunities, as well as comprehensive health and retirement benefits; life, disability
and accident insurance coverages; and employee assistance and wellness programs to promote
financial stability and healthy lifestyles. We promote the health and well-being of our employees by
providing these comprehensive health benefits and time off for maternity and parental leave for the
adoption or birth of a child, illness and vacation. We also provide options for alternate work schedules,
flexible work hours, part-time work options and telecommuting.
As of December 31, 2021, we had approximately 970 employees, all in the United States.
Approximately 50 of our employees are covered by a collective bargaining agreement. We also utilize
the services of many third-party contractors throughout our operations.
Core Values
We believe our core values of Character, Responsibility and Commitment and our comprehensive
business and ethical conduct policies sustain and enhance shareholder value.
Our comprehensive business and ethical conduct policies apply to all directors, officers and
employees, each of whom personally commits to following our code of conduct and our corporate
policies, as well as to suppliers and vendors working in our operations. Our position is that no business
goal is worth our employees compromising their integrity or our shared values.
Diversity, Equity and Inclusion
Our goal is to foster a strong culture that promotes diversity, equity and inclusion and are
committed to advancing women and minorities in our workplace. We believe increasing diversity,
equity and inclusion will improve financial performance through better retention rates, higher
innovation, and increased productivity. Beginning in 2022, we plan to establish a diversity, equity and
inclusion executive council to oversee our initiatives and incorporate a quantitative metric that directly
impacts incentive compensation for all of our employees.
As of December 31, 2021, 19% of our employees and 18% of our senior managers were female.
Additionally, 38% of our employees and 21% of our senior managers were ethnically diverse.
Currently, 33% of our Board of Directors are female.
Employee Safety
Our unwavering commitment to safety and the environment defines how we operate our business.
We prepare our workforce to work safely through comprehensive training, on-the-job guidance and
tools and safety meetings. Each year, we set a threshold injury and illness incidence rate as a
quantitative metric that directly impacts incentive compensation for all of our employees. We have
achieved exemplary, steadily improved safety performance over the last several years by promoting a
culture of safety where all employees, contractors and vendors are empowered with Stop Work
Authority to cease any activity – without repercussions – to prevent a safety or environmental accident.
Engagement and Retention
We survey our employees annually to assess engagement levels and drivers to determine areas of
improvement to enhance engagement and retention. The results of the engagement surveys are
reviewed by senior management and our Board. The tightening labor market has not adversely
affected our operations and we continue to attract the talent needed to support our operations.
20
Marketing Arrangements
Crude Oil – We sell nearly all of our crude oil into the California refining markets. Substantially all of
our crude oil production is connected to third-party pipelines and California refining markets via our
gathering systems. We do not refine or process the crude oil we produce and do not have any significant
long-term transportation arrangements.
The prices paid by California refiners are typically based on local third-party indices that are closely
tied to Brent prices. International waterborne-based Brent prices are used because there is limited crude
pipeline infrastructure available to transport crude overland from other parts of the United States into
California. We believe that these limitations will continue to contribute to higher realizations in California
than most other U.S. oil markets for comparable grades.
Natural Gas – We sell all of our natural gas not used in our operations into the California markets on a
daily basis at average monthly index pricing. Natural gas prices and differentials are strongly affected by
local market fundamentals, such as storage capacity and the availability of transportation capacity in the
market and producing areas. Transportation capacity influences prices because California imports more
than 90% of its natural gas from other states and Canada. As a result, we typically enjoy higher
realizations relative to out-of-state producers due to lower transportation costs on the delivery of our
natural gas.
In addition to selling natural gas, we also use natural gas in steam generation for our steamfloods and
power generation. As a result, the positive impact of higher natural gas prices is partially offset by higher
operating costs of our steamflood projects and power generation, but higher prices still have a net
positive effect on our operating results due to net higher revenue. Conversely, lower natural gas prices
lower these operating costs but have a net negative effect on our financial results.
We currently hold transportation capacity contracts to transport all of our natural gas volumes for
multiple years.
NGLs – NGL prices vary by liquid type and realizations are closely correlated to the different
commodity prices to which they relate. Prices can also fluctuate due to the demand for certain chemical
products (for which NGLs are used as feedstock) and due to infrastructure constraints and seasonality.
Finally, our results are also affected by the performance of our natural gas-processing plants. We
process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to
pipelines and separately sell the remaining products as NGLs. The efficiency with which we extract
liquids from the wet gas stream affects our operating results. Our natural gas-processing plants also
facilitate access to third-party delivery points near the Elk Hills field.
We currently have a pipeline transportation contract for 6,500 barrels per day of NGLs. Our contract
to transport NGLs requires us to cash settle any shortfall between the committed quantities and volumes
actually shipped. We have met all our shipping commitments under this contract.
Electricity – A portion of the electrical output of the Elk Hills power plant is used by Elk Hills and other
nearby production fields. This provides a reliable source of power. We sell remaining electrical output to
the wholesale power market and a local utility. We also sell the remaining capacity to community choice
aggregates and local utilities.
Delivery Commitments
We have short-term commitments to certain refineries and other buyers to deliver oil, natural gas and
NGLs. As of December 31, 2021, we had oil delivery commitments of 52 MBbl/d through March 2022,
NGL delivery commitments of 12 MBbl/d through March 2022 and natural gas delivery commitments of
32 MMcf/d through October 2022. We generally have significantly more production than the amounts
committed for delivery and have the ability to secure additional volumes of products as needed. These
commitments are typically index-based contracts with prices set at the time of delivery.
21
Hedging
Our hedging strategy seeks to mitigate our exposure to commodity price volatility and ensure our
financial strength and liquidity by protecting our cash flows. Our Revolving Credit Facility includes
covenants that require us to maintain a certain level of hedges over our reasonably anticipated oil
production from our proved reserves. We have also entered into incremental hedges above and beyond
these requirements for some time periods and will continue to evaluate our hedging strategy based on
prevailing market prices and conditions.
Refer to Part II, Item 8 – Financial Statements and Supplementary Data, Note 7 Derivatives for more
information on our commodity contracts.
Our Principal Customers
We sell crude oil, natural gas and NGLs to marketers, California refineries and other purchasers that
have access to transportation and storage facilities. Our ability to sell our products can be affected by
factors that are beyond our control and cannot be accurately predicted.
We had three customers that individually accounted for at least 10%, and collectively accounted for
51%, of our sales (before the effects of hedging). These purchasers are in the crude oil refining industry.
In light of the ongoing energy deficit in California and the strong demand for native crude oil production,
we do not believe that the exit of any single customer from the market would have a material adverse
effect on our financial condition or results of operations at this time.
Title to Properties
As is customary in the oil and natural gas industry for acquired properties, we initially conduct a high-
level review of the title to our properties at the time of acquisition. Individual properties may be subject to
ordinary course burdens that we believe do not materially interfere with the use or affect the value of such
properties. Burdens on properties may include customary royalty or net profits interests, liens incident to
operating agreements and tax obligations or duties under applicable laws, or development and
abandonment obligations, among other items. Prior to the commencement of drilling operations on those
properties, we typically conduct a more thorough title examination and may perform curative work with
respect to significant defects. We generally will not commence drilling operations on a property until we
have cured known title defects that are material to the project. For additional information on properties
which secure our debt, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt.
Competition
Our competitors are primarily other exploration and production companies that produce oil, natural
gas and NGLs. We compete locally against small independent producers and major international oil
companies who operate in California. We also compete with foreign oil and gas companies because
California imports approximately 70% of the oil it consumes and virtually all of that arrives from
waterborne sources. We believe that our proximity to the California refineries gives us a competitive
advantage over importers due to lower transportation costs. Further, California refineries are generally
designed to process crude with similar characteristics to the oil produced from our fields. The California
natural gas market is serviced from a network of pipelines, including interstate and intrastate pipelines.
We deliver our natural gas to customers using our firm capacity contracts.
We compete for third-party services to profitably develop our assets, to find or acquire additional
reserves, to sell our production and to find and retain qualified personnel. Higher commodity prices could
intensify competition for drilling and workover rigs, pipe, other oil field equipment and personnel. At
current commodity price levels, we have experienced modest price increases for materials and services
as contracts are renewed. We believe our relative size and activity levels, compared to other in-state
producers, favorably influences the pricing we receive from third-party providers in the markets in which
we operate.
We face competition from other sources of energy, including wind and solar power. These products
compete directly with the electricity we generate from our power plants and indirectly as substitutes for
oil, natural gas and NGLs. We expect competition from these sources to intensify in the future due to
technological advances and as California continues to develop renewable energy and implements
climate-related policies.
22
Infrastructure
Our infrastructure, including plants and facilities owned by the Wilmington field and used in our
operations, 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) . . . . . . . . . .
Gathering Systems(e)
. . . . . . . . . . .
6
3
>30
>300
16
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-megawat cogeneration facility at Elk Hills that provides additional flexibility and reliability to support
field operations and a 48-megawatt power generating facility within our Long Beach operations in the Los Angeles basin.
(c) We own, control and operate water management and steam-generation infrastructure. We soften and self-supply water to
generate steam, reducing our operating costs. This is integral to our operations in the San Joaquin basin and supports our high-
margin oil fields.
(d) Our tank storage capacity throughout California gives us flexibility for a period of time to store crude oil and NGLs, allowing us to
continue production and avoid or delay any field shutdowns in the event of temporary power, pipeline or other shutdowns.
(e) Our gathering lines are dedicated almost entirely to collecting our oil and natural gas production and are in close proximity to
field-specific facilities such as tank settings or central processing sites. Our oil gathering systems connect to multiple third-party
transportation pipelines. In addition, virtually all of our natural gas facilities connect with major third-party natural gas pipeline
systems.
Regulation of the Oil and Natural Gas Industry
Our operations are subject to a wide range of federal, state and local laws and regulations. Those that
specifically relate to oil and natural gas exploration and production are described in this section.
Regulation of Exploration and Production
CalGEM is California’s primary regulator of the oil and natural gas industry on private and state lands,
with additional oversight from the State Lands Commission’s administration of state surface and mineral
interests. The Bureau of Land Management (BLM) of the U.S. Department of the Interior exercises similar
jurisdiction on federal lands in California, on which CalGEM also asserts jurisdiction over certain activities.
Government actions, including the issuance of certain permits or approvals, by state and local agencies or
by federal agencies may be subject to environmental reviews, respectively, under the California
Environmental Quality Act (CEQA) or the National Environmental Policy Act (NEPA), which may result in
delays, imposition of mitigation measures or litigation. CalGEM currently requires an operator to identify the
manner in which CEQA has been satisfied prior to issuing various state permits, typically through either an
environmental review or an exemption by a state or local agency. In Kern County this requirement has
typically been satisfied by complying with the local oil and gas ordinance, which was supported by an
Environmental Impact Report (EIR) certified by the Kern County Board of Supervisors in 2015. A group of
plaintiffs challenged the EIR and on February 25, 2020, a California Court of Appeal issued a ruling that
invalidates a portion of the EIR. Kern County circulated and certified a supplementary EIR to address the
ruling from the court and, thereafter, resumed issuing local permits relying on the revised Kern County EIR.
However, the trial court required that Kern County pause its local permitting system until the trial court has
reviewed the supplementary EIR and confirmed that it satisfied the concerns raised by the Court of Appeal.
A hearing is scheduled for April 2022. If the Kern County EIR is not reinstated or adequately modified
following resolution of the litigation described above, obtaining drilling permits for our operations in areas
where we do not have field or project specific CEQA coverage could be delayed or become more costly as
a result of compliance with CEQA. We believe that we currently have a sufficient inventory of drilling permits
for our anticipated operations; however, we cannot guarantee our ability to timely obtain additional permits
in the future.
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The California Legislature has significantly increased the jurisdiction, duties and enforcement
authority of CalGEM, the State Lands Commission and other state agencies with respect to oil and
natural gas activities in recent years. For example, 2019 state legislation expanded CalGEM’s duties
effective on January 1, 2020 to include public health and safety and reducing or mitigating greenhouse
gas emissions while meeting the state’s energy needs, and will require CalGEM to study and prioritize
idle wells with emissions, evaluate costs of abandonment, decommissioning and restoration, and
review and update associated indemnity bond amounts from operators if warranted, up to a specified
cap which may be shared among operators. Other 2019 legislation specifically addressed oil and
natural gas leasing by the State Lands Commission, including imposing conditions on assignment of
state leases, requiring lessees to complete abandonment and decommissioning upon the termination
of state leases, and prohibiting leasing or conveyance of state lands for new oil and natural gas
infrastructure that would advance production on certain federal lands such as national monuments,
parks, wilderness areas and wildlife refuges.
CalGEM and other state agencies have also significantly revised their regulations, regulatory
interpretations and data collection and reporting requirements. CalGEM issued updated regulations in
April 2019 governing management of idle wells and underground fluid injection, which include specific
implementation periods. The updated idle well management regulations require operators to either
submit annual idle well management plans describing how they will plug and abandon or reactivate a
specified percentage of long-term idle wells or pay additional annual fees and perform additional
testing to retain greater flexibility to return long-term idle wells to service in the future. The updated
underground injection regulations address injection approvals, project data requirements, testing of
injection wells, monitoring and reporting requirements with respect to injection parameters,
containment and incident response, among other topics.
In October 2021, CalGEM released for public comment public health regulations, which include
expanded land use setbacks of up to 3,200 feet from new wells in new surface locations. The proposed
regulation would also require pollution controls for existing wells and facilities within the same
3,200-foot setback area. CalGEM is currently in the process of conducting an economic analysis of the
proposed rule. Following this analysis, CalGEM will submit the proposed rule to the Office of
Administrative Law and begin an additional process of receiving comments and refinement of the
proposal as needed before a final rule can be issued. Litigation regarding any final rulemaking is also
expected.
Federal and state pipeline regulations have also been recently revised. CalGEM imposed more
stringent inspection and integrity management requirements in 2019 and 2020 with respect to certain
natural gas pipelines in specified locations, with additional regulations anticipated in 2022 regarding
digital mapping of such lines. The Office of the State Fire Marshal adopted regulations in 2020 to
require risk assessment of various oil lines in the coastal zone, followed by retrofitting of certain of
those lines with the best available control technology to mitigate oil spills over a specified
implementation period. Finally, the federal PHMSA has, from time to time, issued new regulations
expanding or otherwise revising pipeline integrity requirements. For example, in November 2021,
PHMSA issued a final rule imposing safety regulations on approximately 400,000 miles of previously
unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection
and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply
a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high
operating pressures.
In addition, certain local governments have proposed or adopted ordinances that would restrict
certain drilling activities in general and well stimulation, completion or injection activities in particular,
impose setback distances from certain other land uses, or ban such activities outright. For example,
both the City and the County of Los Angeles have voted to prohibit new oil and gas wells and phase
out existing wells over a number of years. These bans do not apply to our operations in unincorporated
areas of Los Angeles, and we do not anticipate a material impact from these bans to our future drilling
operations as we have no drilling plans or proved undeveloped reserves within the area that would be
covered by these bans. However, from time to time, other local governments in California have sought
to enact similar bans and others may seek to do so in the future. For example, a similar ban was
previously proposed in Monterey County, where we own mineral rights but have no production, before
being declared to be preempted by state and federal regulation. Other local governments have sought
to ban natural gas or the transportation of natural gas through their cities. The City of Antioch declined
to extend our franchise agreement for a natural gas pipeline through its city. Several companies,
including CRC, have challenged the city’s inconsistent and arbitrary approach to natural gas approvals.
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Collectively, the effect of these regulations is to potentially limit the number and location of our wells
and the amount of oil and natural gas that we can produce from our wells compared to what we
otherwise would be able to do.
Regulation of Health, Safety and Environmental Matters
Numerous federal, state, local and other laws and regulations that govern health and safety, the
release or discharge of materials, land use or environmental protection may restrict the use of our
properties and operations, increase our costs or lower demand for or restrict the use of our products
and services. Applicable federal health, safety and environmental laws include the Occupational Safety
and Health Act, Clean Air Act, Clean Water Act, Safe Drinking Water Act, Oil Pollution Act, Natural Gas
Pipeline Safety Act, Pipeline Safety Improvement Act, Pipeline Safety, Regulatory Certainty, and Job
Creation Act, Endangered Species Act, Migratory Bird Treaty Act, Comprehensive Environmental
Response, Compensation, and Liability Act, Resource Conservation and Recovery Act and NEPA,
among others. California imposes additional laws that are analogous to, and often more stringent than,
such federal laws. These laws and regulations:
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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;
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• may expose us to litigation with government authorities, counterparties, special interest groups
or others; and
• may restrict our rate of oil, NGLs, natural gas and electricity production.
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Due to the risk of future drought conditions in California, water districts and the state government
have implemented regulations and policies that may restrict groundwater extraction and water usage and
increase the cost of water. Water management, including our ability to recycle, reuse and dispose of
produced water and our access to water supplies from third-party sources, in each case at a reasonable
cost, in a timely manner and in compliance with applicable laws, regulations and permits, is an essential
component of our operations to produce crude oil, natural gas and NGLs economically and in commercial
quantities. As such, any limitations or restrictions on wastewater disposal or water availability could have
an adverse impact on our operations. We treat and reuse water that is co-produced with oil and natural
gas for a substantial portion of our needs in activities such as pressure management, waterflooding,
steamflooding and well drilling, completion and stimulation. We also provide reclaimed produced water to
certain agricultural water districts. We also use supplied water from various local and regional sources,
particularly for power plants and steam generation, and while our production to date has not been
impacted by restrictions on access to third-party water sources, we cannot guarantee that there may not
be restrictions in the future.
In 2014, at the request of the EPA, CalGEM commenced a detailed review of the multi-decade
practice of permitting underground injection wells and associated aquifer exemptions under the SDWA. In
2015, the state set deadlines to obtain the EPA’s confirmation of aquifer exemptions under the SDWA in
certain formations in certain fields. Since the state and the EPA did not complete their review before the
state’s deadlines, the state announced that it will not rescind permits or enforce the deadlines with
respect to many of the formations pending completion of the review but has applied the deadlines to
others. Several industry groups and operators challenged CalGEM’s implementation of its aquifer
exemption regulations. In March 2017, the Kern County Superior Court issued an injunction barring the
blanket enforcement of CalGEM’s aquifer exemption regulations. The court found that CalGEM must find
actual harm results from an injection well’s operations and go through a hearing process before the
agency can issue fines or shut down operations. During the review, the state has restricted injection in
certain formations or wells in several fields, including some operated by us, requested that we change
injection zones in certain fields, and held certain pending injection permits in abeyance. We are
coordinating with the state to change injection zones in certain fields to facilitate disposal of produced
water in deeper formations where feasible or to increase recycling of produced water in pressure
maintenance or waterfloods in lieu of disposal. In September 2021, the EPA issued a letter to the
California Natural Resources Agency and the State Water Resources Control Board regarding the state’s
compliance with the 2015 compliance plan relating to the state’s process for approving aquifer
exemptions under the SDWA. The letter requested that California take appropriate action by September
2022, or the EPA would consider taking additional action to impose limits on California’s administration of
the UIC program, withhold federal funds for the administration of the UIC program, and direct orders to oil
and gas operators injecting into formations not authorized by EPA, among other measures. The state
responded in October 2021 with a proposed compliance plan but, to date, EPA has not yet responded.
Federal, state and local agencies may assert overlapping authority to regulate in these areas. In
addition, certain of these laws and regulations may apply retroactively and may impose strict or joint
and several liability on us for events or conditions over which we and our predecessors had no control,
without regard to fault, legality of the original activities, or ownership or control by third parties.
Regulation of Climate Change and Greenhouse Gas (GHG) Emissions
A number of international, federal, state, regional and local efforts seek to prevent or mitigate the
effects of climate change or to track, mitigate and reduce GHG emissions associated with energy use
and industrial activity, including operations of the oil and natural gas production sector and those who
use our products as a source of energy or feedstocks. President Biden has announced that climate
change will be a focus of his administration, and he has issued several executive orders on the subject,
which, among other things, recommitted the United States to the Paris Agreement, called for the
reinstatement or issuance of methane emissions standards for new, modified and existing oil and gas
facilities and called for an increased emphasis on climate-related risk across governmental agencies
and economic sectors. Additionally, the EPA has adopted federal regulations to:
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require reporting of annual GHG emissions from oil and natural gas exploration and production,
power plants and natural gas processing plants; gathering and boosting compression and
pipeline facilities; and certain completions and workovers;
incorporate measures to reduce GHG emissions in permits for certain facilities; and
restrict GHG emissions from certain mobile sources.
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California has adopted stringent laws and regulations to reduce GHG emissions. These state laws
and regulations:
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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
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resources by 2030;
established a policy to derive all of California’s retail electricity from renewable or “zero-carbon”
resources by 2045, subject to required evaluation of the feasibility by state agencies;
imposed state goals to double the energy efficiency of buildings by 2030 and to reduce emissions
of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013 levels by 2030;
and
• mandated that all new single family and low–rise multifamily housing construction in California
include rooftop solar systems or direct connection to a state–approved community solar system.
In addition, the current and former Governors of California and certain municipalities in California have
announced their commitment to adhere to GHG reductions called for in the Paris Agreement through
executive orders, pledges, resolutions and memoranda of understanding or other agreements with
various other countries, U.S. states, Canadian provinces and municipalities. In furtherance of this
commitment, in September 2020, the Governor of California issued an executive order directing several
agencies to take further actions with respect to reducing emissions of GHGs. The Governor has also
directed state agencies to implement other measures to mitigate climate change and strengthen
biodiversity, such as via the conservation of 30% of state lands and waters by 2030. For more
information, see Part I, Item 1A – Risk Factors.
The EPA and the California Air Resources Board (CARB) have also expanded direct regulation of
methane as a contributor to GHG emissions. In 2016, the EPA adopted regulations to require additional
emission controls for methane, volatile organic compounds and certain other substances for new or
modified oil and natural gas facilities. Although the EPA rescinded the methane-specific requirements for
production and processing facilities in September 2020, the U.S. Congress subsequently approved, and
President Biden signed into a law, a resolution to repeal the September 2020 revisions to the methane
standards, effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a
proposed rule that, if finalized, would establish new source and first-time existing source standards of
performance for methane and volatile organic compound emissions for oil and gas facilities. The EPA
plans to issue a supplemental proposal in 2022 containing additional requirements not included in the
November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year.
Moreover, CARB has implemented more stringent regulations that require monitoring, leak detection,
repair and reporting of methane emissions from both existing and new oil and natural gas production,
pipeline gathering and boosting facilities and natural gas processing plants, as well as additional controls
such as tank vapor recovery to capture methane emissions.
Regulation of Transportation, Marketing and Sale of Our Products
Our sales prices of oil, NGLs and natural gas in the U.S. are set by the market and are not presently
regulated. In 2015, the U.S. federal government lifted restrictions on the export of domestically produced
oil that allows for the sale of U.S. oil production, including ours, in additional markets.
