California Resources Annual Report 2019

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FY2019 Annual Report · California Resources

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9
1
0
2

T ENERGY FOR CALIFORNIA
BY CALIFORNIANS

R
O
P
E
R
L
A
U
N
N
N
A

6.77

1.40

1.27

$
$
$
$

(0.57)

2019

2018

$
$
$
$
$

461
690
26
692

676
455
181
(282)

Financial Highlights

3,064
429
101
328
61

2,634
99
127
(28)
70

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

Total Assets
Long-Term Debt
Deferred Gain and Issuance Costs, Net
Equity

Net (Loss) Income Attributable to Common
Stock per Share – Basic and Diluted
Adjusted Net Income (Loss)
per Share – Diluted

Net Cash Provided by Operating Activities
Capital Investments
Payments from Debt, Net
Net (Used) Cash Provided by Financing Activities

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

HIGHLIGHTS

9
9FINANCIAL & OPERATIONAL
1
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)

Organic Reserve Replacement Ratio(a)
PV-10 of Proved Reserves(a) (in billions)

Operational Highlights

7,158
5,251
216
(247)

6,958
4,877
146
(296)

68.65
64.83
31.71
2.87

62.60
70.11
43.67
3.00

Closing Share Price

701
1,539
2,240

673
1,491
2,164

530
60
734
712

483
52
654
644

82
16
202
132

80
15
197
128

127%
9.4

111%
6.8

47.4
48.7

49.2
49.2

2019

2018

17.04

$
$
$
$

9.03

2017

2,006
(262)
4
(266)
(187)

(6.26)

(4.40)

248
371
18
73

6,207
5,306
287
(720)

42.5
42.9

2017

83
16
182
129

51.24
51.47
35.76
2.67

442
58
706
618

119%
4.5

703
1,550
2,253

19.44

$
$
$
$
$

$
$
$
$

(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,

Access to affordable, reliable energy has driven economic growth, environmental progress and an
increased standard of living at all socioeconomic levels across America and throughout the world. The
ingenuity of the exploration and production industry has provided the essential building blocks for this
progress, along with complementary technological innovations in energy efficiency and renewables. As
we move into the next decade, the demand for sustainably produced energy continues to grow.

California is a global leader in setting long-term climate goals. These ambitious goals must be
balanced with meeting the constant need for affordable and reliable energy to produce and deliver
massive quantities of food, water, medicine and goods upon which all Californians depend. Recent
events including power outages, international turmoil and the Coronavirus have exposed risks resulting
from the State’s excessive dependence on imported goods and energy. To create and sustain the
inclusive, equitable society to which Californians aspire, we need a diversified energy portfolio of
traditional and renewable energy to ensure affordability, reliability and resilience.

CRC serves an essential role in California by operating critical energy infrastructure and providing

locally produced energy for California by Californians under leading safety, labor, human rights and
environmental standards. Our in-state production ensures fundamental energy security for the Golden
State. Even as the rest of the United States becomes more energy independent, California imports a
continually growing share of its energy needs. Why does this matter? Because as California imports
more energy, the State outsources its environmental stewardship to other states and countries that do
not share our standards or values. At CRC, we believe being a leader in safe and environmentally
sustainable oil and gas operations drives value for our shareholders and provides future economic and
energy security for California’s diverse communities.

Energy for Californians by Californians

California, the fifth largest economy in the world, consumes significant amounts of energy. Based

on the most recent data from the U.S. Energy Information Administration, Californians consume 7.9
quadrillion BTUs per year to: (i) energize the homes and communities of 40 million residents, (ii) drive
344 billion miles a year, (iii) support more port traffic than any other state, (iv) fuel well over 600,000
airlines flights, and (v) power the vast agricultural, commercial, service and industrial sectors that
employ most working Californians. To support this level of energy consumption, California imports
approximately 70 percent of its crude oil, 90 percent of its natural gas and 32 percent of its electricity
from other states and countries. In 2018 alone, California imported about 370 million barrels of foreign
oil, equating to Californians sending approximately $25 billion per year to countries like Saudi Arabia,
Ecuador, and Iraq. Californians, who comprise 12% of the U.S. population, consume nearly twice their
share of net energy imports for the entire U.S. on a BTU basis, often at a higher cost from places that
do not share California’s strict environmental, safety, labor and human rights standards. However, the
Golden State has its own vast oil, natural gas and renewable resources. CRC is well positioned as
California’s largest oil and natural gas producer to help make Californians more self-sufficient and less
dependent on energy imports.