Federal and state laws regulate transportation rates for, and marketing and sale of, petroleum
products and electricity with respect to certain of our operations and those of certain of our customers,
suppliers and counterparties. Such regulations also govern:
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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;
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• market transparency rules with respect to natural gas and power markets;
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the physical and futures energy commodities market, including financial derivative and hedging
activity; and
prevention of discrimination in natural gas gathering operations in favor of producers or sources
of supply.
The federal and state agencies overseeing these regulations have substantial rate-setting and
enforcement authority, and violation of the foregoing regulations could expose us to litigation with
government authorities, counterparties, special interest groups and others.
International treaties and regulations also affect the marketing or sale of our products. For example,
on January 1, 2020, the International Maritime Organization reduced the maximum sulfur content in
marine fuels from 3.5% to 0.5% by weight under the International Convention for the Prevention of
Pollution from Ships. Under this IMO 2020 rule, ships must either switch to low-sulfur fuels or install
scrubbing facilities for emission controls, which may affect the price of and demand for varying grades
of crude oil, both internationally and in California.
In addition, mandates or subsidies have been adopted or proposed by the state and certain local
governments to require or promote renewable energy or electrification of transportation, appliances
and equipment, or prohibit or restrict the use of petroleum products, by our customers or the public.
For example, in January 2020, the California Public Utilities Commission (CPUC) commenced a
rulemaking to develop a long-term natural gas planning strategy to ensure safe and reliable gas
systems at just and reasonable rates during what it describes as a 25-year transition from natural
gas-fueled technologies to meet the state’s GHG goals. In addition, several municipalities in California
enacted ordinances in 2019 that restrict the installation of natural gas appliances and infrastructure in
new residential or commercial construction, which could affect the retail natural gas market of our utility
customers and the demand and prices we receive for the natural gas we produce. Several of these
ordinances face legal challenges.
Available Information
We make available, free of charge on our website www.crc.com, our Annual Reports on Form 10-K,
Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Definitive Proxy Statements and
amendments to those reports filed or furnished, if any, as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the SEC. Unless otherwise provided herein,
information contained on our website is not part of this report. The SEC maintains an internet site,
http://www.sec.gov, that contains reports, proxy and information statements, and other information
regarding issuers that file electronically with the SEC.
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ITEM 1A
RISK FACTORS
Described below are certain risks and uncertainties that could adversely affect our business, financial
condition, results of operations or cash flow. These risks are not the only risks we face. Our business could
also be affected materially and adversely by other risks and uncertainties that are not currently known to us
or that we currently deem to be insignificant.
Summary:
Risks Related to Our Business
• Prices for our products can fluctuate widely and an extended period of low prices could materially
and adversely affect our financial condition, results of operations, cash flow and ability to invest in
our assets.
• We are subject to economic downturns and the effects of public health events, such as the
COVID-19 pandemic, which may materially and adversely affect the demand and the market prices
for our products.
• Our aspirations, goals and initiatives related to carbon management activities and our Full Scope Net
Zero target and our public statements and disclosures regarding them expose us to numerous risks.
• Our ability to establish a large-scale carbon capture and sequestration project is subject to numerous
risks and uncertainties. If we are unable to successfully execute our carbon capture and
sequestration strategy, it could have a material adverse effect on our business, results of operations
and financial condition and our ability to achieve our Full-Scope Net Zero goals.
• Drilling for and producing oil and natural gas carry significant operational and financial risks and
uncertainty. We may not drill wells at the times we scheduled, or at all. Wells we do drill may not
yield production in economic quantities or generate the expected payback.
• Our business can involve substantial capital investments. We may be unable to fund these
investments which could lead to a decline in our oil and natural gas reserves or production. Our
capital investment program is also susceptible to risks that could materially affect its implementation.
• From time to time we may engage in exploratory drilling, including drilling in new or emerging plays.
Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is
unsuccessful.
• Our producing properties are located exclusively in California, making us vulnerable to economic and
regulatory factors associated with having operations concentrated in this geographic area.
• Many of our current and potential competitors have or may potentially have greater resources than
we have and we may not be able to successfully compete in acquiring, exploring and developing
new properties.
• Our hedging activities may limit our ability to realize the full benefits of increases in commodity
prices.
• Our level of hedging activities may be impacted by financial regulations that could increase our costs
of hedging and/or limit the number of hedging counterparties available to us.
• Estimates of proved reserves and related future net cash flows are not precise. The actual quantities
of our proved reserves and future net cash flows may prove to be lower than estimated.
Risks Related to Regulation and Government Action
• Recent and future actions by the state of California could reduce both the demand for and supply of
oil and natural gas within the state.
• Our business is highly regulated and government authorities can delay or deny permits and
approvals or change requirements governing our operations any of which could increase costs,
restrict operations and change or delay the implementation of our business plans.
• Concerns about climate change and other air quality issues may prompt governmental action that
could materially affect our operations or results.
• Adverse tax law changes may affect our operations.
Risks Related to our Indebtedness
• Our existing and future indebtedness may adversely affect our business and limit our financial
flexibility.
• We may not be able to generate sufficient cash to service all of our indebtedness and may be forced
to take other actions to satisfy the obligations under our indebtedness, which may not be successful.
• The lenders under our Revolving Credit Facility could limit our ability to borrow and restrict our ability
to use or access to capital.
• Restrictive covenants in our Revolving Credit Facility and the indenture governing our Senior Notes
may limit our financial and operating flexibility.
• Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate risk, which
could cause our debt service obligations to increase significantly.
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Risks Related to Our Common Stock
• Our ability to pay dividends and repurchase shares of our common stock is subject to certain risks.
• The trading price of our common stock may decline, and you may not be able to resell shares of
our common stock at prices equal to or greater than the price you paid or at all.
• Future issuances of our common stock could reduce our stock price, and any additional capital
raised by us through the sale of equity or convertible securities may dilute your ownership in us.
• There is an increased potential for short sales of our common stock due to the sales of shares
issued upon exercise of warrants, which could materially affect the market prices of the stock.
• The ownership position of certain of our stockholders limits other stockholders’ ability to influence
corporate matters and could affect the price of our common stock.
General Risk Factors
Increasing attention to ESG matters may adversely impact our business.
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• 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:
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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;
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• worldwide drilling and exploration activities;
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• weather conditions and other seasonal impacts;
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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:
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reducing our proved oil and natural gas reserves over time
limiting our ability to grow or maintain future production
causing a reduction in our borrowing base under our Revolving Credit Facility, which could affect
our liquidity;
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•
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reducing our ability to make interest payments or maintain compliance with financial covenants
in the agreements governing our indebtedness, which could trigger mandatory loan repayments
and default and foreclosure by our lenders and bondholders against our assets;
affecting our ability to attract counterparties and enter into commercial transactions, including
hedging, surety or insurance transactions; and
limiting our access to funds through the capital markets and the price we could obtain for asset
sales or other monetization transactions.
Our hedging program does not provide downside protection for all of our production. As a result,
our hedges do not fully protect us from commodity price declines, and we may be unable to enter into
acceptable additional hedges in the future.
We are subject to economic downturns and the effects of public health events, such as the
COVID-19 pandemic, which may materially and adversely affect the demand and the market
price for our products.
The COVID-19 pandemic has adversely affected the global economy, and has resulted in, among
other things, travel restrictions, business closures and the institution of quarantining and other
mandated and self-imposed restrictions on movement. We do not know how long these conditions will
last. The severity, magnitude and duration of COVID-19 or another pandemic, the extent of actions that
have been or may be taken to contain or treat their impact, and the impacts on the economy generally
and oil prices in particular, are uncertain, rapidly changing and hard to predict. This uncertainty could
force us to reduce costs, including by decreasing operating expenses and lowering capital
expenditures, and such actions could negatively affect future production and our reserves. We may
experience labor shortages if our employees are unwilling or unable to come to work because of
illness, quarantines, government actions or other restrictions in connection with the pandemic. If our
suppliers cannot deliver the materials, supplies and services we need, we may need to suspend
operations. In addition, we are exposed to changes in commodity prices which have been and will
likely remain volatile. We cannot predict the duration and extent of the pandemic’s adverse impact on
our operating results.
Additionally, to the extent the COVID-19 pandemic or any resulting worsening of the global
business and economic environment adversely affects our business and financial results, it may also
have the effect of heightening or exacerbating many of the other risks described in the “Risk Factors”
herein.
Our aspirations, goals, and initiatives related to carbon management activities and our Full
Scope Net Zero target, and our public statements and disclosures regarding them, expose us to
numerous risks.
We have developed, and will continue to develop and set, goals, targets, and other objectives
related to sustainability matters, including our Full Scope Net Zero target and our energy transition
strategy. Statements related to these goals, targets and objectives reflect our current plans and do not
constitute a guarantee that they will be achieved. Our efforts to research, establish, accomplish, and
accurately report on these goals, targets, and objectives expose us to numerous operational,
reputational, financial, legal, and other risks. Our ability to achieve any stated goal, target, or objective,
including with respect to emissions reduction, is subject to numerous factors and conditions, some of
which are outside of our control. In particular, our 2045 Full-Scope Net Zero goal includes Scope 1, 2
and 3 emissions and estimation and management of Scope 3 emissions is subject to some degree of
uncertainty. We cannot guarantee that we have been able to completely quantify the full scope of our
emissions and account for mitigating all such emissions in our Full-Scope Net Zero goal.
Our business may face increased scrutiny from investors and other stakeholders related to our
sustainability activities, including the goals, targets, and objectives that we announce, and our
methodologies and timelines for pursuing them. If our sustainability practices do not meet investor or
other stakeholder expectations and standards, which continue to evolve, our reputation, our ability to
attract or retain employees, and our attractiveness as an investment or business partner could be
negatively affected. Similarly, our failure or perceived failure to pursue or fulfill our sustainability-
focused goals, targets, and objectives, to comply with ethical, environmental, or other standards,
regulations, or expectations, or to satisfy various reporting standards with respect to these matters,
within the timelines we announce, or at all, could adversely affect our business or reputation, as well as
expose us to government enforcement actions and private litigation.
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Our ability to establish a large scale carbon capture and sequestration project is subject to
numerous risks and uncertainties. If we are unable to successfully execute our CCS strategy, it
could have a material adverse effect on our business, results of operations and financial
condition and our ability to achieve our Full-Scope Net Zero goals.
We have announced a strategy to pursue various carbon emissions reduction efforts, including CCS
projects such as Carbon TerraVault. To our knowledge, there are no existing large scale carbon capture
projects in California of the type contemplated by Carbon TerraVault or CalCapture. These projects face
operational, technological and regulatory risks that could be considerable due to early stage nature of
these projects and the sector generally. Our ability to successfully develop these projects depends on a
number of factors that we are not able to fully control, including the following:
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Large scale carbon capture is an emerging sector and there are not substantial precedents to
gauge the likely range of structures or economic terms that will be necessary to reach agreeable
terms.
• The development of a CCS project may require us to enter into long term joint ventures with large
carbon emitters and operators of infrastructure for transporting CO2 (or other GHGs) and we may
not be able to do so on agreeable terms or at all.
• Not all facilities produce sufficiently large quantities of pure or relatively pure streams of CO2, or
have installed equipment to capture such CO2, so as to be usable in one or more of our CCS
projects.
• Our CCS projects are expected to have material capital requirements and there is no certainty that
we will be able to finance these projects on reasonable terms.
• To the extent CO2 transportation pipelines are not present in proposed project areas, or if they do
not extend to one or more of our project sites, we may be required to convert existing pipelines, or
build new CO2 pipelines or lateral connections, which will require much larger capital expenditures
and may be subject to various environmental and other permitting requirements as well as third
party easements that could be difficult to obtain, which may render one or more projects
uneconomical or impractical. Additionally, even in areas where such pipelines are in place, our use
of them may require reaching agreements on CO2 transportation with operators of the pipelines.
• The economics of CCS projects depend on financial and tax incentives that may not currently be
sufficient for our CCS projects to be economical or could be changed or terminated. Congress has
incentivized the development of carbon capture projects through the establishment of the Internal
Revenue Code Section 45Q tax credit (45Q) for carbon sequestration. Recent Internal Revenue
Service guidance and regulations on this tax credit are intended to provide increased certainty for
the industry by establishing processes and standards to secure geologic storage of CO2. However,
additional financial incentives may be required for our CCS projects to be economical. In
particular, we anticipate that CCS projects associated with carbon emission reductions for
transportation fuels will generate LCFS credits and that these additional credits will improve the
economics of CCS projects. If the existing legal requirements for incentives such as 45Q or LCFS
are subsequently amended in a manner that such incentives no longer apply or are restricted in
application to our projects, we may not be able to successfully achieve an economic return from
our CCS business or, alternatively, the construction of operation of applicable projects may be
substantially delayed such that one or more projects is unprofitable or otherwise infeasible.
• CCS projects will require storage of CO2 in subterranean reservoirs over long periods of time. If
accidental releases or subsurface migration of CO2 from our CCS activities were to occur in the
course of operating one or more of our CCS sites, there is the risk of recapture of 45Q tax credits
or LCFS credits from us by the government, as well as a risk of trespass or other tort claims
related to the accidental release or migration of CO2 beyond the boundaries of any anticipated
project’s approved area and potential for fines and penalties for violations of environmental
requirements.
• Successful development of CCS projects in the United States require that we comply with what we
anticipate will be a stringent regulatory scheme requiring that we obtain certain permits applicable
to subsurface injection of CO2 for geologic sequestration. Moreover, as operator of our CCS
projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the
cost of corrective action, injection well plugging, post injection site care and site closure, and
emergency and remedial response. There is no assurance that we will be successful in obtaining
permits or adequate levels of financial assurance for one or more of our CCS projects or that
permits can be obtained on a timely basis, whether due to difficulty with the technical
demonstrations required to obtain such permits, public opposition, or otherwise.
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• Separately, permitting CCS projects requires obtaining a number of other permits and approvals
unrelated to subsurface injection from various U.S. federal and state agencies, such as for air
emissions or impacts to environmental, natural, historic or cultural resources resulting from the
construction and operation of a CCS facility. We cannot guarantee that we will be able to obtain all
applicable permits for CCS activities on a timely basis or on favorable terms.
• As CCS and carbon management represent an emerging sector, regulations may evolve rapidly,
which could impact the feasibility of one or more of our anticipated projects. To the extent regulatory
requirements are imposed, are amended, or more stringently enforced, we may incur additional
costs in the pursuit of one or more of our carbon capture projects, which costs may be material or
may render any one or more of our projects uneconomical.
• We may not own the pore space at all of our CCS project sites, which may require us to enter into
agreements with a group of owners for the real estate covering the extent of the project.
• Complex recordkeeping and GHG emissions/sequestration accounting may be required in
connection with one or more of our projects, which may increase the costs of such operations.
Different methodologies may be required for various regulatory and non-regulatory accounts
regarding GHG emissions/sequestration at one or more of our projects, including but not limited to
compliance with the EPA’s Mandatory Greenhouse Gas Reporting Program.
• Carbon capture may be viewed as a pathway to the continued use of fossil fuels, notwithstanding
that CO2 emissions are intended to be captured, there may be organized opposition to carbon
capture, including our projects, from certain environmental groups.
There can be no assurances that we will successfully develop our CCS projects, including Carbon
Terravault and CalCapture, and such failure could have a material adverse effect on our liquidity, financial
condition and results of operations. If we are not able to successfully develop these projects, our ability to
achieve our 2045 Full-Scope Net Zero goal for Scope 1, 2 and 3 emissions would also be materially and
adversely affected.
Drilling for and producing oil and natural gas carry significant operational and financial risks
and uncertainty. We may not drill wells at the times we scheduled, or at all. Wells we do drill may
not yield production in economic quantities or generate the expected payback.
The exploration and development of oil and natural gas properties depend in part on our analysis of
geophysical, geologic, engineering, production and other technical data and processes, including the
interpretation of 3D seismic data. This analysis is often inconclusive or subject to varying interpretations. We
also bear the risks of equipment failures, accidents, environmental hazards, unusual geological formations
or unexpected pressure or irregularities within formations, adverse weather conditions, permitting or
construction delays, title disputes, surface access disputes, disappointing drilling results or reservoir
performance (including lack of production response to workovers or improved and enhanced recovery
efforts) and other associated risks.
Our decisions and ultimate profitability are also affected by commodity prices, the availability of capital,
regulatory approvals, available transportation and storage capacity, the political environment and other
factors. Our cost of drilling, completing, stimulating, equipping, operating, inspecting, maintaining and
abandoning wells is also often uncertain.
Any of the forgoing operational or financial risks could cause actual results to differ materially from the
expected payback or cause a well or project to become uneconomic or less profitable than forecast.
We have specifically identified locations for drilling over the next several years, which represent a
significant part of our long-term growth strategy. Our actual drilling activities may materially differ from those
presently identified. If future drilling results in these projects do not establish sufficient production and
reserves to achieve an economic return, we may curtail drilling or development of these projects. We make
assumptions about the consistency and accuracy of data when we identify these locations that may prove
inaccurate. We cannot guarantee that our identified drilling locations will ever be drilled or if we will be able
to produce crude oil or natural gas from these drilling locations. In addition, some of our leases could expire
if we do not establish production in the leased acreage. The combined net acreage covered by leases
expiring in the next three years represented 13% of our total net undeveloped acreage at December 31,
2021.
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Our business involves substantial capital investments, which may include acquisitions,
partnerships or joint venture arrangements with other oil and gas exploration and production
companies or financial investors. We may be unable to fund our capital program, or reach
satisfactory terms for other future capital requirements, which could lead to a decline in our oil
and natural gas reserves or production. Our capital investment program is also susceptible to
risks that could materially affect its implementation.
Our exploration, development and acquisition activities can involve substantial capital investments.
We intend to fund our 2022 capital program using cash flow from operations. Accordingly, a reduction in
projected operating cash flow could cause us to reduce our future capital investments. In general, the
ability to execute our capital plan depends on a number of factors, including:
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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
the availability under our Revolving Credit Facility and external sources of financing.
Access to future capital may be limited by our lenders, capital markets constraints, activist funds or
investors, or poor stock price performance. Because of these and other potential variables, we may be
unable to deploy capital in the manner planned, which may negatively impact our production levels and
development activities and limit our ability to make acquisitions or enter into partnerships and farmout
arrangements.
Unless we make sufficient capital investments and conduct successful development and exploration
activities or acquire properties containing proved reserves, our proved reserves will decline as those
reserves are produced. Our ability to make the necessary long-term capital investments or acquisitions
needed to maintain or expand our reserves may be impaired to the extent we have insufficient cash flow
from operations or liquidity to fund those activities. Over the long term, a continuing decline in our
production and reserves would reduce our liquidity and ability to satisfy our debt obligations by reducing
our cash flow from operations and the value of our assets.
From time to time we may engage in exploratory drilling, including drilling in new or emerging
plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if
drilling is unsuccessful.
The risk profile for our exploration drilling locations is higher than for other locations because we have
less geologic and production data and drilling history, in particular for those exploration drilling locations in
unconventional reservoirs, which are in unproven geologic plays. Our ability to profitably drill and develop
our identified drilling locations depends on a number of variables, including crude oil and natural gas
prices, capital availability, costs, drilling results, regulatory approvals, available transportation capacity
and other factors. We may not find commercial amounts of oil or natural gas or the costs of drilling,
completing, stimulating and operating wells in these locations may be higher than initially expected. If
future drilling results in these projects do not establish sufficient reserves to achieve an economic return,
we may curtail drilling or development of these projects. In either case, the value of our undeveloped
acreage may decline and could be impaired.
Our producing properties are located exclusively in California, making us vulnerable to risks
associated with having operations concentrated in this geographic area.
Our operations are concentrated in California. Because of this geographic concentration, the success
and profitability of our operations may be disproportionately exposed to the effect of regional conditions.
These include local price fluctuations, changes in state or regional laws and regulations affecting our
operations and other regional supply and demand factors, including gathering, pipeline, transportation
and storage capacity constraints, limited potential customers, infrastructure capacity and availability of
rigs, equipment, oil field services, supplies and labor. Our operations are also exposed to natural
disasters and related events common to California, such as wildfires, mudslides, high winds and
earthquakes. Further, our operations may be exposed to power outages, mechanical failures, industrial
accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be
shut in, delay operations and growth plans, decrease cash flows, increase operating and capital costs,
prevent development of lease inventory before expiration and limit access to markets for our products.
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Many of our current and potential competitors have or may potentially have greater
resources than we have and we may not be able to successfully compete in acquiring,
exploring and developing new properties.
We face competition in every aspect of our business, including, but not limited to, acquiring
reserves and leases, obtaining goods and services and hiring and retaining employees needed to
operate and manage our business and marketing natural gas, NGLs or oil. Competitors include
multinational oil companies, independent production companies and individual producers and
operators. In California, our competitors are few and large, which may limit available acquisition
opportunities. Many of our competitors have greater financial and other resources than we do. As a
result, these competitors may be able to address such competitive factors more effectively than we can
or withstand industry downturns more easily than we can.
Our hedging activities limit our ability to realize the full benefits of increases in commodity
prices.
We enter into hedges to mitigate our economic exposure to commodity price volatility and ensure
our financial strength and liquidity by protecting our cash flows. Our Revolving Credit Facility also
includes covenants that require us to maintain a certain level of hedges and we currently have entered
into incremental hedges above these requirements for certain time periods. These hedges expose us
to the risk of financial losses depending on commodity price movements and may prevent us from
realizing the full benefits of price increases. Our ability to realize the benefits of our hedges also
depends in part upon the counterparties to these contracts honoring their financial obligations. If any of
our counterparties are unable to perform their obligations in the future, we could be exposed to
increased cash flow volatility that could affect our liquidity.
Our level of hedging activities may be impacted by financial regulations that could increase
our costs of hedging and/or limit the number of hedging counterparties available to us.
U.S. financial regulations can impact both our level of hedging activity as well as the potential cost
of entering into hedges. In particular, the Dodd-Frank Wall Street Reform and Consumer Protection Act
(Dodd-Frank Act), enacted in 2010, established federal oversight and regulation of the
over-the-counter (OTC) derivatives market and entities, like us, that participate in that market. Among
other things, the Dodd-Frank Act required the U.S. Commodity Futures Trading Commission to
promulgate a range of rules and regulations applicable to OTC derivatives transactions. These
regulations can affect both the size of positions that we may enter and the ability or willingness of
counterparties to trade opposite us.
In addition, U.S. regulators adopted a final rule in November 2019 implementing a new approach
for calculating the exposure amount of derivative contracts under the applicable agencies’ regulatory
capital rules, referred to as the standardized approach for counterparty credit risk (SA-CCR). Certain
financial institutions are required to comply with the new SA-CCR rules beginning on January 1, 2022.
The new rules could significantly increase the capital requirements for some of our hedge
counterparties in the OTC derivatives market. These increased capital requirements could result in
significant additional costs being passed through to end users like us or reduce the number of
participants or products available to us in the OTC derivatives market.