CRC’s values are California’s values. CRC operates under the strictest health, safety and
environmental (HSE) regulations in the U.S. and our California workforce proudly implements HSE
programs and long-term sustainability goals that surpass regulatory requirements. Health and safety
are always our primary focus. In 2019, CRC’s workforce achieved our best health and safety rating in
the history of our operations, with zero recordable employee injuries. Our overall health and safety
rating, which includes our contractors, is better than most office-based sectors. We continue to set the
standard for our industry and believe our track record, recognized by leading organizations including
the CDP (formerly the Carbon Disclosure Project), National Safety Council and Wildlife Habitat
Council, along with our Environmental, Social and Governance (ESG) policies are a strategic
differentiator.

Our 2030 Sustainability Goals, which are measured from a 2013 baseline, include increasing the

volume of recycled produced water by 30 percent, integrating at least 10 megawatts (MW) of
renewable power into our oil and gas operations, reducing our methane emissions by 50 percent, and
designing and permitting California’s first carbon capture and sequestration project at Elk Hills to
reduce our statewide CO2 emissions by 30 percent.

We have made significant progress toward these goals, which we believe are an essential
component to a balanced energy future for California. In the past year, we received financial support
from the Department of Energy to advance our carbon capture and sequestration project through a
FEED study. We have initiated solar projects to provide up to 44 MW of power to our fields and
facilities in the San Joaquin Basin and Long Beach, and we have surpassed our methane emissions
reduction target and look to further these reductions. We are halfway to our 2030 goal of increasing our
volume of recycled produced water, and we delivered over 5.3 billion gallons of much needed
reclaimed water to agricultural water districts in the San Joaquin Valley in 2019. Further, we continue
to build strong community relationships throughout California as we focus on supporting upward
economic mobility and reducing energy poverty.

CRC’s long-term strategy is focused on value creation and is directly tied to our ESG policies and
goals. We remain consistent and predictable with this strategy based on our Value Creation Index that
ensures we invest our capital in our highest value projects. Our large portfolio of low-decline assets
and extensive infrastructure provides optionality as we strive to deliver value to our shareholders and
support our community stakeholders. In 2019, we continued to live within our means and invested at a
level that delivered $269 million of free cash flow after internally funded capital. We produced 47 million
barrels of oil equivalent of local production, supplying critical energy to Californians.

Balance sheet strengthening remained a top priority in 2019. We reduced the face value of our
debt by $274 million through free cash flow generation and proceeds from a strategic asset sale which
targeted discounted debt repurchases, reducing both our principal and fixed interest payments.
Additionally, in early 2020, $100 million of our unsecured notes were repaid in full upon maturity,
further reducing our overall debt level to $4.9 billion, the lowest level since our spin. We remain
diligently focused on reducing our debt through an all-of-the-above approach in a disciplined and
thoughtful manner.

We are intently concentrating on the items within our control. Innovations by our operations and
engineering teams continue to drive significant cost reductions, improved efficiencies and sustained
HSE performance. We continuously review and refine our organizational design, which recently led us
to take steps to reduce our workforce. We are now operating our assets with a little over half the
number of employees we had prior to the spin. We believe these steps will reduce our annual cash
costs, while retaining our vigilance on health and safety, helping us to uphold margins for debt
reduction and enhance value creation.

We have a world-class portfolio of assets, and we increased our unproved reserves in 2019. Our

development joint ventures allow us to de-risk resources in our portfolio, accelerate production and
provide additional flexibility to remain disciplined in our capital allocation. In 2019, we entered into our
largest development joint venture to date with Alpine Energy Capital, LLC, which provides for up to
$500 million to invest in our assets, with $320 million already committed to our flagship Elk Hills field.

We are seeing a change in investor sentiment towards underlying asset diversification with longer
resource duration and the ability to sustain free cash flow generation. This has been CRC’s trademark
since the spin. We have consistently increased our resource base and lived within cash flows. Our
oil-weighted production allows us to further benefit from California’s premium Brent-based pricing.
These factors, along with continued balance sheet strengthening, further support the value of our
world-class assets for our shareholders.