The European Union and other non-U.S. jurisdictions may implement regulations with respect to the
derivatives market. To the extent we transact with counterparties in foreign jurisdictions or
counterparties with other businesses that subject them to regulation in foreign jurisdictions, we may
become subject to or otherwise impacted by such regulations, which could also adversely affect our
hedging opportunities.
Estimates of proved reserves and related future net cash flows are not precise. The actual
quantities of our proved reserves and future net cash flows may prove to be lower than
estimated.
Many uncertainties exist in estimating quantities of proved reserves and related future net cash
flows. Our estimates are based on various assumptions that require significant judgment in the
evaluation of available information. Our assumptions may ultimately prove to be inaccurate.
Additionally, reservoir data may change over time as more information becomes available from
development and appraisal activities.
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Our ability to add reserves, other than through acquisitions, depends on the success of improved
recovery, extension and discovery projects, each of which depends on reservoir characteristics,
technology improvements and oil and natural gas prices, as well as capital and operating costs. Many
of these factors are outside management’s control and will affect whether the historical sources of
proved reserves additions continue to provide reserves at similar levels.
Generally, lower prices adversely affect the quantity of our reserves as those reserves expected to
be produced in later years, which tend to be costlier on a per unit basis, become uneconomic. In
addition, a portion of our proved undeveloped reserves may no longer meet the economic producibility
criteria under the applicable rules or may be removed due to a lower amount of capital available to
develop these projects within the SEC-mandated five-year limit.
In addition, our reserves information represents estimates prepared by internal engineers. Although
over 80% of our estimated proved reserve volumes as of December 31, 2021 were audited by our
independent petroleum engineers, Ryder Scott and NSAI, we cannot guarantee that the estimates are
accurate.
Reserves estimation is a partially subjective process of estimating accumulations of oil and natural
gas. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows
from those reserves depend upon a number of variables and assumptions, including:
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historical production from the area compared with production from similar areas;
the quality, quantity and interpretation of available relevant data;
commodity prices;
production and operating costs;
ad valorem, excise and income taxes;
development costs;
the effects of government regulations; and
future workover and facilities costs.
Changes in these variables and assumptions could require us to make significant negative reserves
revisions, which could affect our liquidity by reducing the borrowing base under our Revolving Credit
Facility. In addition, factors such as the availability of capital, geology, government regulations and
permits, the effectiveness of development plans and other factors could affect the source or quantity of
future reserves additions.
Risks Related to Regulation and Government Action
Recent and future actions by the state of California could reduce both the demand for and
supply of oil and natural gas within the state.
In September 2020, Governor Gavin Newsom of California issued an executive order (Order) that
seeks to reduce both the demand for and supply of petroleum fuels in the state. The Order establishes
several goals and directs several state agencies to take certain actions with respect to reducing
emissions of GHGs, including, but not limited to: phasing out the sale of new emissions-producing
passenger vehicles, drayage trucks and off-road vehicles by 2035 and, to the extent feasible, medium
and heavy duty trucks by 2045; developing strategies for the closure and repurposing of oil and gas
facilities in California; and proposing legislation to end the issuance of new hydraulic fracturing permits
in the state by 2024.
Our business is highly regulated and government authorities can delay or deny permits and
approvals or change requirements governing our operations, including hydraulic fracturing and
other well stimulation methods, enhanced production techniques and fluid injection or
disposal, that could increase costs, restrict operations and change or delay the implementation
of our business plans.
Our operations are subject to complex and stringent federal, state, local and other laws and
regulations relating to the exploration and development of our properties, as well as the production,
transportation, marketing and sale of our products.
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To operate in compliance with these laws and regulations, we must obtain and maintain permits,
approvals and certificates from federal, state and local government authorities for a variety of activities
including siting, drilling, completion, stimulation, operation, inspection, maintenance, transportation,
storage, marketing, site remediation, decommissioning, abandonment, protection of habitat and
threatened or endangered species, air emissions, disposal of solid and hazardous waste, fluid injection
and disposal and water consumption, recycling and reuse. Failure to comply may result in the
assessment of administrative, civil and/or criminal fines and penalties, liability for noncompliance, costs
of corrective action, cleanup or restoration, compensation for personal injury, property damage or other
losses, and the imposition of injunctive or declaratory relief restricting or prohibiting certain operations
or our access to property, water, minerals or other necessary resources, and may otherwise delay or
restrict our operations and cause us to incur substantial costs. Under certain environmental laws and
regulations, we could be subject to strict or joint and several liability for the removal or remediation of
contamination, including on properties over which we and our predecessors had no control, without
regard to fault, legality of the original activities, or ownership or control by third parties. Beginning in
2021, CalGEM ceased issuing new well stimulation permits and has slowed the approval of new drill
permits even as it continues approving plugging and workovers. In addition, a group of plaintiffs
challenged the EIR and on February 25, 2020, a California Court of Appeal issued a ruling that
invalidates a portion of the EIR that Kern County had typically relied on to satisfy CEQA in order to
issue permits in Kern County. Kern County circulated and certified a supplementary EIR. However, the
trial court required that Kern County pause its local permitting system until the trial court has reviewed
the supplementary EIR and confirmed that it satisfied the concerns raised by the Court of Appeal. A
hearing is scheduled for April 2022. If the Kern County EIR is not reinstated or adequately modified
following resolution of the litigation described above, obtaining drilling permits for our operations in
areas where we do not have field or project specific CEQA coverage could be delayed or become
costly as a result of compliance with CEQA.
While we have a new drill permit inventory and believe we will be able to continue to maintain oil
production in 2022, we cannot guarantee that we will indefinitely continue to receive new drill permits in
a sufficient number to offset oil production decline.
Changes to elected or appointed officials or their priorities and policies could result in different
approaches to the regulation of the oil and natural gas industry. We cannot predict the actions the
Governor of California or the California legislature may take with respect to the regulation of our
business, the oil and natural gas industry or the state’s economic, fiscal or environmental policies, nor
can we predict what actions may be taken at the federal level with respect to health, environmental
safety, climate, labor or energy laws, regulations and policies, including those that may directly or
indirectly impact our operations.
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Concerns about climate change and other air quality issues may prompt governmental
action that could materially affect our operations or results.
Governmental, scientific and public concern over the threat of climate change arising from GHG
emissions, and regulation of GHGs and other air quality issues, may materially affect our business in
many ways, including increasing the costs to provide our products and services and reducing demand
for, and consumption of, our products and services, and we may be unable to recover or pass through a
significant portion of our costs. In addition, legislative and regulatory responses to such issues at the
federal, state and local level may increase our capital and operating costs and render certain wells or
projects uneconomic, and potentially lower the value of our reserves and other assets. Both the EPA and
California have implemented laws, regulations and policies that seek to reduce GHG emissions.
California’s cap-and-trade program operates under a market system and the costs of such allowances
per metric ton of GHG emissions are expected to increase in the future as the CARB tightens program
requirements and annually increases the minimum state auction price of allowances and reduces the
state’s GHG emissions cap. As the foregoing requirements become more stringent, we may be unable to
implement them in a cost-effective manner, or at all. In recent years, the regulation of methane emissions
from oil and gas facilities has been subject to uncertainty. In September 2020, the Trump Administration
revised prior regulations to rescind certain methane standards and remove the transmission and storage
segments from the source category for certain regulations. However, the U.S. Congress subsequently
approved and President Biden signed into a law, a resolution to repeal the September 2020 revisions to
the methane standards, effectively reinstating the prior standards. Additionally, in November 2021, the
EPA issued a proposed rule that, if finalized, would establish new source and first-time existing source
standards of performance for methane and volatile organic compound emissions for oil and gas facilities.
The EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included
in the November 2021 proposed rule and anticipates the issuance of a final rule by the end of the year.
Additionally, at the 26th Conference of the Parties of the United Nations Framework Convention on
Climate Change (COP26) in Glasgow in November 2021, the United States and the European Union
jointly announced the launch of the Global Methane Pledge, an initiative committing to a collective goal of
reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible
reductions” in the energy sector. The full impact of these actions is uncertain at this time and it is unclear
what additional initiatives may be adopted or implemented that may have adverse effects upon our
operations.
To the extent financial markets view climate change and GHG or other emissions as an increasing
financial risk, this could adversely impact our cost of, and access to, capital and the value of our stock
and our assets. Current investors in oil and gas companies may elect in the future to shift some or all of
their investments into other sectors, and institutional lenders may elect not to provide funding for oil and
gas companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (GFANZ)
announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in
capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to
set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities
to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt
policies that have the effect of reducing the funding provided to the fossil fuel sector. The Federal
Reserve announced in late 2020 that it has joined the Network for Greening the Financial System
(NGFS), a consortium of financial regulators focused on addressing climate-related risks in the financial
sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the
efforts of the NGFS to identify key issues and potential solutions for the climate-related challenged most
relevant to central banks and supervisory authorities. Although we cannot predict the effects of these
actions, such limitation of investments in and financings for fossil fuel energy companies could result in
the restriction, delay or cancellation of drilling programs or development or production activities.
Additionally, the Securities and Exchange Commission announced its intention to promulgate rules
requiring climate disclosures. Although the form and substance of these requirements is not yet known,
this may result in additional costs to comply with any such disclosure requirements.
We believe, but cannot guarantee, that our local production of oil, NGLs and natural gas will remain
essential to meeting California’s energy and feedstock needs for the foreseeable future. We have also
established 2030 Sustainability Goals for water recycling, renewables integration, methane emission
reduction and carbon capture and sequestration in our life-of-field planning in an attempt to align with the
state’s long-term goals and support our ability to continue to efficiently implement federal, state and local
laws, regulations and policies, including those relating to air quality and climate, in the future. However,
there can be no assurances that we will be able to design, permit, fund and implement such projects in a
timely and cost-effective manner or at all, or that we, our customers or end users of our products will be
able to satisfy long-term environmental, air quality or climate goals if those are applied as enforceable
mandates.
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The adoption and implementation of new or more stringent international, federal, state or local
legislation, regulations or policies that impose more stringent standards for GHG or other emissions from
our operations or otherwise restrict the areas in which we may produce oil, natural gas, NGLs or
electricity or generate GHG or other emissions could result in increased costs of compliance or costs of
consuming, and thereby reduce demand for or the value of our products and services. Additionally,
political, litigation and financial risks may result in restricting or canceling oil and natural gas production
activities, incurring liability for infrastructure damages or other losses as a result of climate change, or
impairing our ability to continue to operate in an economic manner. Moreover, climate change may pose
increasing risks of physical impacts to our operations and those of our suppliers, transporters and
customers through damage to infrastructure and resources resulting from drought, wildfires, sea level
changes, flooding and other natural disasters and other physical disruptions. One or more of these
developments could have a material adverse effect on our business, financial condition and results of
operations.
Adverse tax law changes may affect our operations.
We are subject to taxation by various tax authorities at the federal, state and local levels where we do
business. New legislation could be enacted by any of these government authorities that could adversely
affect our business. Legislation has been previously proposed that would, if enacted into law, make
significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal
income tax benefits currently available to oil and gas exploration and production companies. Such
changes include, but are not limited to, (i) the repeal of percentage depletion allowance for oil and natural
gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and
(iii) an extension of the amortization period for certain geological and geophysical expenditures. However,
it is unclear whether any such changes will be enacted and, if enacted, how soon any such changes
would be effective. Additionally, legislation could be enacted that imposes new fees or increases the
taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced
demand for our products. The passage of any such legislation or any other similar change in U.S. federal
income tax law could eliminate or postpone certain tax deductions that are currently available with
respect to natural gas and oil exploration and development or could increase costs and any such
changes could have an adverse effect on our financial condition, results of operations and cash flows.
In California, there have been numerous state and local proposals for additional income, sales, excise
and property taxes, including additional taxes on oil and natural gas production. Although such proposals
targeting our industry have not become law, campaigns by various interest groups could lead to
additional future taxes.
Risks Related to our Indebtedness
Our existing and future indebtedness may adversely affect our business and limit our financial
flexibility.
As of December 31, 2021, we had $600 million of total long-term debt, and additional borrowing
capacity of $367 million under the Revolving Credit Facility (after taking into account $125 million of
outstanding letters of credit). The terms of our Revolving Credit Facility and Senior Notes permit us to
incur significant additional debt, some of which may be secured. Our level of future indebtedness could
affect our operations in several ways, including the following:
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limit management’s discretion in operating our business and our flexibility in planning for, or
reacting to, changes in our business and the industry in which we operate;
require us to dedicate a portion of our cash flow from operations to service our existing debt,
thereby reducing the cash available to finance our operations and other business activities due to
restrictions on our ability to obtain additional financing, make investments, lease equipment, sell
assets and engage in business combinations;
increase our vulnerability to downturns and adverse developments in our business and the
economy generally;
limit our ability to access the capital markets to raise capital on favorable terms or to obtain
additional financing for working capital, capital expenditures, acquisitions, general corporate or
other expenses, or to refinance existing indebtedness;
• make it more likely that a reduction in our borrowing base following a periodic redetermination
could require us to repay a portion of our then-outstanding bank borrowings; and
• make us vulnerable to increases in interest rates as our indebtedness under the Revolving Credit
Facility varies with prevailing interest rates
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Our ability to satisfy our obligations depends on our future operating performance and on economic,
financial, competitive and other factors, many of which are beyond our control. Our business may not
generate sufficient cash flow, and future financings may not be available to provide sufficient net
proceeds, to meet these obligations or to successfully execute our business strategy.
We may not be able to generate sufficient cash to service all of our indebtedness, and may be
forced to take other actions to satisfy the obligations under our indebtedness, which may not be
successful.
Our earnings and cash flow could vary significantly from year to year due to the nature of our industry
despite our commodity price risk-management activities. As a result, the amount of debt that we can
manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow
may be insufficient to meet our debt obligations and other commitments at that time. Any insufficiency
could negatively impact our business. A range of economic, competitive, business and industry factors
will affect our future financial performance, and, as a result, our ability to generate cash flow from
operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices,
economic and financial conditions in our industry and the global economy and initiatives of our
competitors, are beyond our control as discussed in this “Risk Factors” section. We may not be able to
maintain a level of cash flows from operating activities sufficient to permit us to pay the principal,
premium, if any, and interest on our indebtedness.
The lenders under our Revolving Credit Facility could limit our ability to borrow and restrict
our use or access to capital.
Our Revolving Credit Facility is an important source of our liquidity. Our ability to borrow under our
Revolving Credit Facility is limited by our borrowing base, the size of our lenders’ commitments and our
ability to comply with covenants.
The borrowing base under our Revolving Credit Facility is redetermined semi-annually by our lenders
who review the value of our reserves and other factors that may be deemed appropriate. Currently, our
borrowing base is set at $1.2 billion and the availability under our Revolving Credit Facility is limited by
the aggregate elected commitment amount of our lenders, which as of February 1, 2022 was set at
$492 million.
A reduction in our borrowing base below the aggregate commitment amount of our lenders would
materially and adversely affect our liquidity and may hinder our ability to execute on our business
strategy.
Restrictive covenants in our Revolving Credit Facility and the indenture governing our Senior
Notes may limit our financial and operating flexibility.
Both our Revolving Credit Facility and the indenture governing our Senior Notes contain certain
restrictions, which may have adverse effects on our business, financial condition, cash flows or results of
operations, limiting our ability, among other things, to:
incur additional indebtedness;
incur additional liens;
pay dividends or make other distributions;
sell or discount receivables;
enter into mergers;
sell properties;
enter into or terminate hedge agreements;
enter into transactions with affiliates;
•
•
•
• make investments, loans or advances;
•
•
•
•
•
• maintain gas imbalances;
•
•
•
•
•
•
• make capital investments.
enter into take-or-pay contracts or make other prepayments;
enter into sale and leaseback agreements;
prepay or modify the terms of junior debt;
enter into negative pledge agreements;
enter into production sharing contracts;
amend our organizational documents; and
40
The Revolving Credit Agreement also requires us to comply with certain financial maintenance
covenants, including a leverage ratio and current ratio.
A breach of any of these restrictive covenants could result in a default under the Revolving Credit
Facility and/or the Senior Notes. If a default occurs under the Revolving Credit Facility, the lenders may
elect to declare all borrowings thereunder outstanding, together with accrued interest and other fees, to
be immediately due and payable. If we are unable to repay our indebtedness when due or declared
due, the lenders under the Revolving Credit Facility will also have the right to proceed against the
collateral pledged to them to secure the indebtedness. An event of default under the Senior Notes may
cause all outstanding Senior Notes to become due and payable immediately or give the trustee and the
holders the right to declare all outstanding Senior Notes to become due and payable immediately.
Variable rate indebtedness under our Revolving Credit Facility subjects us to interest rate
risk, which could cause our debt service obligations to increase significantly.
Borrowings under our Revolving Credit Facility are at variable rates of interest and expose us to
interest rate risk. As such, our results of operations are sensitive to movements in interest rates. There
are many economic factors outside our control that have in the past and may, in the future, impact
rates of interest including publicly announced indices that underlie the interest obligations related to a
certain portion of our debt. Factors that impact interest rates include governmental monetary policies,
inflation, economic conditions, changes in unemployment rates, international disorder and instability in
domestic and foreign financial markets. If interest rates increase, our debt service obligations on the
variable rate indebtedness would increase even though the amount borrowed remained the same, and
our results of operations would be adversely impacted. Such increases in interest rates could have a
material adverse effect on our financial condition and results of operations.
Risks Related to Our Common Stock
Our ability to pay dividends and repurchase shares of our common stock is subject to
certain risks.
We have adopted a cash dividend policy which anticipates a total annual dividend of $0.68, payable
to shareholders in quarterly increments of $0.17 per share of common stock, subject to board
authorization and declaration each quarter. In addition, as of December 31, 2021, we had remaining
authorization under our Share Repurchase Program to repurchase up to $102 million of shares of our
common stock. Any payment of future dividends or repurchasing shares of our common stock will be at
the discretion of our Board of Directors and will depend upon, among other things, our earnings,
liquidity, capital requirements, financial condition and other factors deemed relevant. Our Revolving
Credit Facility and Senior Notes both limit our ability to pay dividends and repurchase shares of our
common stock. In addition, cash dividend payments in the future may only be made out of legally
available funds and, if we experience substantial losses, such funds may not be available. We can
provide no assurances that we will continue to pay dividends at the anticipated rate or repurchase
shares of our common stock within the authorized amount or at all.
The trading price of our common stock may decline, and you may not be able to resell
shares of our common stock at prices equal to or greater than the price you paid or at all.
The trading price of our common stock may decline for many reasons, some of which are beyond
our control. In the event of a drop in the market price of our common stock, you could lose a
substantial part or all of your investment in our common stock. Numerous factors, including those
referred to in this “Risk Factors” section could affect our stock price. These factors include, among
other things, changes in our results of operations and financial condition; changes in commodity prices;
changes in the national and global economic outlook; changes in applicable laws and regulations;
variations in our capital plan; changes in financial estimates by securities analysts or ratings agencies;
changes in market valuations of comparable companies; and additions or departures of key personnel.
41
Future issuances of our common stock could reduce our stock price, and any additional
capital raised by us through the sale of equity or convertible securities may dilute your
ownership in us.
We may sell additional shares of common stock in subsequent public or private offerings. We may
also issue additional shares of common stock or convertible securities. As of December 31, 2021, we had
79,299,222 outstanding shares of common stock and 4,296,055 shares of common stock issuable upon
exercise of outstanding warrants. We cannot predict the size of future issuances of our common stock or
securities convertible into common stock or the effect, if any, that future issuances and sales of shares of
our common stock will have on the market price of our common stock. Sales of substantial amounts of
our common stock (including shares issued in connection with an acquisition), or the perception that such
sales could occur, may adversely affect prevailing market prices of our common stock.
There is an increased potential for short sales of our common stock due to the sales of shares
issued upon exercise of warrants, which could materially affect the market price of the stock.
Downward pressure on the market price of our common stock that likely will result from sales of our
common stock issued in connection with the exercise of warrants could encourage short sales of our
common stock by market participants. Generally, short selling means selling a security, contract or
commodity not owned by the seller. The seller is committed to eventually purchase the financial
instrument previously sold. Short sales are used to capitalize on an expected decline in the security’s
price. Such sales of our common stock could have a tendency to depress the price of the stock, which
could increase the potential for short sales.
The ownership position of certain of our stockholders limits other stockholders’ ability to
influence corporate matters and could affect the price of our common stock.
As of January 31, 2022, four of our shareholders owned at least 10% and collectively approximately
46% of our common stock. As a result, each of these stockholders, or any entity to which such
stockholders sell their stock, may be able to exercise significant control over matters requiring
stockholder approval. Further, because of this large ownership position, if these stockholders sell their
stock, the sales could depress our share price.
General Risk Factors
Increasing attention to ESG matters may adversely impact 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. 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.
42
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.
Part of our business strategy involves divesting non-core assets. 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 oil and natural gas exploration and production activities
and our assets are subject to risks such as fires, explosions, releases, discharges, power outages,
equipment or information technology failures and industrial accidents, as are the assets and properties of
third parties who supply us with energy, equipment and services or who purchase, transport or use our
products. 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. In addition, events such as earthquakes, floods, mudslides,
wildfires, power outages, high winds, droughts, cybersecurity, vandalism or terrorist attacks and other
events may cause operations to cease or be curtailed and could adversely affect our business, workforce
and the communities in which we operate. Further, recent wildfires experienced in California have limited
the availability and increased the cost of obtaining insurance against certain natural disasters. 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.
43
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.
44
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 3 stockholders of record at December 31, 2021.
Dividend Policy
In the fourth quarter of 2021, our Board of Directors declared a quarterly cash dividend of $0.17 per
share of common stock. The dividend was paid on December 16, 2021 to shareholders of record at the
close of business on December 1, 2021. On February 23, 2022, our Board of Directors declared a
quarterly cash dividend of $0.17 per share of common stock. The dividend is payable to shareholders of
record at the close of business on March 7, 2022 and is expected to be paid on March 16, 2022. 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,
business conditions and other factors. Based on current conditions, we expect to continue paying regular
quarterly dividends of $0.17 per share through 2022.
Share Repurchases
In May 2021, our Board of Directors authorized a Share Repurchase Program. We increased our
Share Repurchase Program in February 2022 by $100 million to $350 million in aggregate and
extended the term of the program until December 31, 2022. 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, 2021 was as follows:
Period
April 1, 2021 - June 30, 2021 . . . . . . . . . . .
July 1, 2021 - September 30, 2021 . . . . . .
October 1, 2021 - October 31, 2021 . . . . .
November 1, 2021 - November 30, 2021 .
December 1, 2021 - December 31, 2021 .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
Total
Number of
Shares
Purchased
1,440,203
1,151,596
384,605
491,331
622,253
4,089,988
Average
Price
Paid per
Share
$ 31.56
$ 33.42
$ 42.23
$ 43.57
$ 41.75
$ 36.08
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs
1,440,203
1,151,596
384,605
491,331
622,253
4,089,988
Maximum Dollar
Value of Shares that
May Yet be
Purchased Under the
Plans or Programs(a)
—
$
—
—
—
—
—
$
(a) The dollar value of shares that may yet be purchased under the Share Repurchase Program totaled $102 million as of
December 31, 2021.
Securities Authorized for Issuance Under Equity Compensation Plans
A description of stock-based compensation plans can be found in Part II, Item 8 – Financial
Statements and Supplementary Data, Note 9 Stock-Based Compensation. The aggregate number of
shares of our common stock authorized for issuance under our stock-based compensation plans for
our executives, employees and non-employee directors, approved as part of the Plan upon our
emergence from bankruptcy, is 9,257,740. Approximately 2,092,318 has been issued or reserved
through December 31, 2021. See Part II, Item 8 – Financial Statements and Supplementary Data, Note
14 Chapter 11 Proceedings for more information on the Plan.
45
The following is a summary of the securities available for issuance as of December 31, 2021:
Plan Category
Equity compensation plans approved
by security holders . . . . . . . . . . . . . . . . .
Equity compensation plan not
approved by security holders . . . . . . . .
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)
—
2,074,145 (1)
—
—
—
7,165,422 (2)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1) 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 9 Stock-Based Compensation for more information on these awards.
7,165,422
2,074,145
(2) Relates to remaining shares available for issuance under our stock-based compensation plans for our executives,
employees and non-employee directors.
46
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 groups. 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 peer group consisted of Antero Resources Corporation; Berry Petroleum; Callon Petroleum
Company; Comstock Resources Inc.; Coterra Energy Inc.; Denbury Inc.; Kosmos Energy Ltd.; Magnolia
Oil & Gas Corp; Matador Resources Company; Murphy Oil Corporation; Oasis Petroleum Inc.; PDC
Energy, Inc.; Range Resources Corporation; SM Energy Company; Southwestern Energy Company;
Vermilion Energy Inc.; and Whiting Petroleum Corporation
PERFORMANCE GRAPH*
Among California Resources Corp, the S&P 500 Index,
the Dow Jones US Exploration & Production Index, and a Peer Group
$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
California Resources Corp
S&P 500
Dow Jones US Exploration & Production
Peer Group
CRC
S&P 500
Dow Jones US Exploration & Production
Peer Group
10/28/20
12/31/20
3/31/21
6/30/21
9/30/21
12/31/21
100.00
100.00
100.00
100.00
157.27
115.21
143.37
125.21
160.40
122.33
192.09
193.92
200.93
132.78
221.97
258.98
273.33
133.56
226.75
289.09
285.97
148.28
245.05
285.45
* 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.
47
ITEM 6 RESERVED
48
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 14 Chapter 11 Proceedings and Note 15 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.
COVID-19 Pandemic
The COVID-19 pandemic has continued to create challenges including disrupting global supply
chains. In early 2021, health agencies approved vaccines for combating the COVID-19 virus. However,
actual vaccination results are ultimately dependent on, among other factors, vaccine availability and their
acceptance by individuals. Variants of COVID-19 have become the dominant strain and have begun to
spread resulting in pandemic restrictions being reinstated. Accordingly, the continued pace of recovery
from the COVID-19 pandemic is not currently known.
Global commodity prices increased during 2021 amid strong demand recovery from the economic
impacts of COVID-19. We maintain various measures, primarily implemented during 2020, 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.
49
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, 2021, the period from November 1, 2020 through December 31,
2020, the period from January 1, 2020 through October 31, 2020 and the year ended December 31,
2019:
Successor
Predecessor
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
2019
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 Production
(MBoe/d) . . . . . . . . . . . . . . . . .
39
19
2
60
13
13
135
1
4
19
159
100
38
23
2
63
12
12
138
1
3
23
165
103
42
25
3
70
13
13
147
2
4
21
174
112
52
24
4
80
15
15
162
2
5
28
197
128
Total daily production volumes was 100 MBoe/d for the year ended December 31, 2021, a
decrease of 10% from 111 MBoe/d for the combined year ended December 31, 2020. The decrease
was largely a result of natural production declines. We suspended our drilling activity in the first quarter
of 2020 and temporarily shut-in production in the second quarter of 2020 in response to the economic
conditions at that time. We increased our capital investment and re-started our drilling program during
2021. Our capital program for 2022 aims to maintain oil production by investing in shallower, oil
projects with faster payouts to offset natural oil decline. PSCs negatively impacted our production in
2021 by approximately 3 MBoe/d compared to the combined year ended December 31, 2020. We
divested the vast majority of our assets in the Ventura basin which resulted in a decrease of 2 MBoe/d
beginning in the fourth quarter of 2021. This decrease was partially offset by improved operational
results from our 2021 drilling program and our acquisition of MIRA’s working interest in certain wells in
the third quarter of 2021 which increased oil production by 1 MBbl/d.
In the first quarter of 2022, we expect to conduct regular maintenance at our Elk Hills cryogenic gas
plant that will result in a shut down for approximately six to eight weeks. We estimate a decrease in
production of approximately 6 MBoe/d in the first quarter of 2022, returning to pre-turnaround
production levels in the second quarter of 2022.
We temporarily shut-in production of 3 MBoe/d in 2020, which negatively impacted our production
compared to 2019. Additionally, our divestiture of a 50% working interest in certain zones within our
Lost Hills Field resulted in a decrease of approximately 2 MBoe/d beginning in the second quarter of
2019. Our PSCs positively impacted our oil production in the combined year ended December 31,
2020 by approximately 3 MBoe/d compared to 2019.
50
Our operating results and those of the oil and natural gas industry as a whole are heavily influenced
by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result
of numerous market-related variables. These and other factors make it impossible to predict realized
prices reliably. 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
2021
November 1, 2020 -
December 31, 2020
Price
Realization
Price
Realization
Oil ($ per Bbl)
Brent
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
70.79
Realized price without derivative settlements . . . . . $
Effects of derivative settlements . . . . . . . . . . . . . . . .
70.43
(14.38)
99%
Realized price with derivative settlements . . . . . . . . $
56.05
79%
WTI
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price without derivative settlements . . . . . $
Realized price with derivative settlements . . . . . . . . $
67.91
70.43
56.05
104%
83%
NGLs ($ per Bbl)
Realized price(a)
Realized price(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
53.62
53.62
76%
79%
Natural gas
NYMEX ($/MMBTU) . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price without derivative settlements
($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Effects of derivative settlements . . . . . . . . . . . . . . . .
3.61
4.22
(0.02)
117%
Realized price with derivative settlements
($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4.20
116%
(a) Realization is calculated as a percentage of Brent.
(b) Realization is calculated as a percentage of WTI.
$
$
$
$
$
$
$
$
$
$
$
47.10
45.65
(0.28)
45.37
44.21
45.65
45.37
97%
96%
103%
103%
38.00
38.00
81%
86%
2.86
3.21
(0.07)
112%
3.14
110%
51
Predecessor
January 1, 2020 -
October 31, 2020
2019
Price
Realization
Price
Realization
42.43
41.21
1.98
43.19
38.44
41.21
43.19
25.70
25.70
1.95
2.11
0.06
2.17
97%
102%
107%
112%
61%
67%
108%
111%
$
$
$
$
$
$
$
$
$
$
$
64.18
64.83
3.82
68.65
57.03
64.83
68.65
31.71
31.71
2.67
101%
107%
114%
120%
49%
56%
2.87
(0.01)
2.86
107%
107%
Oil ($ per Bbl)
Brent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price without derivative settlements . . . . . . $
Effects of derivative settlements . . . . . . . . . . . . . . . .
Realized price with derivative settlements . . . . . . . . $
WTI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price without derivative settlements . . . . . . $
Realized price with derivative settlements . . . . . . . . $
NGLs ($ per Bbl)
Realized price(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Natural gas
NYMEX ($/MMBTU) . . . . . . . . . . . . . . . . . . . . . . . . . . $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Realized price without derivative settlements
($/Mcf)
Effects of derivative settlements . . . . . . . . . . . . . . . .
Realized price with derivative settlements ($/Mcf) . . $
(a) Realization is calculated as a percentage of Brent.
(b) Realization is calculated as a percentage of WTI.
Oil — Brent index and realized prices excluding hedge settlements were higher for the year ended
December 31, 2021 compared to 2020 as oil demand was bolstered by the re-opening of economies
and easing of mobility restrictions related to the COVID-19 pandemic. Prices also increased due to a
rise in domestic demand and lower supply caused by reduced investment in the U.S. upstream oil and
gas sector during 2020 as well as supply management by OPEC members.
NGLs — Prices for NGLs increased in the year ended December 31, 2021 compared to 2020.
Higher prices were primarily the result of increased demand in the U.S. and abroad.
Natural Gas — In 2021, natural gas prices increased both across the United States and within
California compared to 2020 primarily due to concerns that low storage levels combined with
anticipated demand returning to pre-COVID-19 levels would not be sufficient to meet domestic and
growing export demand.
Divestitures
Ventura Transactions
During the second quarter of 2021, we entered into transactions to sell our Ventura basin assets.
These transactions contemplate multiple closings that are subject to customary closing conditions. In
total, we will receive cash consideration of up to $102 million, before purchase price adjustments, plus
additional earn-out consideration that is linked to future commodity prices. The consideration, exclusive of
the earn-out, includes $82 million of total cash consideration (subject to purchase price adjustments) and
up to $20 million of potential additional consideration if the buyer does not perform certain abandonment
obligations with respect to the divested properties. The additional consideration is secured by production
payments of $20 million over a five-year period. To the extent the buyer satisfies all of the required
abandonment obligations within a five-year period following the initial close date, none of the $20 million
of potential additional consideration will be paid to us.
52
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. We expect to divest our remaining assets in the Ventura basin during the first
half of 2022. These remaining assets, consisting of property, plant and equipment and the associated
asset retirement obligations, are classified as held for sale on our consolidated balance sheet as of
December 31, 2021.
Lost Hills Transaction
In February 2022, we sold our 50% non-operated working interest in certain horizons within our Lost
Hills field, located in the San Joaquin basin, for proceeds of $55 million (before transaction costs and
purchase price adjustments). We retained an option to capture, transport and store 100% of the CO2
from steam generators across the Lost Hills field for future carbon management projects. We also
retained 100% of the deep rights and related seismic data.
Other Divestitures
In 2021, we also sold unimproved land and other non-core assets for $13 million of proceeds
recognizing a $4 million gain.
In January 2020, we sold royalty interests and divested non-core assets resulting in $41 million of
proceeds. The divestitures were treated as normal retirements and no gain or loss was recognized.
Acquisitions and Joint Ventures
During the second half of 2021, we completed our development joint venture (JV) with MIRA, our
development joint venture with Benefit Street Partners (BSP) and our development joint venture with
Royale Energy Inc. (Royale JV).
The MIRA JV contemplated that MIRA would fund the development of certain of our oil and natural
gas properties in the San Joaquin basin in exchange for a 90% working interest in the related properties.
In August 2021, we purchased MIRA’s entire working interest share in the conveyed assets for a net
cash payment of $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.
The BSP JV contemplated that BSP would contribute funds for the development of our oil and natural
gas properties in exchange for preferred interests in a joint venture entity. 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 recorded as a financing cash outflow
on our consolidated statement of cash flows. Our consolidated results reflect the full operations of the
BSP JV, with BSP’s share of net income reported in net income attributable to noncontrolling interests on
our consolidated statements of operations through the redemption date.
The Royale JV contemplated that Royale would fund the development of certain of our natural gas
properties in Sacramento Valley. In December 2021, the Royale JV was mutually terminated by both
parties.
The development joint venture with Alpine Energy Capital, LLC (Alpine) contemplated that Alpine
would fund the drilling of certain wells within the Elk Hills field. The development agreement with Alpine
was terminated in October 2021. The termination of the development plan does not affect the 90%
working interest earned by Alpine in wells previously drilled. Our consolidated results reflect only our
working interest share in the productive wells.
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 Payment
On December 16, 2021, we paid a $0.17 per share dividend on our common stock in the aggregate
amount of $14 million to shareholders of record at the close of business on December 1, 2021.
53
On February 23, 2022, our Board of Directors declared a cash dividend of $0.17 per share of
common stock. The dividend is payable to shareholders of record at the close of business on March 7,
2022 and is expected to be paid on March 16, 2022. This quarterly dividend is made pursuant to a
cash dividend policy approved by the Board of Directors in November 2021.
Share Repurchase Program
During 2021, our Board of Directors authorized a Share Repurchase Program for up to $250 million
of our common stock through June 30, 2022. As of December 31, 2021, we repurchased 4,089,988
shares of our common stock, at an average price of $36.08 per share, through either open market
purchases or a Rule 10b5-1 plan for $148 million. Shares repurchased are held as treasury stock as of
December 31, 2021.
In February 2022, the Share Repurchase Program was increased by $100 million to $350 million in
aggregate and we extended the term of the program until December 31, 2022. For the period
January 1, 2022 through February 18, 2022, we repurchased an additional 933,200 shares of our
common stock, at an average price of $42.57 per share, through either open market purchases or a
Rule 10b5-1 plan for approximately $40 million. After these repurchases and the $100 million increase
in our Share Repurchase Program, we have approximately $162 million of remaining capacity available
for future repurchases.
Seasonality
While certain aspects of our operations are affected by seasonal factors, such as energy costs,
overall, seasonality has not been a material driver of changes in our earnings during the year.
Income Taxes
Management assesses the realizability of 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. For the assessment
period ended December 31, 2021, management concluded that it was more-likely-than-not that all of
our existing deferred tax assets would be realized. This determination was based, in part, on our three-
year cumulative income position, the profitability of our core business activities in recent periods and
our projections of future taxable income at current commodity prices and our current cost structure. We
also considered our ability to generate future taxable income in a lower commodity price environment
as a potential source of negative evidence. Based on our assessment, we determined there is
sufficient positive evidence to conclude that it is more-likely-than-not that our deferred tax assets of
$396 million at December 31, 2021 are realizable and we released all of our valuation allowance in the
fourth quarter of 2021.
For additional information on tax-related items, see information set forth in Part II, Item 8 – Financial
Statements and Supplementary Data, Note 8 Income Taxes.
54
Statement of Operations Analysis
Results of Oil and Natural Gas Operations
The following table presents key operating data for our oil and natural gas operations, on a per Boe
basis for the year ended December 31, 2021, 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. Energy operating
costs consist of purchases of natural gas used to generate electricity, purchased electricity and internal
costs used to generate electricity used in our operations. Non-energy operating costs equal total
operating costs less energy and gas processing costs. However, non-energy operating costs include
the costs of purchasing natural gas used to generate steam for our steamfloods.
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Combined
Year ended
December 31,
2020
Energy operating
costs . . . . . . . . . . . . . . . $
Gas processing
costs . . . . . . . . . . . . . . . $
Non-energy operating
costs . . . . . . . . . . . . . . . $
Operating costs . . . . $
Field general and
administrative
expenses . . . . . . . . . . . . $
Field depreciation,
depletion and
amortization . . . . . . . . . $
Field taxes other than
on income . . . . . . . . . . . $
5.09
0.54
13.76
19.39
0.94
5.23
2.83
$
$
$
$
$
$
$
4.46
0.55
13.18
18.19
1.12
4.95
0.64
$
$
$
$
$
$
$
3.86
0.55
10.54
14.95
1.11
8.75
3.10
$
$
$
$
$
$
$
3.95
0.55
10.95
15.45
1.11
8.16
2.72
Operating costs per Boe in 2021 were higher than the combined period of 2020 primarily as a result
of higher natural gas and electricity prices and increased downhole maintenance activity. Partially
offsetting these increases are reduced labor-related expenses from actions taken to reduce our
headcount in late 2020 and early 2021 and reduced employee benefits beginning in the second quarter
of 2021. Further, our management team’s annual incentive for 2021 included a performance metric tied
to cost savings. Operating costs in the Predecessor period of 2020 reflect cost savings for shut-in wells
and lower activity in response to the lower commodity price environment as well as reduced work
hours in the second quarter of 2020. We continue to focus on achieving recurring cost savings.
Field depreciation, depletion and amortization in the Successor periods of 2021 and 2020 was
lower than the Predecessor period of 2020 primarily as a result of a lower depletable basis resulting
from our fresh start fair value adjustments.
Field general and administrative expenses were lower in 2021 primarily due to actions taken to
reduce costs which included headcount reductions in the third quarter of 2020 and first quarter of 2021.
Field taxes other than on income on a per Boe basis were higher in 2021 as compared to the
combined period of 2020 due to lower production volumes in 2021. However, the total amount paid on
field taxes other than on income was lower in 2021 as compared to the combined period of 2020 due
to a decrease in ad valorem and production taxes, partially offset by higher greenhouse gas taxes due
to emission levels as we increased activity and market prices.
55
Consolidated Results of Operations
Year Ended December 31, 2021 vs. the Successor and Predecessor Periods of 2020
The following table presents our consolidated revenue for the year ended December 31, 2021 and
the Successor and Predecessor periods of 2020 along with supplemental information for the combined
year ended December 31, 2020 (in millions):
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Combined
Year ended
December 31,
2020
Revenue
Oil, natural gas and
NGL sales . . . . . . . . . .
Net (loss) gain from
commodity
derivatives . . . . . . . . . .
Sales of purchased
natural gas . . . . . . . . . .
Electricity sales . . . . . .
Other revenue . . . . . . .
Total operating
revenues . . . . . . . . .
$
2,048
$
237
$
1,092
$
1,329
(676)
312
172
33
(141)
38
15
3
91
124
86
14
(50)
162
101
17
$
1,889
$
152
$
1,407
$
1,559
Oil, natural gas and NGL sales – Oil, natural gas and NGL sales, excluding the impact of settled
hedges, were $2,048 million for the year ended December 31, 2021, which is an increase of 54% or
$719 million, compared to $1,329 million for the combined year ended December 31, 2020. The
increase was primarily due to higher realized prices as shown in the following table:
Oil
NGLs
Natural
Gas
Total
(in millions)
Year ended December 31, 2020
(Combined) . . . . . . . . . . . . . . . . . . . . . . . . $
Changes in realized prices . . . . . . . . . . .
Changes in production . . . . . . . . . . . . . . .
$
1,050
715
(210)
$
135
127
(12)
$
144
122
(23)
Year ended December 31, 2021 . . . . . . . $
1,555
$
250
$
243
$
1,329
964
(245)
2,048
Note: See Production, Prices and Realizations for volumes by commodity type and realized prices for each period.
The effect of settled hedges is not included in the table above. Payments on commodity derivatives
were $319 million for the year ended December 31, 2021 compared to proceeds of $107 million for the
combined year ended December 31, 2020. Including the effect cash settlements on commodity
derivatives, our oil, natural gas and NGL sales increased by $293 million or 20% in 2021 compared to
the same prior year period. A majority of our cash settlements on commodity derivatives during 2021
were related to contracts entered into shortly after our emergence from bankruptcy in order to comply
with debt covenants in our Revolving Credit Facility.
56
Net (loss) gain from commodity derivatives – Gains and losses from our commodity derivative
contracts primarily relate to the non-cash changes in the fair value of our outstanding derivatives
resulted 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:
Successor
Year ended
December 31,
2021
November 1,
2020 -
December
31, 2020
Predecessor
January 1,
2020 -
October 31,
2020
Combined
Year ended
December 31,
2020
(in millions)
Non-cash commodity derivative loss,
excluding noncontrolling interest . . . . .
Non-cash commodity derivative (loss)
gain, attributable to noncontrolling
interest
. . . . . . . . . . . . . . . . . . . . . . . . .
Total non-cash changes . . . . . . . . . .
Net (payments) proceeds on settled
commodity derivatives . . . . . . . . . . .
Net (loss) gain from commodity
derivatives . . . . . . . . . . . . . . . . . . . . . . .
$
(357) $
(138) $
(19)
$
(157)
—
(357)
(319)
(2)
(140)
(1)
2
(17)
108
$
(676) $
(141)
$
91
$
—
(157)
107
(50)
Sales of purchased natural gas – Sales of purchased natural gas were $312 million for the year
ended December 31, 2021, compared to $162 million for the combined year ended December 31,
2020, which is an increase of $150 million, or 93%. The increase was due to higher natural gas prices
in 2021 partially offset by decreased volumes. Our natural gas sales net of related purchases were
$116 million for the year ended December 31, 2021 compared to $60 million for the combined year
ended December 31, 2020.
Electricity sales — Electricity sales increased by $71 million to $172 million during the year ended
December 31, 2021 compared to $101 million for the combined year ended December 31, 2020. The
increase was predominantly due to higher electricity prices in 2021 resulting from higher natural gas
prices as well as reduced hydroelectric generation in California. Additionally, electric power generation
was higher in 2021 due to planned maintenance and an outage at the Elk Hills power plant in 2020.
Other revenue — Other revenue primarily includes fees and sales from processing third party gas.
Other revenue increased by $16 million to $33 million for the year ended December 31, 2021,
compared to $17 million for the combined year ended December 31, 2020 primarily due to higher
natural gas prices.
57
The following table presents our operating and non-operating expenses (income) for the year ended
December 31, 2021 and the Successor and Predecessor periods of 2020 along with supplemental
information for the combined year ended December 31, 2020 (in millions):
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 . . . . . . . .
Gain on asset divestitures . . . . . . . . .
Operating income (loss) . . . . . . . . .
Non-operating (expenses) income
. . . . . . . . .
Reorganization items, net
Interest and debt expense, net
. . . . .
Net (loss) gain on early
extinguishment of debt . . . . . . . . . . . .
Other non-operating expenses,
net
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income
taxes . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . .
Income tax benefit
Net (income) loss attributable to
noncontrolling interests . . . . . . . . . . .
Successor
Year ended
December 31,
2021
November 1,
2020 -
December 31,
2020
Predecessor
January 1,
2020 -
October 31,
2020
Combined
Year ended
December 31,
2020
$
$
$
$
185
20
500
200
213
28
145
7
196
96
51
50
29
1,720
124
293
(6)
(54)
(2)
(2)
229
396
625
$
$
$
(13) $
28
3
83
40
34
—
10
1
24
10
8
8
9
258
—
(106)
(3)
(11)
—
(5)
(125)
—
(125)
2
$
$
$
$
132 $
19
360
212
328
1,736
134
10
78
53
35
33
56
3,186 $
—
(1,779)
4,060
(206)
5
(84)
1,996
—
1,996 $
160
22
443
252
362
1,736
144
11
102
63
43
41
65
3,444
—
(1,885)
4,057
(217)
5
(89)
1,871
—
1,871
(107) $
(105)
Energy operating costs – Energy operating costs were $185 million for the year ended December 31,
2021, which was an increase of 16% or $25 million compared to $160 million for the combined year
ended December 31, 2020. The increase was predominantly a result of higher prices for purchased
natural gas, which we use to generate electricity for our operations, and for purchased electricity.
Non-energy operating costs – Non-energy operating costs for the year ended December 31, 2021
were $500 million, which was an increase of $57 million or 13% from $443 million for the combined year
ended December 31, 2020. This increase was primarily a result of higher downhole maintenance activity
in 2021 which was deferred from 2020 as we shut-in wells and suspended surface maintenance activity
due to the COVID-19 pandemic. Additionally, non-energy operating costs increased in 2021 due to higher
prices for natural gas, which we use to generate steam for our steamfloods. Partially offsetting these
increases were lower labor-related costs from headcount reductions in late 2020 and early 2021 and
reduced employee benefits beginning in the second quarter of 2021. Although higher natural gas prices
in 2021 increased our operating costs, higher prices have a net positive effect on our operating results
due to higher revenue from sales of this commodity which we also produce.
58
General and administrative expenses – Our general and administrative expenses (G&A) were
$200 million for the year ended December 31, 2021, which was a decrease of $52 million from
$252 million for the combined year ended December 31, 2020. The decrease in G&A expenses was
primarily attributable to lower labor-related costs as a result of workforce reductions that occurred in the
second half of 2020 and the first quarter of 2021 as well as employee benefit reductions in the second
quarter of 2021. The remaining decrease was also due to lower spending across a number of cost
categories. The decrease was partially offset by an increase in compensation expense related to equity-
settled awards granted to executives and directors in 2021.
Depreciation, depletion and amortization – Depreciation, depletion and amortization in each of the
Successor periods was lower than the Predecessor period of 2020 primarily due to a decrease in the
carrying value of our property as a result of fair value adjustments recorded as part of fresh start
accounting on our emergence date. For further detail about our fair value adjustments see Part II, Item 8
– Financial Statements and Supplementary Data, Note 15 Fresh Start Accounting.
Asset impairments – Asset impairments were $28 million for the year ended December 31, 2021
compared to $1.7 billion for the combined year ended December 31, 2020. The asset impairment
charges in 2021 included $25 million related to a commercial office building located in Bakersfield,
California due to the decline in commercial demand for office space of this size and type in that market.
The impairment charge of $1.7 billion in 2020 was due to the sharp drop in commodity prices at the end
of the first quarter of 2020. Approximately $1.5 billion of this charge related to certain of our proved
properties and $228 million related to unproved acreage that was no longer included in our development
plans at that time. For further detail about our first quarter 2020 asset impairment, 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 $145 million for the year ended
December 31, 2021, which was an increase of $1 million from $144 million for the combined year ended
December 31, 2020. In 2021, we paid higher greenhouse gas taxes due to emission levels as we
increased activity and increased market prices, which was partially offset by a decrease in ad valorem
and production taxes.
Purchased natural gas expense – Purchased natural gas expense was $196 million for the year
ended December 31, 2021, which was an increase of $94 million or 92% from $102 million for the
combined year ended December 31, 2020 primarily due to higher prices in 2021 for purchased natural
gas related to our trading activities.
Electricity generation expense – Electricity generation expenses increased to $96 million for the year
ended December 31, 2021 from $63 million for the combined year ended December 31, 2020. The
increase of $33 million was predominantly a result of higher pricing in 2021 on purchased natural gas
used in electricity generation.
Other operating expenses, net – Other operating expenses, net was $29 million for the year ended
December 31, 2021, which was a decrease of $36 million or 55% from $65 million for the combined year
ended December 31, 2020. In 2020, other operating expenses, net included a one-time payment of
$20 million made in connection with an expiring pipeline delivery contract and $7 million related to an
outage at the Elk Hills power plant. Both of the years ended December 31, 2021 and the combined year
ended December 31, 2020 include $15 million of severance costs related to the reduction in our
workforce and the departure of certain executive and other senior officers.
Gain on asset divestitures – 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. No gain or loss was recognized in 2020 on the sale of royalty interests and a
non-core asset since we accounted for these transactions as normal retirements. For more information
on our asset divestitures, see Part II, Item 8 – Financial Statements and Supplementary Data, Note 3
Divestitures and Acquisitions.
Reorganization items, net – Reorganization items, net was $6 million for the year ended
December 31, 2021, all of which related to legal, professional and other fees related to our bankruptcy,
compared to a $4.1 billion net gain for the combined year ended December 31, 2020. Reorganization
items, net for the combined periods of 2020 includes legal, professional and other fees related to our
bankruptcy, a net gain from the cancellation of our pre-emergence debt and the associated write-off of
the unamortized balance of deferred gain, original issue discounts and deferred issuance costs and
debtor-in-possession financing costs which were incurred during our bankruptcy proceedings. See Part II,
Item 8 – Financial Statements and Supplementary Data, Note 14 Chapter 11 Proceedings for additional
information about reorganization items, net.
59
Interest and debt expense, net – Interest and debt expense, net was $54 million for the year ended
December 31, 2021 compared to $11 million for the Successor period of 2020 and $206 million for the
Predecessor period of 2020. Interest and debt expense, net during 2021 primarily consists of interest on
our Senior Notes. Interest and debt expense, net for the Successor period of 2020 primarily includes
interest on our Revolving Credit Facility, Second Lien Notes and EHP Notes as well as amortization of
debt issuance costs and deferred gain as shown in the table below. See Part II, Item 8 – Financial
Statements and Supplementary Data, Note 4 Debt for additional information on our credit agreements
and January 2021 Senior Notes offering.
Interest and debt expense, net decreased in the Successor period of 2020 as compared to the
Predecessor period of 2020 primarily due to the discharge of our debt upon emergence from bankruptcy.
The table below shows interest and debt expense, net for the Successor and Predecessor periods (in
millions):
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
. . . . . . . . . . . . $
Interest expense on debt
Amortization of deferred gain . . . . . . . . .
Amortization of debt issuance . . . . . . . .
Other interest . . . . . . . . . . . . . . . . . . . . . .
Capitalized interest . . . . . . . . . . . . . . . . .
Interest and debt expense, net . . . . . . $
49
—
7
1
(3)
54
$
$
10
—
1
—
—
11
$
$
223
(39)
29
1
(8)
206
Other non-operating expense, net – Other non-operating expenses, net for the year ended
December 31, 2021 was $2 million compared to $89 million in the combined period of 2020. Other
non-operating expense includes pension cost, other than the service cost component, related to our
pension and postretirement benefit plans. The higher expense in 2020 was primarily a result of legal,
professional and other fees in preparation for our bankruptcy filing and an abandoned financing
transaction.
Income tax benefit – We released our valuation allowance in the fourth quarter of 2021. See Part II,
Item 8 – Financial Statements and Supplementary Data, Note 8 Income Tax for more information on the
realizability of our deferred tax assets.
Net income attributable to noncontrolling interests – Upon emergence from bankruptcy, we acquired
all third-party membership interests in the Ares JV. As a result, the allocation of net loss (income) to
noncontrolling interest holders in the Successor period not comparable to the Predecessor periods.
The net loss allocated to the noncontrolling interest holder, BSP, in the Successor period of 2020
primarily related to non-cash losses on derivatives. 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 14 Chapter 11 Proceedings
for additional information on the Ares JV and Part II, Item 8 – Financial Statements and Supplementary
Data, Note 10 Equity for more information on the redemption of the preferred member interest from BSP.
The Successor and Predecessor Periods of 2020 vs. 2019
See Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of
Operations, Statement of Operations Analysis in our 2020 Form 10-K for our analysis of the changes in
our consolidated statements of operations for the Successor period from November 1, 2020 through
December 31, 2020 and the Predecessor periods from January 1, 2020 through October 31, 2020 and
the year ended December 31, 2019.
60
Liquidity and Capital Resources
Liquidity
Our primary sources of liquidity and capital resources are cash flows from operations, cash on hand
and available borrowing capacity under our Revolving Credit Facility. As of December 31, 2021, we
had liquidity of $672 million, which consisted of $305 million in cash and $367 million of available
borrowing capacity under our Revolving Credit Facility. In February 2022, we obtained $60 million of
additional commitments from new lenders increasing our liquidity due to our available borrowing
capacity under our Revolving Credit Facility increasing to $427 million from $367 million. As of
December 31, 2021, 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 control costs 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 expect to
begin paying cash income taxes in 2022. Our tax paying status depends on a number of factors,
including the amount and type of our capital spend, cost structure and activity levels. We expect to
focus on asset retirement activities over the next several years to reduce our idle well inventory. We
believe we have sufficient sources of liquidity to meet our obligations for the next twelve months.
Derivatives
Significant changes in oil and natural gas prices may have a material impact on our liquidity.
Declining commodity prices negatively affect our operating cash flow, and the inverse applies during
periods of rising commodity prices. Our hedging strategy seeks to mitigate our exposure to commodity
price volatility and ensure our financial strength and liquidity by protecting our cash flows. 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 for some time
periods and will continue to evaluate our hedging strategy based on prevailing market prices and
conditions. In some circumstances, these hedges (including hedges entered into by us in 2020 to
comply with covenants in our Revolving Credit Facility) may prevent us from realizing the full benefits
of price increases.
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, 2021.
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, 2021.
61
Uses of Cash
2022 Capital Program
We have increased our 2022 capital program from our 2021 level and target a range of $330 to
$375 million. The program includes $300 to $335 million for oil and gas development and $30 to
$40 million for carbon management projects. This level of expected spending is consistent with our
strategy of investing up to 50% of our operating cash flow back into our oil and gas operations.
We prioritize high oil mix projects that provide high margins and low decline rates to maximize our
cash flow from operations. Our technical teams are consistently working to enhance value by
improving the economics of our inventory through detailed geologic studies as well as application of
more effective and efficient drilling and completion techniques. We regularly monitor internal
performance and external factors and adjust our capital investment program with the objective of
creating the most value from our asset portfolio.
The actual amount of spending under our 2022 capital program will depend on a variety of factors,
including commodity prices, the success of our drilling program, operating costs and other general
market conditions. Because we own and operate substantially all of our assets, the amount and timing
of our capital spending is largely within our control. Any curtailment of the development of our
properties will 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 2022 capital program and hedging activity, our expected material uses of cash
during 2022 include, among other possible uses: (1) cash settlements on commodity derivative
contracts and premiums for entering into new contracts (2) payments to service our debt; (3) domestic
income taxes; (4) asset retirement obligations; and (5) advancing carbon management activities. After
these material uses, we intend to return cash to shareholders through either future dividends or share
repurchases.
The table below summarizes our current and long-term material cash requirements as of
December 31, 2021 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 and finance leases(c)
. . . . . . . . . . . . . . . . . . . . . . . . $
Off-Balance Sheet
600 $
177
108
62
— $
43
17
12
— $
87
19
16
Purchase obligations(d)
. . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
136
1,083 $
54
126 $
42
164 $
600 $
47
15
11
10
683 $
—
—
57
23
30
110
(a) Represents the outstanding long-term debt balance as of December 31, 2021. See Part II, Item 8 – Financial Statements
and Supplementary Data, Note 1 Debt for more information on our long-term debt agreements.
(b) Represents undiscounted future obligations for defined benefit and supplemental plans.
(c) Our operating leases include drilling rigs, commercial office space, fleet vehicles and certain facilities. Our finance leases
include information technology equipment and are not material to our consolidated financial statements taken as a whole.
(d) Amounts include payments that will become due under long-term agreements to purchase goods and services used in the
normal course of business primarily including pipeline capacity and land leases. Purchase obligations for pipeline capacity
are based on contractual volumes and current market rates for that firm transportation capacity during the contract period.
Land leases reflect obligations for fixed payments under our term contracts. Also included is a commitment to invest
approximately $12 million in evaluation and development activities at one of our oil and natural gas properties prior to
January 1, 2023. During 2021, we entered into an amendment allowing us to accept certain land use requirements which,
at the time of acceptance on or before May 2022, will relieve us from our remaining obligation.
62
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, 2021 was $660 million, which was an
increase of $554 million, or 523%, from $106 million for the combined year ended December 31, 2020.
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 costs from higher
activity levels in 2021 as compared to 2020. Further, in 2021, we realized cost savings from actions taken
to reduce the size of our workforce and employee benefits along with other cost savings measures. Our
improved operating cash flow in 2021 reflects lower interest payments and professional fees compared to
2020 when we restructured our balance sheet through bankruptcy proceedings. With improved operating
cash flow in 2021, we took additional steps to protect our downside commodity price risk by entering into
derivative contracts, perform asset retirement activities and build our inventory of greenhouse gas
allowances.
Cash flows from investing activities – Our net cash used in investing activities was $161 million for the
year ended December 31, 2021, which was an increase of $124 million from $37 million in the combined
year ended December 31, 2020. This use of cash primarily related to a higher capital program in 2021 as
compared to 2020 when we reduced our capital investment to a level necessary to maintain the
mechanical integrity of our facilities. We sold the majority of our Ventura basin operations in 2021 and the
cash from this divestiture was partially offset by the cash paid for the acquisition of working interests in
certain joint venture wells held by MIRA. During the combined period ended December 31, 2020, we
realized cash proceeds of $41 million from the sale of royalty interests and non-core assets.
The table below summarizes net cash used in investing activities (in millions):
Successor
Predecessor
Year ended
December 31,
2021
November 1,
2020 - December
31, 2020
January 1, 2020 -
October 31, 2020
Combined
Year ended
December 31,
2020
Capital investments . . . . . . . . . . . . . . . .
Changes in capital investment
accruals . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions, divestitures and other . . .
Net cash used in investing
activities . . . . . . . . . . . . . . . . . . . . . . .
$
(194)
$
20
13
$
(161)
$
(7)
(1)
1
(7)
$
$
(40)
$
(24)
34
(30)
$
(47)
(25)
35
(37)
Cash flows from financing activities – Our net cash used in financing activities was $222 million for the
year ended December 31, 2021 and primarily related to distributions to BSP as well as repurchases of
our common stock under our Share Repurchase Program. During the year ended December 31, 2021,
we issued Senior Notes, the proceeds of which were used to repay our EHP Notes and our Second Lien
Term Loan with the remainder used to paydown our Revolving Credit Facility. See Part II, Item 8 –
Financial Statements and Supplementary Data, Note 4 Debt for additional information on our credit
agreements.
Our net cash used in financing activities was $58 million for the combined year ended December 31,
2020. Uses of cash in 2020 primarily related to our debt transactions as a result of our bankruptcy
proceedings and a payoff of $100 million of existing debt in January 2020. We also made $134 million of
distributions to noncontrolling interest holders in the combined period of 2020, which included payments
of $70 million to our former noncontrolling interest holder, ECR and $64 million to BSP. We raised
proceeds of $446 million from an equity issuance at the time of our emergence from bankruptcy.
63
The table below summarizes net cash (used) provided by financing activities for the years ended
December 31, 2021 and 2020 (in millions):
Successor
Predecessor
Year ended
December 31,
2021
November 1,
2020 - December
31, 2020
January 1, 2020 -
October 31, 2020
Combined
Year ended
December 31,
2020
Debt transactions . . . . . . . . . . . . . . . . . . . . .
Distributions to noncontrolling interest
holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repurchases of common stock . . . . . . . . .
Issuance of common stock . . . . . . . . . . . . .
Common stock dividends . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(12) $
(126)
$
(241) $
(50)
(148)
2
(14)
—
(30)
—
—
—
—
(104)
—
446
—
(3)
(367)
(134)
—
446
—
(3)
Net cash (used) provided by financing
activities . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(222) $
(156)
$
98
$
(58)
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, 2021 and 2020 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 is challenging BSEE’s order.
Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution
Agreement between us and Oxy. In September 2021, we accepted the indemnification claim from Oxy
and 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 policies and estimates that involve management’s judgment and that could
result in a material impact to the consolidated financial statements due to the levels of subjectivity and
judgment include the following:
64
Sensitivities
Our total proved reserves were
480 MMBoe and our total
proved developed reserves
were 405 MMBoe at
December 31, 2021. We
estimate our 2022 DD&A rate
for our oil and natural gas
producing properties using the
unit-of-production method will
be approximately $4.50/Boe. A
5% change in our reserves
would increase or decrease this
DD&A rate by approximately
$0.25/Boe.
If realized prices used in our
year-end reserve estimates
increased or decreased by
10%, our proved reserve
quantities at December 31,
2021 would have increased by
4 MMBoe or decreased by 8
MMBoe, respectively.
Title
Reserves
Judgments 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
derived using a number of
methods, including estimates
from decline-curve analysis,
type-curve analysis, material
balance calculations, which
consider the volumes of
substances replacing the
volumes produced and
associated reservoir pressure
changes, 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.
Description
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 our asset
retirement obligations.
65
Title
Description
Realizability of
Deferred Tax
Assets
We record deferred tax
assets and liabilities to
account for the expected
future tax consequences of
events that have been
recognized in our financial
statements and our tax
returns. We routinely
assess the realizability of
our deferred tax assets. If
we conclude that it is
more-likely-than-not that
some portion or all of our
deferred tax assets will not
be realized, the deferred
tax asset is reduced to the
amount realizable by a
valuation allowance.
Judgments and
Uncertainties
In making such
assessments regarding the
realizability of our deferred
tax assets, numerous
judgments and
assumptions are inherent
in the determination of
whether sufficient future
taxable income will be
generated to permit
realization of existing
deferred tax assets.
Significant assumptions
include commodity price
curves and estimates of
future expected operating,
development and
abandonment costs. We
also evaluate whether we
are in a three-year
cumulative income position
and our historic earnings
trends which may support
our ability to protect future
taxable income.
Sensitivities
At December 31, 2020, we
had a tax valuation
allowance of $549 million
against our entire U.S.
federal and state deferred
tax assets. During 2021, we
realized substantial
improvements in commodity
prices and have an
improved financial position.
At December 31, 2021, we
assessed the realizability of
our deferred tax assets and
determined that all our
deferred tax assets are
more-likely-than-not
realizable. Changes in
assumptions or changes in
tax laws and regulations
could materially affect the
recognized amount of
valuation allowance.
Significant Accounting and Disclosure Changes
See Part II, Item 8 – Financial Statements and Supplementary Data, Note 1 Nature of Business,
Summary of Significant Accounting Policies and Other for a discussion of new accounting standards.
66
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 and the
potential for sustained low oil, natural gas
and natural gas liquids prices;
legislative or regulatory changes, including
those related to (i) drilling, completion, well
stimulation, operation, maintenance or
abandonment of wells or facilities,
(ii) managing energy, water, land,
greenhouse gases (GHGs) or other
emissions, (iii) protection of health, safety
and the environment, (iv) tax credits or
other incentives, or (v) transportation,
marketing and sale of our products;
availability or timing of, or conditions
imposed on, permits and approvals
necessary for drilling or development
projects;
changes in business strategy and our
capital plan;
lower-than-expected production, reserves
or resources from development projects or
acquisitions, or higher-than-expected
decline rates;
incorrect estimates of reserves and related
future cash flows and the inability to replace
reserves;
the recoverability of resources and
unexpected geologic conditions;
our ability to realize the benefits of business
strategies and initiatives related to energy
transition, including carbon capture and
storage projects and other renewable
energy efforts;
our ability to finance and implement our
carbon capture and storage projects;
global geopolitical, socio-demographic and
economic trends and technological
innovations;
changes in our dividend policy and our
ability to declare future dividends;
production-sharing contracts’ effects on
production and operating costs;
67
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
limitations on our financial flexibility due to
existing and future debt;
insufficient cash flow to fund planned
investments, interest payments on our debt,
stock repurchases or changes to our capital
plan;
insufficient capital or liquidity unavailability
of capital markets or inability to attract
potential investors;
limitations on transportation or storage
capacity and the need to shut-in wells;
inability to enter into desirable transactions,
including acquisitions, asset sales and joint
ventures;
joint ventures and acquisitions and our
ability to achieve expected synergies;
our ability to utilize our net operating loss
carryforwards to reduce our income tax
obligations;
our ability to successfully gather and verify
data regarding emissions, our
environmental impacts and other initiatives;
the compliance of various third parties with
our policies and procedures and legal
requirements as well as contracts we enter
into in connection with our climate-related
initiatives;
the effect of our stock price on costs
associated with incentive compensation;
changes in the intensity of competition in
the oil and gas industry;
effects of hedging transactions;
equipment, service or labor price inflation or
unavailability;
climate-related conditions and weather
events;
disruptions due to accidents, mechanical
failures, power outages, transportation or
storage constraints, natural disasters, labor
difficulties, cyber-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.
68
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 term as a result of our current hedges in place. As of December 31, 2021, we had hedges on
approximately 80% of our anticipated oil production through 2022 and approximately 50% through 2023,
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, 2021, we
had net liabilities of $395 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
$165 million in 2022 and $101 million in 2023, limiting our upside. We estimate that a $10 decrease in Brent
oil forward prices could decrease our settlement payments by $162 million in 2022 and $101 million in
2023, negating the downside price movement for hedged volumes.
A summary of our Brent-based crude oil derivative contracts at December 31, 2021 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 customer 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 and
accelerate payment dates. Approximately 60% of our production during 2021 was oil which was sold
predominately to refineries in California. As of December 31, 2021, trade receivables for all commodities
were collected within 30 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. 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
As discussed in Part II, Item 8 – Financial Statements and Supplementary Data, Note 4 Debt, we issued
$600 million of Senior Notes in January 2021 the net proceeds of which were used to repay in full our
Second Lien Term Loan and repay all the outstanding EHP Notes with the remainder used to repay
substantially all of the then outstanding borrowings under our Revolving Credit Facility. Our new Senior
Notes bear interest at a fixed rate of 7.125% per annum. We had no variable-rate debt outstanding as of
December 31, 2021.
In May 2018, we entered into derivative contracts that limit our interest rate exposure with respect to
$1.3 billion of our variable-rate indebtedness. These interest-rate contracts reset monthly and require the
counterparties to pay any excess interest owed on such amount in the event the one-month LIBOR
exceeds 2.75% for any monthly period prior to May 4, 2021. The contracts expired on May 4, 2021. We did
not report any gains or losses on these contracts for the years ended December 31, 2021 or 2020. No
settlement payments were received in either 2021 or 2020.
69
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, 2021 and 2020, the related consolidated statements of
operations, comprehensive income (loss), changes in stockholders’ equity (deficit), and cash flows for the
year ended December 31, 2021 (Successor), for the periods from November 1, 2020 to December 31,
2020 (Successor) and January 1, 2020 to October 31, 2020 (Predecessor), and for the year ended
December 31, 2019 (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, 2021, 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 present fairly, in all material respects, the financial
position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash
flows for the year ended December 31, 2021 (Successor), for the periods ended November 1, 2020 to
December 31, 2020 (Successor) and January 1, 2020 to October 31, 2020 (Predecessor), and for the year
ended December 31, 2019 (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, 2021 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, 2021 and 2020 and for the Successor
period 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
70
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 Matter
The critical audit matter communicated below is a matter arising from the current period audit of the
consolidated financial statements that was communicated or required to be communicated to the audit
committee and that: (1) relates 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 a critical audit matter 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 matter below, providing a
separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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 $213 million for the year ended
December 31, 2021 (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
71
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.
/s/ KPMG LLP
We have served as the Company’s auditor since 2014.
Los Angeles, California
February 25, 2022
72
CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2021 and 2020
(in millions, except share data)
2021
2020
CURRENT ASSETS
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Trade receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets held for sale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTY, PLANT AND EQUIPMENT . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depreciation, depletion and amortization . . . . . . . . . . .
Total property, plant and equipment, net
. . . . . . . . . . . . . . . . . . .
DEFERRED TAX ASSET . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OTHER NONCURRENT ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
305
245
60
22
121
753
2,845
(246)
2,599
396
98
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,846
$
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, 2021 or 2020 . . . . . . . . . . .
Common stock (200 million shares authorized at $0.01 par value);
(83,389,210 and 83,319,660 shares issued; 79,299,222 and
83,319,660 shares outstanding at December 31, 2021 and 2020,
respectively) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock (4,089,988 shares held at cost at December 31,
2021 and no shares held at December 31, 2020) . . . . . . . . . . . . . . .
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings (accumulated deficit) . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive income (loss) . . . . . . . . . . . . . . .
Total equity attributable to common stock . . . . . . . . . . . . . . . . . .
Equity attributable to noncontrolling interests . . . . . . . . . . . . . . . . . .
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
266
21
270
297
854
589
132
438
145
—
1
(148)
1,288
475
72
1,688
—
1,688
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY . . . . . . . . . . . . $
3,846
$
The accompanying notes are an integral part of these consolidated financial statements.
73
28
177
61
—
63
329
2,689
(34)
2,655
—
90
3,074
212
—
50
211
473
597
6
547
269
—
1
—
1,268
(123)
(8)
1,138
44
1,182
3,074
CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
For the year ended December 31, 2021, the period from November 1, 2020 through
December 31, 2020, the period from January 1, 2020 through October 31, 2020 and the year
ended December 31, 2019
(in millions, except share and per share data)
REVENUES
Oil, natural gas and NGL sales . . . . . . . . . .
Net (loss) gain from commodity
derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales of purchased natural gas . . . . . . . . . .
Electricity sales . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . .
Gain on asset divestitures . . . . . . . . . . . . . .
OPERATING INCOME (LOSS) . . . . . . . . . . . .
NON-OPERATING (EXPENSES) INCOME
Reorganization items, net . . . . . . . . . . . . . . .
Interest and debt expense, net . . . . . . . . . . .
Net (loss) gain on early extinguishment of
debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-operating expenses, net . . . . . . .
INCOME (LOSS) BEFORE INCOME
TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit (provision) . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
$
2,048
$
237
$
1,092
$
2,270
(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)
(141)
38
15
3
152
114
40
34
—
10
1
24
10
8
8
9
258
—
(106)
(3)
(11)
—
(5)
(125)
—
(125)
—
2
2
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)
5
(84)
1,996
—
1,996
(94)
(13)
(107)
$
$
$
612
$
(123)
7.46
7.37
$
$
82.0
83.0
(1.48)
(1.48)
83.3
83.3
$
$
$
1,889
$
40.59
40.42
$
$
49.4
49.6
(59)
286
112
25
2,634
895
290
471
—
157
29
201
68
40
36
18
2,205
—
429
—
(383)
126
(72)
100
(1)
99
(117)
(10)
(127)
(28)
(0.57)
(0.57)
49.0
49.0
The accompanying notes are an integral part of these consolidated financial statements.
74
CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)
For the year ended December 31, 2021, the period from November 1, 2020 through
December 31, 2020, the period from January 1, 2020 through October 31, 2020 and the year
ended December 31, 2019
(in millions)
Net income (loss) . . . . . . . . . . . . . .
Net (income) loss attributable to
noncontrolling interests . . . . . . . . . .
Other comprehensive income
(loss):
Actuarial gains (losses)
associated with pension and
postretirement plans(a)
. . . . . . .
Prior service credit(a) . . . . . . . . .
Amortization of prior service
cost credit included in net
periodic benefit cost
. . . . . . . . .
Comprehensive income (loss)
attributable to common stock . . .
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
$
625
$
(125)
$
1,996
$
99
(13)
2
(107)
(127)
16
65
(1)
(8)
—
—
(2)
2
—
(24)
7
—
$
692
$
(131)
$
1,889
$
(45)
(a) No associated tax has been recorded for the components of other comprehensive (loss) income for 2021, 2020 or 2019.
See Note 12 Pension and Postretirement Benefit Plans for additional information on the components of other
comprehensive income related to our defined benefit plans.
The accompanying notes are an integral part of these consolidated financial statements.
75
CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
For the year ended December 31, 2021, the period from November 1, 2020 through
December 31, 2020, the period from January 1, 2020 through October 31, 2020 and the year
ended December 31, 2019
(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
$
(5,342)
(28)
$
(6)
—
$
(361)
(28)
$
114
10
$
(247)
(18)
—
—
—
. . . . . . . . . .
Balance, December 31,
2018 . . . . . . . . . . . . . . . . . $ — $ — $ 4,987
—
Net (loss) income . . . .
Contribution from
noncontrolling interest
holder, net
Distributions to
noncontrolling interest
holders . . . . . . . . . . . . .
Other comprehensive
loss . . . . . . . . . . . . . . . .
Warrant issued . . . . . .
Share-based
compensation, net . . . .
Balance, December 31,
2019 . . . . . . . . . . . . . . . . . $ — $ — $ 5,004
—
—
—
—
—
—
3
14
—
—
—
—
—
—
—
—
—
—
—
—
—
$
(5,370)
1,889
$
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 . . .
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
—
—
—
—
—
—
—
—
10
138
128
261
408
71
12
445
15
—
—
—
—
—
—
—
—
—
—
—
—
(5,224)
3,481
Balance, October 31,
2020 . . . . . . . . . . . . . . . . . $
1
$ — $ 1,268
$
—
$
The accompanying notes are an integral part of these consolidated financial statements.
76
—
—
(17)
—
(23)
—
—
—
—
—
—
—
—
—
—
—
—
23
—
—
—
(17)
3
14
$
(389)
1,889
$
—
10
138
128
261
408
71
12
446
15
—
(1,720)
49
(80)
—
—
93
13
(37)
—
—
—
—
—
—
—
—
—
7
—
49
(80)
(17)
3
14
$
(296)
1,902
(37)
10
138
128
261
408
71
12
446
15
7
(1,720)
$ 1,269
$
76
$ 1,345
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
— $ 1,268 $
—
—
— $
(123)
— $
—
1,269
(123)
$
76
(2)
$ 1,345
(125)
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 . . . . . . . . . . . . . . .
. . . . . . . . . . . . .
$
$
1
—
—
—
1
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $ 1,268 $
—
—
(123)
612
$
—
—
—
(148)
—
—
—
—
7
13
—
2
(2)
—
—
(14)
—
—
—
—
—
—
—
(8)
(8)
—
—
—
—
—
—
—
80
72
—
(8)
$
1,138
612
$
—
(14)
7
13
(148)
2
(2)
80
(30)
—
44
13
(50)
(7)
—
—
—
—
—
(30)
(8)
$ 1,182
625
(50)
(14)
—
13
(148)
2
(2)
80
$
1,688
$
— $ 1,688
Balance, December 31,
2021 . . . . . . . . . . . . . . . . . $
1
$ (148) $ 1,288 $
475
$
Note: Excludes amounts related to redeemable noncontrolling interests recorded in mezzanine equity.
(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 14 Chapter 11 Proceedings for more information.
The accompanying notes are an integral part of these consolidated financial statements.
77
CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the year ended December 31, 2021, the period from November 1, 2020 through
December 31, 2020, the period from January 1, 2020 through October 31, 2020 and the year
ended December 31, 2019
(in millions)
CASH FLOW FROM OPERATING
ACTIVITIES
Net income (loss) . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion and
amortization . . . . . . . . . . . . . . . . . . . .
Deferred income tax benefit . . . . . . . .
Asset impairment
. . . . . . . . . . . . . . . .
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 . . . . . . .
Gain on asset divestitures . . . . . . . . .
Other non-cash charges to income,
net . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reorganization items, net
(non-cash)
Reorganization items, net
(debtor-in-possession financing
costs)
. . . . . . . . . . . . . . . . . . . . . . . . .
Dry hole expenses . . . . . . . . . . . . . . .
Changes in operating assets and liabilities,
net:
. . . . . . . . . . . . . . . . . . . . .
(Increase) decrease in trade
receivables . . . . . . . . . . . . . . . . . . . . .
Decrease (increase) in inventories . . .
(Increase) decrease in other current
assets . . . . . . . . . . . . . . . . . . . . . . . . .
Increase (decrease) 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 . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . .
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
$
625
$
(125)
$
1,996
$
99
213
(396)
28
676
(319)
2
—
(124)
62
—
—
—
(68)
—
(47)
8
660
(194)
20
67
(52)
(2)
(161)
—
—
—
—
16
(115)
—
—
600
34
—
—
141
(1)
—
—
—
27
—
—
—
(28)
1
6
(67)
(12)
(7)
(1)
—
—
1
(7)
—
—
—
—
82
(208)
—
—
—
328
—
1,736
(91)
108
(5)
(39)
—
60
(4,128)
25
—
128
(1)
2
(1)
118
(40)
(24)
41
—
(7)
(30)
797
(1,315)
802
(802)
225
—
200
(25)
—
471
—
—
59
111
(126)
(70)
—
131
—
—
7
22
—
(1)
(27)
676
(455)
(85)
164
(6)
(12)
(394)
2,330
(2,353)
—
—
—
—
—
—
—
The accompanying notes are an integral part of these consolidated financial statements.
78
Debt repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
—
(13)
(200)
(300)
—
—
(50)
(148)
(14)
—
2
—
(222)
277
28
305 $
—
—
—
—
—
—
(30)
—
—
—
—
—
(156)
(175)
203
28
$
(3)
(20)
—
—
(100)
—
(104)
—
—
(2)
446
(1)
98
186
17
203 $
(156)
(2)
—
—
—
49
(151)
—
—
—
4
(3)
(282)
—
17
17
The accompanying notes are an integral part of these consolidated financial statements.
79
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.
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 proportionately consolidate our
share of revenue and costs related to our development joint ventures with Alpine Energy Capital, LLC
(Alpine) and Royale Energy, Inc. (Royale). In October 2021, the development agreement with Alpine
was terminated. The termination does not affect the 90% working interest earned by Alpine in wells
previously drilled. In December 2021, the development joint venture with Royale was mutually
terminated by both parties and our operating results include activity through the termination date. Our
consolidated results reflect only our working interest share in the productive wells in our development
joint venture with Alpine.
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 14 Chapter 11 Proceedings and
Note 15 Fresh Start Accounting for additional information on our bankruptcy proceedings and the
impact of fresh start accounting on our consolidated financial statements.
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.
80
Risks and Uncertainties
Our revenue, profitability and future growth 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 and economic conditions. Additionally, the Coronavirus Disease 2019 (COVID-19) pandemic
continues to create price volatility for the oil and gas industry. The ongoing impacts from 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, vaccine availability and acceptance by individuals,
resurgence of the pandemic or further mutations of the virus and pandemic restrictions being
reinstated, among other things.
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, 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 and
for the year ended December 31, 2019, 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
We adopted new accounting guidance on current expected credit losses on January 1, 2020, using
a modified retrospective approach to the first period in which the guidance was effective. The new
rules changed the measurement of credit losses for financial assets and certain other instruments,
including trade and other receivables with a right to receive cash, and require the use of a new
forward-looking expected loss model that results in the earlier recognition of an allowance for losses.
The adoption of these new rules did not have a significant impact on our consolidated financial
statements.
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 14 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 15 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.
81
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.
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, 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.
82
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 25
years for a commercial office building we own in Bakersfield, California and 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.
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 property, plant and equipment (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.
83
Commodity sales contracts — Disaggregated revenue for sales of oil, natural gas and natural gas
liquids (NGLs) to customers includes the following:
(in millions)
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
Oil . . . . . . . . . . . . . . . . . . . . . . .
NGLs . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . .
Oil, natural gas and NGL
sales . . . . . . . . . . . . . . . . . . .
$
$
$
1,555
250
243
$
176
29
32
$
874
106
112
1,884
179
207
2,048
$
237
$
1,092
$
2,270
See Note 13 Revenue Recognition for more information on our revenue from contracts with
customers.
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, 2021 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:
(in millions)
Successor
2021
Predecessor
2020
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Finished goods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
54 $
6
60 $
58
3
61
Derivative Instruments
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.
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 9 Stock-Based Compensation.
84
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 record an adjustment to both the ARO and PP&E. Over time the liability is
increased, and expense is recognized for accretion, and the capitalized cost is recovered over either
the useful life of our facilities or the unit-of-production method for our minerals.
At certain of our facilities, we have identified ARO that are related mainly to plant and field
decommissioning, including plugging and abandonment of wells. In certain cases, we do not know or
cannot estimate when we would perform the ARO work and, therefore, we cannot reasonably estimate
the fair value of these liabilities. 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.
The following table presents a rollforward of our ARO.
(in millions)
Beginning balance . . . . . . . . . . . . . . . . . . $
Liabilities settled and divested . . . . . . . .
Accretion expense on discounted
obligation . . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of estimated obligation . . . . . .
Impact of fresh start accounting . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities reclassified as held for sale . . .
Ending balance . . . . . . . . . . . . . . . . . . . . . $
Current portion . . . . . . . . . . . . . . . . . . . . . $
Non-current portion . . . . . . . . . . . . . . . . . . $
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
597
(157)
$
593
(5)
$
50
19
—
1
(21)
489
51
438
$
$
$
8
—
—
1
—
597
50
547
$
$
$
517
(16)
33
—
57
2
—
593
50
543
During 2021, our total asset retirement obligation decreased by $108 million, including $21 million
of liabilities reclassified as held for sale. Our liability decreased by $157 million including $42 million for
settlement payments and $115 million of liabilities assumed as part of our Ventura divestiture.
Revisions to our future cost estimates and abandonment dates for our oil and gas assets resulted in an
increase of $19 million. See Note 3 Divestitures and Acquisitions for more information on our sold
properties and our liabilities reclassified as held for sale.
85
In 2020, upon emergence from bankruptcy and the adoption of fresh start accounting, ARO liabilities
were adjusted to their estimated fair value resulting in a $57 million increase to our obligations at that
time. See Note 15 Fresh Start Accounting for more information on our fresh start accounting adjustments.
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 bases. 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.
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 15% of our total production for the year ended December 31, 2021.
In line with industry practice for reporting PSCs, we report 100% of operating costs under such
contracts in 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.
86
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.
Leases
We account for our leases, 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
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 considered whether there was an identifiable asset and then
considered 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 considered the average cost of borrowing for publicly traded corporate bond yields, which were
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 recognized 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. Our finance leases are not significant. 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, 2021 include the remaining assets and the
associated asset retirement obligations in the Ventura basin. See Note 3 Divestitures and Acquisitions
for more information.
87
Other Current Assets
Other current assets consisted of the following:
(in millions)
Successor
December 31,
2021
December 31,
2020
Amounts due from joint interest partners . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid greenhouse gas allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Collateral on natural gas purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
47 $
6
16
31
12
9
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
121 $
42
—
20
—
—
1
63
Other Noncurrent Assets
Other noncurrent assets consisted of the following:
(in millions)
Successor
December 31,
2021
December 31,
2020
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
43 $
11
11
21
1
11
98 $
38
17
11
14
—
10
90
Accrued Liabilities
Accrued liabilities consisted of the following:
(in millions)
Successor
December 31,
2021
December 31,
2020
Accrued employee-related costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued taxes other than on income . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lease liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred premiums on derivative contracts . . . . . . . . . . . . . . . . . . . . . . .
Net settlement payments due on derivative contracts . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
61 $
30
51
19
11
57
25
43
297 $
72
36
50
1
7
18
3
24
211
As of December 31, 2020, accrued employee-related costs included approximately $5 million of
payroll taxes deferred under COVID-19 relief, half of which was paid before December 31, 2021 with
the remainder due on or before December 31, 2022.
88
Other Long-Term Liabilities
Other long-term liabilities consisted of the following:
(in millions)
Successor
December 31,
2021
December 31,
2020
Compensation-related liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Postretirement and pension benefit plans . . . . . . . . . . . . . . . . . . . . . . . .
Lease liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred premiums on derivative contracts . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
38
59
37
5
6
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
145 $
44
140
35
31
19
269
Other Operating Expenses, net
Other operating expenses, net consisted of the following:
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
(in millions)
Severance and termination
costs . . . . . . . . . . . . . . . . . . . .
Deficiency payment on a
pipeline delivery contract . . . .
Idle well fees . . . . . . . . . . . . . .
Power plant interruption . . . . .
Ad valorem fees . . . . . . . . . . .
. . . . . . . . . . . . . . . .
Other, net
$
15
$
5
$
10 $
—
6
—
—
8
—
—
—
—
4
20
4
7
4
11
Other operating expenses,
net
. . . . . . . . . . . . . . . . . . . .
$
29
$
9
$
56 $
89
—
—
3
1
—
14
18
Reorganization Items, net
Reorganization items, net consisted of the following (in millions):
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
$
— $
— $
4,022
—
—
—
—
— $
(6)
—
(6) $
$
$
—
—
—
—
— $
(3)
—
(3)
$
125
(12)
(5)
(2)
4,128
(43)
(25)
4,060
(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
Supplemental Cash Flow Information
Supplemental disclosures to our consolidated statements of cash flows, excluding leases, are
presented below (in millions):
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
Supplemental Cash Flow Information
Cash paid for interest, net of amounts
capitalized . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . .
Warrant issued to a joint venture
partner . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative related to additional
earn-out consideration for the Ventura
divestiture . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
(28) $
(8)
$
(79) $
(425)
— $
— $
— $
— $
— $
— $
(494) $
— $
(12) $
— $
(561) $
— $
— $
(52) $
— $
3
$
— $
— $
90
—
—
—
—
(3)
—
NOTE 2 PROPERTY, PLANT AND EQUIPMENT
We capitalize the costs incurred to acquire or develop our oil and natural gas assets, including ARO
and capitalized 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.
Property, plant and equipment, net consisted of the following:
(in millions)
Successor
December 31,
2021
December 31,
2020
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 . . . . . . . . . .
2,604 $
1
240
2,845
(246)
Total property, plant and equipment, net(a) . . . . . . . . . . . . . . . .
$
2,599 $
2,416
1
272
2,689
(34)
2,655
(a) Upon our emergence from bankruptcy, we adopted fresh start accounting on October 31, 2020. At that time, we remeasured
our assets at their relative fair value. See Note 15 Fresh Start Accounting for more information.
The following table summarizes the activity of capitalized exploratory well costs:
(in millions)
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
Beginning balance . . . . . . . . . . . $
Additions to capitalized
exploratory well costs . . . . . . . .
Reclassification to property,
plant and equipment
. . . . . . . . .
Charged to expense . . . . . . . . .
Impact of fresh start
accounting . . . . . . . . . . . . . . . . .
Ending balance . . . . . . . . . . . . . $
3
$
3
$
7
$
—
—
(2)
—
1
$
—
—
—
—
3
—
—
(2)
(2)
$
3
$
5
12
(3)
(7)
—
7
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, 2021 are for permitted wells that we intend to drill.
Asset Impairments
Asset impairments were $28 million for the year ended December 31, 2021, including $25 million
related to the write-down of a commercial office building located in Bakersfield, California 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
resulted in an impairment as of our September 30, 2021 assessment date. In January 2022, we
entered into an agreement to sell our commercial office building for $15 million. See Note 16
Subsequent Events for details of this potential divestiture. We determined that this asset did not meet
the requirements to be classified as held for sale at December 31, 2021.
91
The following table presents a summary of our asset impairments during the Predecessor period of
2020 (in millions):
Predecessor
January 1, 2020 -
October 31, 2020
Proved oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,487
228
21
1,736
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 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 or the year ended
December 31, 2019.
NOTE 3 DIVESTITURES AND ACQUISITIONS
Divestitures
Ventura Basin Transactions
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. In
total, we will receive cash consideration of up to $102 million, before purchase price adjustments, plus
additional earn-out consideration that is linked to future commodity prices. The consideration, exclusive
of the earn-out, includes $82 million of total cash consideration (subject to purchase price adjustments)
and up to $20 million of potential additional consideration if the buyer does not perform certain
abandonment obligations with respect to the divested properties. The additional consideration is
secured by production payments of $20 million over a five-year period. To the extent the buyer satisfies
all of the required abandonment obligations within a five-year period following the initial close date,
none of the $20 million of potential additional consideration will be paid to us.
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. We expect to divest of the remaining assets in the Ventura basin
during the first half of 2022. These remaining assets, consisting of property, plant and equipment and
the associated asset retirement obligations, are classified as held for sale on our consolidated balance
sheet as of December 31, 2021.
92
Lost Hills Transactions
In May 2019, we sold 50% of our working interest and transferred operatorship in certain horizons
within our Lost Hills field, located in the San Joaquin basin, for proceeds of $164 million (after
transaction costs and purchase price adjustments) plus a carried 200-well development program. The
partial sale of proved property was accounted for as a normal retirement with no gain or loss
recognized. The partial sale of unproved property was recorded as a recovery of cost.
On February 1, 2022, we sold our remaining 50% non-operated working interest in these horizons
for proceeds of $55 million (before transaction costs and purchase price adjustments). See Note 16
Subsequent Events for more information on our Lost Hills divestiture.
Other Divestitures
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.
See Note 16 Subsequent Events for details on an agreement entered into in January 2022 related
to our commercial office building located in Bakersfield, California.
Acquisitions
MIRA JV Acquisition
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
the San Joaquin basin in exchange for a 90% working interest in the related properties. In August
2021, we purchased MIRA’s entire working interest share in the conveyed assets for net cash payment
of $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 2019, we had several acquisitions of non-core properties totaling approximately $6 million.
93
NOTE 4 DEBT
As of December 31, 2021 and 2020, our long-term debt consisted of the following (in millions):
Successor
Interest Rate
Maturity
2021
2020
Revolving Credit Facility(a)
. . . . . . . . . . . $
— $
Senior Notes . . . . . . . . . . . . . . . . . . . . . .
Second Lien Term Loan . . . . . . . . . . . . .
EHP Notes . . . . . . . . . . . . . . . . . . . . . . . .
Principal amount of debt . . . . . . . . . $
Unamortized debt issuance costs . . . . .
Long-term debt, net . . . . . . . . . . . . . . $
600
—
—
600 $
(11)
589 $
99
—
LIBOR plus 3%-4%
ABR plus 2%-3%
7.125%
200 LIBOR plus 9%-10.5%
ABR plus 8%-9.5%
6%
300
599
(2)
597
April 29, 2024
February 1, 2026
October 27, 2025
October 27, 2027
(a)
In February 2022, we amended our Revolving Credit Facility to replace London Interbank Offered Rates (LIBOR). See
Note 16 Subsequent Events, for further information on this amendment.
Fair Value
The estimated fair value of our debt at December 31, 2021 and 2020, including the fair value of the
variable-rate portion, was approximately $623 million and $599 million, respectively, compared to a
face value of approximately $600 million and $599 million, respectively. We estimate the fair value of
fixed-rate debt based on prices known from market transactions as of December 31, 2021 (Level1).
We estimate the fair value of fixed-rate debt based on unobservable inputs as of December 31, 2020
(Level 3). We estimate the fair value of our variable rate debt approximates its carrying value.
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 $492 million, which we are permitted to
increase if we obtain additional commitments from new or existing lenders. Our Revolving Credit
Facility also includes a sub-limit of $200 million for the issuance of letters of credit. As of December 31,
2021, we had approximately $367 million available for borrowing under the Revolving Credit Facility
after taking into account $125 million of outstanding letters of credit. See Note 16 Subsequent Events
for information on additional commitments.
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 – We could elect to borrow at either an adjusted LIBOR rate or an ABR rate, 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 adjusted LIBOR rate plus 1%. The applicable margin is adjusted based on the borrowing
base utilization percentage and will vary from (i) in the case of LIBOR 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 LIBOR loans is payable at the end of each LIBOR period, but not less
than quarterly. In February 2022, we amended our Revolving Credit Facility to replace LIBOR with the
secured overnight financing rate (SOFR) as administered by the Federal Reserve Bank of New York.
See Note 16 Subsequent Events, for further information on this amendment.
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.
94
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
secured 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.
Our Revolving Credit Facility also requires us to maintain hedges on a minimum amount of crude oil
production, determined semi-annually, of no less than (i) 75% of our reasonably anticipated oil
production from our proved reserves during the period November 1, 2020 through October 31, 2022,
and (ii) 50% of our reasonably anticipated oil production from our proved reserves during the period
November 1, 2022 through October 31, 2023. The Revolving Credit Facility specifies the forms of
hedges and prices (which can be prevailing prices) that must be used for a portion of those hedges.
Further, our Revolving Credit Facility requires us to maintain acceptable commodity hedges for no
less than 50% of the reasonably anticipated oil production from our proved reserves for at least 24
months following the date of delivery of each reserve report if our leverage ratio is greater than
2.00:1.00. If our leverage ratio is less than 2.00:1.00, then the minimum amount of hedges that we are
required to maintain is reduced from 50% to 33%. Currently, we may not hedge more than 85% of
reasonably anticipated total forecasted production of crude oil, natural gas and NGLs from our oil and
gas properties for a 48-month period, except that we may purchase puts and floors up to 100% of such
production. The percentage of our crude oil production hedged is calculated exclusive of offsetting
positions on our derivative contracts.
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.
95
Redemption – Prior to February 1, 2023, we may elect to redeem up to 35% of the aggregate
principal amount of our Senior Notes with an amount of cash not greater than the net cash proceeds from
certain equity offerings at a redemption price equal to 107% of the aggregate amount of the Senior Notes
redeemed, plus accrued and unpaid interest. In addition, prior to February 1, 2023, we may redeem the
Senior Notes at a “make whole” premium plus accrued and unpaid interest. 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.
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.
96
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.
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, 2021, 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, 2021, we were in compliance with all debt covenants under our credit
agreements.
97
Principal maturities of debt outstanding at December 31, 2021 (Successor) are as follows:
As of
December 31, 2021
(in millions)
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
—
—
—
—
600
—
600
NOTE 5 LEASES
Balance sheet information related to our operating and finance leases as of December 31, 2021
and December 31, 2020 were as follows:
Classification
Assets
Operating . . . . . . . . . . . . . . . . Other noncurrent assets $
Finance . . . . . . . . . . . . . . . . . .
PP&E
Total right-of-use assets . . . .
Liabilities
Current
Operating . . . . . . . . . . . . . . .
Finance . . . . . . . . . . . . . . . .
Accrued liabilities
Accrued liabilities
Long-term
Operating . . . . . . . . . . . . . . . Other long-term liabilities
Total lease liabilities . . . . . . . .
$
$
$
Successor
2021
(in millions)
2020
(in millions)
43 $
—
43 $
11 $
—
37
48 $
38
1
39
6
1
35
42
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 renew, which we exercise at our
sole discretion, and 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.
98
Our lease costs, including amounts capitalized to PP&E, were as follows:
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
(in millions)
14 $
48
4
66
—
(2)
64 $
2 $
7
—
9
—
—
9 $
(in millions)
23
25
4
52
1
(1)
52
Operating lease costs . . . . . . . . . $
Short-term lease costs(a) . . . . . . .
Variable lease costs . . . . . . . . . . .
Total operating lease costs . . .
Finance lease costs . . . . . . . . . . .
Sublease income . . . . . . . . . . . . .
Total lease costs . . . . . . . . . . . . . $
(a) Contracts with terms of less than one month or less are excluded from our disclosure of short-term lease costs.
We have two contracts treated as finance leases, which were not material to our consolidated
results of operations.
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. 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,
2021 and December 31, 2020 is provided below:
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
(in millions)
(in millions)
Cash paid for amounts included
in the measurement of lease
liabilities
Operating cash flows . . . . . . . . $
Investing cash flows . . . . . . . . . $
Financing cash flows . . . . . . . . $
ROU assets obtained in
exchange for new operating lease
liabilities . . . . . . . . . . . . . . . . . . . . . $
Impairment charges related to
ROU assets . . . . . . . . . . . . . . . . . . $
8 $
4 $
1 $
17 $
— $
2 $
— $
— $
— $
— $
Successor
2021
2020
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 . . . . . . . . . . . . . . . . . . . . . . . . .
8.25
5.4 %
0.33
4.0 %
99
9
14
1
—
2
6.81
4.5 %
1.33
4.0 %
The difference in the weighted-average discount rate between operating leases and finance leases
primarily relates to lease term.
Maturities of our operating liabilities at December 31, 2021 are as follows:
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Less: Interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Successor
Operating
Leases
(in millions)
12
8
8
6
5
23
(14)
48
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, 2021 and 2020 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.
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 is challenging BSEE’s order.
Oxy notified us of the claim under the indemnification provisions of the Separation and Distribution
Agreement between us and Oxy. In September 2021, we accepted the indemnification claim from Oxy
and we are now appealing the order from BSEE.
We have certain commitments under contracts, including purchase commitments for goods and
services used in the normal course of business such as pipeline capacity, land easements and field
equipment. We also have a capital commitment of $12 million in 2022 for evaluation and development
activities at one of our oil and natural gas properties. During 2021, we entered into an agreement which
will relieve us from our remaining obligation upon acceptance of certain land use requirements which
may occur on or before May 2022.
100
At December 31, 2021, total purchase obligations on a discounted basis were as follows:
December 31,
2021
(in millions)
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of purchase obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
54
32
10
5
5
30
136
(18)
118
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, 2021, 2020 and 2019. 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, 2021:
Sold Calls:
Q1
2022
Q2
2022
Q3
2022
Q4
2022
2023
Barrels per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14,790
Weighted-average price per barrel . . . . . . . . . . . . . . $ 60.37 $ 60.63 $ 60.76 $ 57.82 $ 58.01
35,347
25,167
35,343
34,380
Swaps
Barrels per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,937
Weighted-average price per barrel . . . . . . . . . . . . . . $ 54.38 $ 54.12 $ 53.97 $ 58.79 $ 59.08
17,263
10,476
10,669
12,369
Net Purchased Puts(a)
Barrels per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
14,790
Weighted-average price per barrel . . . . . . . . . . . . . . $ 53.32 $ 54.69 $ 55.95 $ 57.22 $ 40.00
34,380
35,343
25,167
35,347
Sold Puts
Barrels per day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-average price per barrel . . . . . . . . . . . . . . $ 32.00 $
6,869
— 4,000
— $ 32.00 $ 32.00 $
1,348
—
—
(a) Purchased puts and sold puts with the same strike price have been presented on a net basis.
101
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.
• Purchased puts – we receive settlement payments for prices below the indicated weighted-
average price per barrel.
• Sold puts – we make 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.
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, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
(in millions)
Non-cash commodity
derivative 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
(357) $
(138)
$
(19) $
(166)
—
(357)
(319)
(2)
(140)
(1)
2
(17)
108
(676) $
(141)
$
91 $
(4)
(170)
111
(59)
In May 2018, we entered into derivative contracts that limit our interest rate exposure with respect to a
notional amount of $1.3 billion of variable-rate indebtedness. These interest-rate contracts reset monthly
and require the counterparties to pay any excess interest owed on such amount in the event the
one-month LIBOR exceeds 2.75% for any monthly period prior to May 4, 2021. The contracts expired on
May 4, 2021. We did not report any gains or losses on these contracts for the years ended December 31,
2021 or 2020. For the year ended December 31, 2019, we reported a loss on these contracts, included in
other non-operating expenses on our consolidated statement of operations, of $4 million. No settlement
payments were received in 2021, 2020, or 2019. As of December 31, 2021, we do not have any
derivative contracts in place with respect to interest-rate exposure.
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.
102
Commodity Contracts
The following tables present the fair values (at gross and net) of our outstanding derivatives:
December 31, 2021 (Successor)
Classification
Assets:
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities:
Current - Fair value of derivative contracts . . . . . . . . .
Noncurrent - Fair value of derivative contracts . . . . . .
Gross
Amounts at
Fair Value
33 $
12
(297)
(143)
$
(395) $
December 31, 2020 (Successor)
Netting
Net Fair Value
(in millions)
(27) $
(11)
27
11
— $
6
1
(270)
(132)
(395)
Classification
Assets:
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities:
Current - Fair value of derivative contracts . . . . . . . . .
Noncurrent - Fair value of derivative contracts . . . . . .
$
Gross
Amounts at
Fair Value
Netting
Net Fair Value
(in millions)
21 $
63
(71)
(69)
(56) $
(21) $
(63)
21
63
— $
—
—
(50)
(6)
(56)
Interest-Rate Contracts
The fair value of our interest-rate derivatives contracts was not significant for all periods presented.
Counterparty Credit Risk
As of December 31, 2021, 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, 2021 was not significant. Losses associated with credit risk have been insignificant for
all years presented. At December 31, 2021, and 2020, we had insignificant collateral posted.
NOTE 8 INCOME TAXES
Net income (loss) before income taxes, for all periods presented, was generated from domestic
operations. For the year ended December 31, 2021, we released all of our valuation allowance of
$549 million, which consisted of $258 million in the U.S. federal jurisdiction and $291 million in the
state jurisdiction. A portion of the change in our valuation allowance was released against current year
income and the remaining $161 million in the U.S. federal jurisdiction and $235 million in the state
jurisdiction 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. We recorded an insignificant income tax provision for the year
ended December 31, 2019.
103
Total income tax (benefit) provision differs from the amounts computed by applying the U.S. federal
income tax rate to pre-tax income (loss) as follows:
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
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 . . . . . . . . . . . . . . . . .
Effective tax rate . . . . . . . .
21 %
(81)
(1)
—
(8)
2
(106)
—
(173)%
21 %
—
—
—
—
—
(20)
(1)
— %
21 %
—
(1)
—
—
—
(21)
1
— %
21 %
1
(27)
—
(7)
2
10
1
1 %
The tax effects of temporary differences resulting in deferred income tax assets and liabilities at
December 31, 2021 and 2020 were as follows:
(in millions)
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 . . . . . . . . . . . . . . . . . . . .
Successor
2021
2020
Deferred
Tax
Assets
$
$
122
18
152
88
177
—
59
616
—
616
Deferred
Tax
Liabilities
$ (151)
—
—
—
—
(49)
(20)
(220)
—
$ (220)
Deferred
Tax
Assets
Deferred Tax
Liabilities
$
$
209
43
178
12
180
—
60
682
(549)
133
$
$
(113)
—
—
—
—
—
(20)
(133)
—
(133)
Management assesses the realizability of 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 may be generated to permit realization of existing deferred tax assets. For the assessment period
ended December 31, 2021, management concluded that it was more-likely-than-not that all of our
existing deferred tax assets would be realized. This determination was based, in part, on our three-year
cumulative income position, the profitability of our business in recent periods and our projections of future
taxable income at current commodity prices and our current cost structure. We also considered our ability
to generate future taxable income in a lower commodity price environment as a potential source of
negative evidence. Based on our assessment, we determined there is sufficient positive evidence to
conclude that it is more-likely-than-not that our deferred tax assets of $396 million at December 31, 2021
are realizable and we released our remaining valuation allowance in the fourth quarter of 2021.
Realization of our deferred tax assets is subjective and remains dependent on our ability to generate
sufficient taxable income in future periods. 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.
104
Carryforwards
As of December 31, 2021, we had U.S. federal net operating loss carryforwards of $84 million,
which begin to expire in 2037, and $20 million of tax credits, which begin to expire in 2041. Our
carryforward for business interest expense of $844 million does not expire.
As of December 31, 2021, we had California net operating loss carryforwards of approximately
$2,431 million, which begin to expire in 2026, and $20 million of tax credit carryforwards, which begin
to expire in 2041.
Our ability to utilize 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 $17 million U.S. federal net operating loss
carryforwards and $1,905 million 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 in any Successor period. The following is
a reconciliation of unrecognized tax benefits in our Predecessor periods:
(in millions)
Predecessor
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
Unrecognized tax benefits – beginning balance . . . . . . . . . . .
Gross (decreases) increases – tax positions in prior year . . .
Gross increases – tax positions in current year . . . . . . . . . . .
Unrecognized tax benefits – ending balance . . . . . . . . . . . . .
$
$
101
(101)
—
—
$
$
25
44
32
101
In 2020, we released our liabilities related to 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 at least on a more-likely-than-not basis and accordingly we reversed our liability
for uncertain tax positions.
Other
We remain subject to audit by the Internal Revenue Service for calendar years 2018 through 2020
as well as 2017 through 2020 by the state of California.
NOTE 9 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.
105
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
Predecessor
Year ended
December 31,
2021
November 1,
2020 -
December 31,
2020
January 1,
2020 -
October 31,
2020
Year ended
December 31,
2019
(in millions)
General and administrative
expenses . . . . . . . . . . . . . . . . . . . . . . $
Operating costs . . . . . . . . . . . . . . . .
Total stock-based compensation
expense . . . . . . . . . . . . . . . . . . . . . $
17
2
19
$
$
— $
—
— $
2
1
3
$
$
25
7
32
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 awards during the Predecessor period of 2020 and $25 million during the year
ended December 31, 2019. We did not recognize any income tax provision or benefit related to our
stock-based compensation expense in 2021, 2020 or 2019.
Successor Stock Based Compensation Plan
Management Incentive Plan
Restricted Stock Units
Executives and non-employee directors were granted RSUs during 2021 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.
The following table sets forth RSU activity for the year ended December 31, 2021:
Weighted-
Average Grant-
Date Fair Value
Number of Units
(in thousands)
Unvested at December 31, 2020 (Successor) . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled or Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unvested at December 31, 2021 (Successor) . . . . . . . . . . . . . . .
106
1,216
— $
$
(18) $
(68) $
$
1,130
—
25.23
24.50
24.50
25.28
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, 2021, the unrecognized compensation expense for our unvested RSUs was
approximately $20 million and is expected to be recognized over a weighted-average remaining
service period of approximately two years.
Performance Stock Units
Executives were granted PSUs during 2021. PSUs 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. Earned PSUs generally vest on the
third anniversary of the grant date and are settled in shares of our common stock at that time.
The following table sets forth PSU activity for the year ended December 31, 2021:
Unvested at December 31, 2020 (Successor) . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled or Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unvested at December 31, 2021 (Successor) . . . . . . . . . . . .
Weighted-
Average Grant-
Date Fair Value
Number of Units
(in thousands)
— $
997
$
(53) $
944
$
—
20.09
19.31
20.14
The range of assumptions used in the Monte Carlo simulation model for the PSUs granted during
2021 were as follows:
Expected volatility(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-free interest rate(b)
Dividend yield(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forecast period (in years) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Successor
2021
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) The Monte Carlo model used for valuation included a dividend adjusted stock price and assumed reinvestment of dividends
during the performance period.
Compensation expense is recognized on a straight-line basis over the requisite service periods
adjusted for actual forfeitures, if any.
As of December 31, 2021, the unrecognized compensation expense for our unvested PSUs was
approximately $14 million and is expected to be recognized over a weighted-average remaining
service period of approximately two years.
107
Long-Term Cash Incentive Awards
On June 30, 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 Monte Carlo simulation model for the performance cash awards as of
December 31, 2021 were as follows:
Expected volatility(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-free interest rate(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forecast period (in years) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Successor
2021
60%
0.85%
— %
2.5
(a) Expected volatility was calculated using the historic volatility of our stock, excluding our first two trading months, and the
historic volatility of a peer group.
(b) Based on the U.S. Treasury yield for the 2.5 year remaining term.
(c) The Monte Carlo model used for valuation included a dividend adjusted stock price and assumed reinvestment of dividends
during the performance period.
As of December 31, 2021, the unrecognized compensation expense for all of our unvested cash-
settled awards was $11 million and is expected to be recognized over a weighted-average remaining
service period of approximately 2.5 years. The value of awards forfeited during the year ended
December 31, 2021 was approximately $1 million.
Predecessor Stock-Based Compensation Plan
As a result of our bankruptcy, 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. As of December 31, 2019, 4,714,316 shares were
issued or reserved under the Amended LTIP and 2,560,684 shares were available for future issuance of
awards. 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.
108
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 and the year ended December 31, 2019, the weighted-average fair value
of each stock-settled RSU granted was $6.20 and $21.71, respectively. 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.
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 and the year ended December 31, 2019, the weighted-average fair
value of each stock-settled PSU granted was $6.20 and $21.71, respectively. 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 and the year ended December 31, 2019, the
weighted-average fair value of each option granted was $6.82 and $23.88, respectively. All outstanding
stock options were cancelled for no consideration as a result of our emergence from bankruptcy.
109
NOTE 10 EQUITY
On the Effective Date, all of our Predecessor common and preferred stock, including contracts on our
equity were cancelled pursuant to the Plan and 83,319,660 shares of new common stock were issued. See
Note 14 Chapter 11 Proceedings for further information.
The following is a summary of changes in our shares outstanding during the year ended December 31,
2021 (Successor):
Balance, December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares issued for warrant exercises . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares issued under stock-based compensation arrangements . . . . . . . . . . . .
Shares repurchased . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common Stock
(in thousands)
83,319,660
51,377
18,173
(4,089,988)
79,299,222
Share Repurchase Program
During 2021, our Board of Directors authorized a Share Repurchase Program for up to $250 million of
our common stock through June 30, 2022. In February 2022, our Share Repurchase Program was
increased by $100 million to $350 million in aggregate and we extended the term of the program until
December 31, 2022. See Note 16 Subsequent Events for more information on this increase. 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.
As of December 31, 2021, we repurchased 4,089,988 shares of our common stock, at an average price
of $36.08 per share, through either open market purchases or our Rule 10b5-1 plan for $148 million. Shares
repurchased were held as treasury stock as of December 31, 2021.
Dividends
On November 11, 2021, our Board of Directors declared a quarterly cash dividend of $0.17 per share of
common stock. The dividend was payable to shareholders of record at the close of business on
December 1, 2021 and was paid on December 16, 2021. The dividend paid in the fourth quarter of 2021
was made pursuant to a cash dividend policy approved by the Board of Directors, which anticipates a total
annual dividend of $0.68, payable in quarterly increments of $0.17 per share of common stock.
The actual declaration of future cash dividends, and the establishment of record and payment dates, is
subject to final determination by our Board of Directors each quarter after reviewing our financial
performance and position. See Note 16 Subsequent Events for more information on future cash dividends.
Noncontrolling Interests
BSP JV
Our development joint venture with Benefit Street Partners (BSP JV) contemplated that BSP would
contribute 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.
110
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 14 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.
During 2021, we had issued 51,377 shares of common stock and received approximately $2 million
in cash related to warrant exercises. As of December 31, 2021, we had outstanding warrants
exercisable into 4,296,005 share of Successor 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. During the year ended December 31, 2021 we
recognized a benefit of $65 million related to a change in our postretirement benefit plan design. See
Note 12 Pension and Postretirement Benefit Plans for additional information on this plan amendment.
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 15 Fresh Start Accounting for additional information.
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 shares were issued under the plan after
March 31, 2020.
NOTE 11 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 9 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.
111
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, 2021.
The following table presents the calculation of basic and diluted EPS.
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
(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)
. . . . . . . . . . . . . . . . . .
Net (loss) income available to
common stockholders . . . . . . . . $
Denominator for Basic EPS
Weighted-average common
shares . . . . . . . . . . . . . . . . . . . .
Potential dilutive common shares:
Restricted Stock Units . . . . .
Performance Stock Units . . .
Denominator for Diluted
Earnings per Share
Weighted-average shares -
diluted . . . . . . . . . . . . . . . . . . . .
EPS
625
$
(125)
$
1,996 $
(13)
612
—
—
2
(123)
—
—
(107)
1,889
(22)
138
99
(127)
(28)
—
—
612
$
(123)
$
2,005 $
(28)
82.0
0.5
0.5
83.3
49.4
49.0
—
—
0.2
—
—
—
83.0
83.3
49.6
49.0
Basic . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . $
$
$
(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 14 Chapter 11 Proceedings.
40.59 $
40.42 $
(1.48)
(1.48)
7.46
7.37
(0.57)
(0.57)
$
$
112
The following table presents potentially dilutive weighted-average common shares which were
excluded from the denominator for diluted earnings per share:
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020
- December 31,
2020
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
(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
—
—
—
—
4.4
—
1.3
0.2
0.8
1.7
4.0
—
0.6
0.6
0.5
1.4
3.1
NOTE 12 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, 2021 and 2020, we recognized $30 million
and $35 million in other long-term liabilities for these supplemental plans, respectively.
We expensed $19 million in 2021, $4 million in the Successor period of 2020, $28 million in the
Predecessor period of 2020 and $36 million in 2019 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 2021, 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.
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 to the plan, 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.
113
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, as of December 31,
2021 and 2020 (in millions):
Amounts recognized on the balance
sheet
Accrued liabilities . . . . . . . . . . . . .
Other long-term liabilities . . . . . . .
Amounts recognized in
accumulated other comprehensive
income (loss)
. . . . . . . . . . . . . . . . . .
$
$
$
Successor
2021
2020
Pension
Postretirement
Pension
Postretirement
— $
(15)
(15)
$
(4)
(44)
(48)
$
$
— $
(15)
(15) $
(4)
(125)
(129)
(2)
$
74 $
(1) $
(7)
114
The following table shows the funding status of our pension and post-retirement benefit plans along
with a reconciliation of our benefit obligations and fair value of plan asset as of December 31, 2021 and
2020 (in millions):
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
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 loss . . . . . . . . . . . . . . . . . . . . . .
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 . . .
Net benefit liability (unfunded status) . . . .
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 . . . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . .
Plan amendment . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
47
$
1
1
2
(7)
44
32
2
2
(7)
29
(15)
$
$
$
$
46
—
—
3
(2)
47
26
2
6
(2)
32
(15)
$
$
$
$
$
129
$
122
$
4
3
(17)
(5)
(65)
1
—
7
(1)
—
Benefit obligation—end of year . . . . . . . . .
$
49
$
129
$
Changes in plan assets
Fair value of plan assets—beginning of
year . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . .
Benefits paid . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of plan assets—end of year . . .
Net benefit liability (unfunded status) . . . .
$
$
$
— $
6
(5)
1
(48)
$
$
—
1
(1)
—
(129)
$
$
$
115
45
1
1
1
(2)
46
27
1
—
(2)
26
(20)
116
4
3
2
(3)
—
122
—
3
(3)
—
(122)
Our accumulated benefit obligation for our defined benefit pension plans exceeded the fair value of our
plan assets as shown in the table below for the years ended December 31:
Successor
2021
2020
(in millions)
Projected benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accumulated benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Fair value of plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
44 $
39 $
29 $
47
43
32
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 expenses 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, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
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 . . . . . . . . . . .
Cost of special
termination benefits . . .
Amortization of prior
service cost credit
. . . .
Settlement costs . . . . . .
Net periodic benefit
costs . . . . . . . . . . . . . . . $
1
$
1
1
(1)
—
—
4
3
—
(1)
—
$
—
$
—
—
—
—
—
$
—
—
—
—
1
$
1
$
$
$
$
1
1
(1)
1
1
3
4
3
—
—
1
1
2
(2)
1
9
11
4
4
6
—
—
14
6
$
116
$
8
$
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 before tax (in millions):
Successor
Predecessor
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
Pension
Amounts recognized
in other
comprehensive
income (loss)
(in millions) . . . . . . . . .
Net actuarial loss . . . .
Settlement costs . . . . .
Amortization of net
actuarial gain/loss . . . .
Total recognized in other
comprehensive (loss)
income . . . . . . . . . . . . . .
Postretirement
Net actuarial gain
(loss) . . . . . . . . . . . . . .
Net prior service
credit . . . . . . . . . . . . . .
Settlement costs . . . . .
Amortization of prior
service cost credit . . . .
Total recognized in other
comprehensive income
(loss) . . . . . . . . . . . . . . . .
$
$
$
$
$
(1)
—
—
$
(1)
—
—
(1) $
1
1
(1)
$
(1)
$
1
$
17
65
—
(1)
$
(7)
$
(2) $
—
—
—
—
1
—
(6)
9
1
4
(19)
—
(2)
—
81
$
(7)
$
(1) $
(21)
Settlement costs related to our pension and postretirement plans 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:
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 . . . . .
Successor
Predecessor
Year ended
December 31,
2021
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
2.79%
4.00%
2.42%
6.25%
4.00%
117
2.42%
4.00%
2.70%
5.42%
4.00%
2.70%
4.00%
3.16%
5.42%
4.00%
October 1,
2021 -
December 31,
2021
Successor
January 1,
2021 -
September 30,
2021
November 1,
2020 -
December 31,
2020
Predecessor
January 1,
2020 -
October 31,
2020
Postretirement(a)
Benefit Obligation
Assumptions
Discount rate . . . . . . . . . . . .
2.75%
2.69%
2.92%
3.11%
Net Periodic Benefit Cost
Assumptions
Discount rate . . . . . . . . . . . .
2.69%
2.92%
3.11%
3.48%
(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 Aon AA Above Median yield curve in both 2021 and 2020. 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 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. Changes in mortality assumptions were reflected in the
valuations of our pension and postretirement benefit obligations as part of fresh start accounting upon
emergence from bankruptcy. These assumptions did not significantly change our pension benefit
obligations or postretirement benefit obligations in 2021 as compared to the prior year.
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 2.57% and 2.06% as of December 31, 2021 and 2020, 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, 2021, health care cost trend rates would decrease from 6.25% in 2021 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 2021 and 2020, the
target allocation of plan assets was 65% equity securities and 35% debt securities. 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 primarily invested in mutual funds.
118
The fair values of our pension plan assets by asset category are as follows:
Total pension plan assets . . . . . . . . . . . . . . . .
$
$
29
Asset Class
Cash equivalents . . . . . . . . . . . . . . . . . . . . . . .
Commingled funds
Fixed income . . . . . . . . . . . . . . . . . . . . . . . .
U.S. equity . . . . . . . . . . . . . . . . . . . . . . . . . .
International equity . . . . . . . . . . . . . . . . . . .
Mutual funds
Bond funds . . . . . . . . . . . . . . . . . . . . . . . . . .
Value funds . . . . . . . . . . . . . . . . . . . . . . . . .
Growth funds . . . . . . . . . . . . . . . . . . . . . . . .
Guaranteed deposit account . . . . . . . . . . . . . .
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 (Successor)
Level 1
Level 2
Level 3
Total
$
5
$
(in millions)
— $
— $
—
—
—
5
2
5
—
17
$
2
3
2
—
—
—
—
7
$
—
—
—
—
—
—
5
5
Fair Value Measurements at
December 31, 2020 (Successor)
Level 1
Level 2
Level 3
Total
$
6
$
(in millions)
— $
— $
—
—
—
5
2
6
—
19
$
2
3
2
—
—
—
—
7
$
—
—
—
—
—
—
6
6
$
32
5
2
3
2
5
2
5
5
6
2
3
2
5
2
6
6
In 2022, we expect to contribute $3 million to our pension and $5 million to our postretirement
benefit plans. 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,
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2027 to 2031 Payouts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
(in millions)
9
3
3
3
3
10
$
$
$
$
$
$
5
5
4
4
4
14
119
NOTE 13 REVENUE
Commodity Sales Contracts
We recognize revenue from the sale of our production when delivery has occurred and control
passes to the customer. Our contracts with customers are short term, typically less than a year. We
consider our performance obligations to be satisfied upon transfer of control of the commodity. In
certain instances, transportation and processing fees are incurred by us prior to control being
transferred to customers. We record these transportation costs as a component of operating expenses
on our consolidated statements of operations.
Our commodity sales contracts are 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. See Note 1 Nature of Business, Summary of Significant Accounting Policies and
Other for disaggregated revenue by commodity type.
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 purchases of natural gas 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 14 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.
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.
120
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.
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.
121
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 11 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.
The following table presents the changes in noncontrolling interests for our consolidated joint
ventures during the Predecessor periods ended December 31, 2019 and October 31, 2020, including
both our BSP JV and Ares JV.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, December 31, 2018 . . . . . . . . . . . . . . $
Net (loss) income attributable to noncontrolling
interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contributions from noncontrolling interest
holders, net
Distributions to noncontrolling interest holders
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 . . . . . . . . . . . . . . . . . . .
Balance, October 31, 2020 . . . . . . . . . . . . . . . . $
15
$
(7)
—
(8)
— $
3
(3)
—
—
—
— $
99
17
49
(72)
93
10
(34)
—
—
7
76
Equity Attributable to Noncontrolling
Interests
BSP JV
Ares JV
Mezzanine Equity -
Redeemable
Noncontrolling Interest
Ares JV
Total
$
$
$
$
$
756
117
—
(71)
802
94
(67)
(138)
(691)
—
— $
756
117
—
(71)
802
94
(67)
(138)
(691)
—
—
Total
(in millions)
114
$
10
49
(80)
93
13
(37)
—
—
7
76
$
$
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.
122
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 10 Equity and reserved 9.3 million shares for
future issuance under our management incentive plan described in Note 9 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;
• 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. Our new Board currently consists of nine directors.
123
NOTE 15 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.
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.
124
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.
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.
125
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 $543 million in other long-term liabilities.
Consolidated Balance Sheet
The following consolidated balance sheet, with accompanying explanatory notes, illustrates the
effects of the transactions contemplated by the Plan (Reorganization Adjustments) and fair value
adjustments resulting from the adoption of fresh start accounting (Fresh Start Adjustments) as of
October 31, 2020 (in millions):
Predecessor
Reorganization
Adjustments
Fresh Start
Adjustments
Successor
CURRENT ASSETS
Cash . . . . . . . . . . . . . . . . . . . . . . . .$
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)
95
—
—
$
—
—
—
—
—
203
149
61
102
515
(20,236)(12)
2,682
18,588 (12)
—
—
18 (3)
(1,648)
(4)(13)
2,682
91
3,288
TOTAL ASSETS . . . . . . . . . . . . . . . . .$
4,827 $
113
$
(1,652)
$
126
Predecessor
Reorganization
Adjustments
Fresh Start
Adjustments
Successor
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
733
215
233
1,181
—
725
4,516
691
—
—
5,149
—
—
—
—
(7,481)
(23)
(2,355)
69
Total equity . . . . . . . . . . . . . . . . . . .
(2,286)
TOTAL LIABILITIES AND EQUITY
$
4,827
$
Reorganization Adjustments
(733)
—
(16)
(749)
723
—
(4)
(5)
(6)
(4,516)
(7)
(691)
(8)
—
—
(5,149)
(9)
(10)
(10)
(10)
(11)
1
1,253
15
9,226
—
5,346
—
5,346
113
—
—
14 (14)
14
—
49 (15)
—
—
—
—
—
—
—
—
—
(1,745) (16)
23 (17)
(1,722)
7 (18)
(1,715)
(1,652)
$
$
(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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
—
215
231
446
723
774
—
—
—
—
—
—
1
1,253
15
—
—
1,269
76
1,345
3,288
225
446
200
(733)
(15)
(18)
(2)
(2)
(3)
(1)
97
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.
127
(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 14 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 $1 million for accrued interest and bank fees.
(6) Our exit financing at emergence included the following:
October 31, 2020
($ in millions)
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.
(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 . . . . . . . . . . . . . . . . . . . . . . . . . . . $
225
200
300
725
(2)
723
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
128
(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. See Note 5 Leases for more information on our leases.
(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.
(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.
129
NOTE 16 SUBSEQUENT EVENTS
Divestitures
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, for proceeds of $55 million (before transaction costs
and purchase price adjustments). 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.
In January 2022, we entered into an agreement to sell our commercial office building located in
Bakersfield, California for $15 million, subject to customary adjustments to be calculated at closing.
The sale is expected to close in the second quarter of 2022, contingent upon due diligence and a fit for
purpose analysis to be performed by buyer. We expect to lease back a portion of the building on a
short-term basis during a transition period. See Note 2 Property, Plant and Equipment for details of a
$25 million impairment charge we recognized in the third quarter of 2021 on this property.
Dividends
On February 23, 2022, our Board of Directors declared a cash dividend of $0.17 per share of
common stock. The dividend is payable to shareholders of record at the close of business on March 7,
2022 and is expected to be paid on March 16, 2022. This quarterly dividend is made pursuant to a
cash dividend policy approved by the Board of Directors in November 2021.
Share Repurchase Program
On February 22, 2022, our Board of Directors authorized an increase to our Share Repurchase
Program by $100 million to $350 million in aggregate and we extended the term of the program until
December 31, 2022.
Debt
In February 2022, we amended our Revolving Credit Facility to change the benchmark rate from
LIBOR to SOFR. As a result of this amendment, we can elect to borrow at either an adjusted SOFR
rate or an ABR rate, 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.
In February 2022, we obtained additional commitments under our Revolving Credit Facility from
new lenders increasing our aggregate commitment to $552 million from $492 million. After taking into
account these additional commitments, our available borrowing capacity under our Revolving Credit
Facility was increased by $60 million to $427 million from $367 million, after $125 million of outstanding
letters of credit.
130
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.
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . .
Revisions of previous estimates(c) . . . . . . . . . . . . . . . . . . . . . . .
Improved recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Extensions and discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . .
PROVED DEVELOPED RESERVES
December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2021(d)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROVED UNDEVELOPED RESERVES
December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil(a)
(MMBbl)
530
(34)
3
24
(11)
(29)
483
(164)
—
20
(1)
(25)
313
50
1
4
(3)
(22)
343
389
357
266
282
141
126
47
61
NGLs
(MMBbl)
Natural Gas
(Bcf)
60
(4)
—
2
—
(6)
52
(7)
—
1
—
(5)
41
5
—
—
(1)
(4)
41
47
45
39
38
13
7
2
3
734
(52)
—
41
6
(75)
654
(86)
—
24
(3)
(62)
527
108
—
6
(7)
(58)
576
565
543
460
510
169
111
67
66
Total(b)
(MMBoe)
712
(47)
3
33
(10)
(47)
644
(185)
—
25
(2)
(40)
442
73
1
5
(5)
(36)
480
530
493
382
405
182
151
60
75
(a) Includes proved reserves related to economic arrangements similar to PSCs of 111 MMBbl, 85 MMBbl, 125 MMBbl and
131 MMBbl at December 31, 2021, 2020, 2019 and 2018, 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.
(c) Commodity price changes affect the proved reserves we record. For example, higher prices generally increase the
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 22% of proved developed oil reserves, 8% of proved developed NGLs reserves, 16% of proved developed
natural gas reserves and, overall, 19% of total proved developed reserves at December 31, 2021 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.
131
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.
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 Part II, Item 8 – Financial Statements and Supplementary Data, 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.
2019
Revisions of previous estimates – We had negative price-related revisions of 20 MMBoe primarily
resulting from a lower commodity-price environment in 2019 compared to 2018.
We had 16 MMBoe of net positive performance-related revisions. We added 23 MMBoe primarily
related to better-than-expected performance in the San Joaquin and Los Angeles basins and 18
MMBoe that had been previously removed due to budgeting and development timing. These volumes
were brought back into our reserves based on re-evaluation of the applicable areas and management’s
plans. These positive revisions were partially offset by 25 MMBoe in negative performance-related
revisions primarily related to delayed responses in certain waterflood and steamflood projects.
132
We removed 43 MMBoe of proved undeveloped reserves, of which 19 MMBoe related to expired
projects not developed within the five-year window as the result of lower-than-anticipated product
prices. The remaining 24 MMBoe had not yet expired but were no longer prioritized in our development
plans in the current commodity price environment. The majority of these proved undeveloped reserves
that were downgraded at management’s discretion are located in the San Joaquin basin, meet
economic investment criteria at current prices and are anticipated to be developed in the future.
Extensions and discoveries – We added 33 MMBoe from extensions and discoveries, primarily
resulting from successful drilling in the San Joaquin and Los Angeles basins.
Improved recovery – We also added 3 MMBoe from improved recovery through IOR and EOR
methods, which were associated with the continued development of steamflood and waterflood
properties in the San Joaquin basin.
Divestitures – We had a reduction of 10 MMBoe in connection with the Lost Hills divestiture and the
Alpine JV entered into during the year. See Part II, Item 7 Management’s Discussion and Analysis,
Acquisitions and Divestitures for more on the Lost Hills divestiture and Part II, Item 7 Management’s
Discussion and Analysis, Joint Ventures for more on the Alpine JV.
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,
2021
(in millions)
December 31,
2020
(in millions)
Proved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depreciation, depletion and amortization . . . . . . . . . . . . .
2,626 $
1
2,627
(219)
Net capitalized costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,408 $
2,416
1
2,417
(31)
2,386
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
Year ended
December 31, November 1, 2020 -
December 31, 2020
2021
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
Property acquisition costs
Proved properties(a) . . . .
Unproved properties . . .
Exploration costs . . . . . . .
Development costs(b) . . . .
$
Costs incurred . . . . . . . .
$
(in millions)
53 $
—
7
210
270 $
—
—
1
7
8
$
$
(in millions)
— $
—
10
35
45 $
1
4
30
505
540
(a) Acquisition costs relates to our acquisition of MIRA’s working interests in certain wells in 2021.
(b) Development costs include a $19 million increase in ARO in 2021. There were no costs incurred for development costs
related to ARO in 2020. Development costs include a $80 million increase in ARO in 2019.
133
RESULTS OF OPERATIONS
Our oil and natural gas producing activities, which exclude items such as asset dispositions, corporate
overhead and interest, were as follows:
Successor
Predecessor
Year ended
December 31,
2021
(millions)
($/Boe)
November 1, 2020 -
December 31, 2020
January 1, 2020 -
October 31, 2020
Year ended
December 31,
2019
(millions)
($/Boe)
($/Boe)
235 $ 37.49 $ 1,196 $ 34.98 $ 2,377 $ 50.88
19.16
114
(millions)
(millions)
($/Boe)
14.95
18.19
511
895
705
19.39
Revenues(a) . . . . . . . . . . . . . . $ 1,729 $ 47.55 $
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
5.23
2.83
—
1.38
0.19
190
103
—
50
7
0.94
0.68
34
25
7
6
31
4
—
8
1
1.12
0.94
4.95
0.64
—
1.28
0.16
38
20
299
106
1,733
33
10
1.11
0.58
8.75
3.10
50.69
0.97
0.29
56
35
439
121
—
36
29
1.20
0.75
9.40
2.59
—
0.77
0.62
Pretax income
Income tax expense(d)
615
(144)
16.91
(3.96)
64
(18)
10.21
(2.87)
(1,554)
435
(45.46)
12.72
766
(205)
16.39
(4.39)
Results of operations
$
471 $ 12.95 $
46 $
7.34 $ (1,119) $ (32.74) $
561 $ 12.00
(a) Revenues include oil, natural gas and NGL sales, cash settlements on our commodity derivatives and other revenue
related to our oil and 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. Operating costs on a per Boe basis, excluding the effects of PSCs, were
$17.56 in 2021, $14.14 for the Successor period of 2020, $16.86 for the Predecessor period of 2020 and $17.70 for 2019.
(c) Other operating expenses primarily include transportation costs.
(d)
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 28%. The effective tax rate for 2021 includes the benefit of enhanced oil recovery credits.
134
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, 2021, 2020 and 2019, 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, 2021, 2020 and 2019. 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
Successor
December 31,
2021
December 31,
2020
Predecessor
December 31,
2019
(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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
28,031 $
15,532 $
34,134
(13,508)
(2,607)
(3,124)
8,792
(4,243)
(9,389)
(2,392)
(701)
3,050
(1,118)
(16,724)
(3,938)
(3,180)
10,292
(5,061)
Standardized measure of discounted future net cash flows . . . . . $
4,549 $
1,932 $
5,231
(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
(in millions)
Beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Successor
Predecessor
2021
2020
2019
1,932 $
5,231 $
7,275
(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)
(1,198)
(1,998)
556
(283)
433
(638)
890
518
(151)
(173)
(2,044)
End of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4,549 $
1,932 $
5,231
(a)
Includes revisions related to performance and price changes.
135
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)
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 . . . . . . . . . . . . . . $
2019 (Predecessor)
Deferred tax valuation
allowance . . . . . . . . . . . . . . $
Other asset valuation
allowance . . . . . . . . . . . . . . $
549 $
(526) $
(23) $
— $
— $
— $
— $
— $
—
—
511 $
35 $
3 $
— $
549
— $
— $
— $
— $
—
646 $
(571) $
436 $
22 $
(22) $
— $
— $
— $
511
—
625 $
16 $
5 $
— $
646
31 $
(9) $
— $
— $
22
136
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,
2021 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, 2021, 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, 2021, 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.
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, 2021 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.
137
ITEM 9B OTHER INFORMATION
None.
ITEM 9C DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
138
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 2022
Annual Meeting of Stockholders, which will be filed with the SEC within 120 days of the fiscal year ended
December 31, 2021 (2022 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
Mark A. (Mac)
McFarland
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.
Francisco J. Leon 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.
Shawn M. Kerns
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.
Michael L. Preston Executive Vice President, Chief Administrative Officer and General
Jay A. Bys
Chris D. Gould
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.
139
Age at
February 25, 2022
52
45
51
57
57
51
ITEM 11 EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference from our 2022 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 2022 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 2022 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 2022 Proxy Statement.
140
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
4.1
4.2
4.3
10.1
10.2
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).
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).
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.
141
Exhibit
Number
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
Exhibit Description
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).
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 Alter Domus Products
Corp., as Administrative Agent and Collateral Agent (filed as Exhibit 10.2 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.)
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.
California Resources Corporation Executive Severance Plan, dated as of March 20, 2020 (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed March 24, 2020 and incorporated
herein by reference).
Separation Agreement and General Release, dated August 18, 2020, by and between Marshall D.
Smith and California Resources Corporation (filed as Exhibit 10.1 to the Registrant’s Current Report
on Form 8-K filed August 18, 2020 and incorporated herein by reference).
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).
Interim Chief Executive Officer Agreement, dated December 21, 2020, by and between Mark A.
McFarland and California Resources Corporation (filed as Exhibit 10.42 to the Registrant’s Annual
Report on Form 10-K filed March 11, 2021 and incorporated herein by reference).
Separation Agreement and General Release, dated December 31, 2020, by and between Todd A.
Stevens and California Resources Corporation (filed as Exhibit 10.43 to the Registrant’s Annual
Report on Form 10-K filed March 11, 2021 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).
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).
142
Exhibit
Number
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
21*
23.1*
23.2*
23.3*
31.1*
31.2*
32.1*
99.1*
99.2*
101.INS*
101.SCH*
101.CAL*
101.LAB*
101.PRE*
Exhibit Description
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).
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.)
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, 2021.
Netherland, Sewell & Associates, Inc. Estimated Future Reserves Attributable to Certain Leasehold
and Royalty Interests as of December 31, 2021.
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.
143
Exhibit
Number
101.DEF*
104
Exhibit Description
Inline XBRL Taxonomy Extension Definition Linkbase Document.
Cover Page Interactive Data File (formatted in inline XBRL and contained in Exhibits 101).
* - Filed herewith.
144
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 25, 2022
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 25, 2022
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 25, 2022
Chief Financial Officer
Senior Vice President and Controller and February 25, 2022
Principal Accounting Officer
Chair of the Board
February 25, 2022
Director
February 25, 2022
Director
February 25, 2022
Director
February 25, 2022
Director
February 25, 2022
Director
February 25, 2022
Director
February 25, 2022
Director
February 25, 2022
145
Annual Meeting
Investor Relations
California Resources Corporation’s annual meeting
of stockholders will be held virtually at 11:00 a.m.
Pacific Time on May 4, 2022. 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
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 Administrative Officer
and General Counsel
This Annual Report is printed on Forest Stewardship
Council®-certified paper that contains wood from
well-managed forests and other responsible sources.
Board of Directors
Tiffany (TJ) Thom Cepak
Chair of the Board, Member of the Audit Committee, Member
of the Compensation Committee and Director since 2020
Andrew B. Bremner
Member of the Sustainability Committee
and Director since 2021
Douglas E. Brooks
Member of the Nominating and Governance Committee
and Director since 2020
James N. Chapman
Chair of the Compensation Committee,
Member of the Nominating and Governance Committee
and Director since 2020
Mark A. (Mac) McFarland
President, Chief Executive Officer and Director since 2020
Nicole Neeman Brady
Member of the Sustainability Committee,
Member of the Compensation Committee
and Director since 2021
Julio M. Quintana
Chair of the Nominating and Governance Committee,
Member of the Audit Committee and Director since 2020
William B. Roby
Chair of the Sustainability Committee,
Member of the Audit Committee, Member of the
Compensation Committee and Director since 2020
Alejandra (Ale) Veltmann
Chair of the Audit Committee and Director since 2021