In 2020, our dedicated and innovative workforce is committed to delivering safe, affordable and

reliable energy for California by Californians. We will advance our direct engagement with key
stakeholders in our communities to drive a sustainable energy future for working families. CRC will
remain focused on strengthening the balance sheet. Our dynamic capital allocation and operational
excellence help us capture the full value of our world-class portfolio. CRC maintains optionality to
monetize assets, and we continue to use free cash flow to reduce our overall level of debt. Our value-
driven capital allocation process targets the highest value projects in our portfolio, while our operational
teams remain dynamic in addressing commodity price volatility. Across CRC, we continue to drive
efficiencies as we strive to maintain operational excellence, improve margins and generate free cash
flow. CRC’s strategy positions us for long-term shareholder value creation and represents a strong
investment opportunity.

Regards,

Todd A. Stevens
President and Chief Executive Officer
California Resources Corporation

Note: See the Investor Relations page at www.crc.com for explanations of how CRC calculates and uses the non–GAAP
measure of free cash flow and a reconciliation to its nearest GAAP measure, and for other important information about possible
and probable reserves and other hydrocarbon resource quantities. The Value Creation Index (VCI) metric is calculated by
dividing the net present value of the project’s expected pre-tax cash flow over its life by the net present value of the related
investments, each using a 10% discount rate.

[THIS PAGE INTENTIONALLY LEFT BLANK]

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, 2019

‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from

Commission File Number 001-36478

California Resources Corporation
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

27200 Tourney Road, Suite 200
Santa Clarita, California
(Address of principal executive offices)

46-5670947
(I.R.S. Employer
Identification No.)

91355
(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

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

Yes ‘ No Í

Act.

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

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

Yes ‘ No Í

the Act.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to
Yes Í No ‘
file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a

smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,”
“smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer
Smaller Reporting Company ‘ Emerging Growth Company

Í Accelerated Filer

‘
‘

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 is a shell company (as defined in Rule 12b-2 of the Act). Yes ‘ No Í

The aggregate market value of the voting common stock held by nonaffiliates of the registrant was approximately

$945 million, computed by reference to the closing price on the New York Stock Exchange composite tape of $19.68 per share
of Common Stock on June 30, 2019. Shares of Common Stock held by each executive officer and director have been excluded
from this computation in that such persons may be deemed to be affiliates. This determination of potential affiliate status is not
a conclusive determination for other purposes.

At January 31, 2020, there were 49,175,843 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be filed with the Securities and Exchange Commission in

connection with the registrant’s 2020 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Strengths . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mineral Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production, Price and Cost History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recovery Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Productive Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marketing Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SELECTED FINANCIAL DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basis of Presentation and Certain Factors Affecting Comparability . . . . . . . . .
Production and Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Joint Ventures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Seasonality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Operations Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Off-Balance-Sheet Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contractual Obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lawsuits, Claims, Commitments and Contingencies . . . . . . . . . . . . . . . . . . . . .
Critical Accounting Policies and Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Significant Accounting and Disclosure Changes . . . . . . . . . . . . . . . . . . . . . . . .
FORWARD-LOOKING STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . .

Page

4
4
4
5
7
9
10
12
19
21
23
24
24
25
28
29
29
37
38
51
51
51

52
55

55
56
56
57
60
61
61
63
64
70
74
78
78
78
79
79
80
81

Item 8

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . . . .
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Quarterly Financial Data (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental Oil and Gas Information (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . .

Item 9

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9A CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Part III

Item 10 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE . . . . . . . .
EXECUTIVE OFFICERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11 EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND

Page

84
84
88
89
90
91
92
93
138
139

145
145
146

147
147
148

MANAGEMENT AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . . .

148

Item 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR

INDEPENDENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 14 PRINCIPAL ACCOUNTANT FEES AND SERVICES . . . . . . . . . . . . . . . . . . . . . . . . . .

148
148

Part IV

Item 15 EXHIBITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

149

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 the state of California. We are the largest oil and natural gas producer in
California on a gross operated basis, with average net production of 128 thousand barrels of oil
equivalent per day (MBoe/d) in 2019. We have the largest privately held mineral acreage position in
the state, consisting of approximately 2.2 million net mineral acres spanning four of California’s major
oil and natural gas basins. Our proved reserves totaled an estimated 644 million barrels of oil
equivalent (MMBoe) at December 31, 2019.

We have a diversified portfolio of oil and natural gas locations and extensive drilling inventory that
are economically viable in a variety of operating and commodity-price conditions, including many that
are high-value projects throughout the commodity-price cycle. Our acreage position contains numerous
development and growth opportunities due to its varied geologic characteristics and thousands of feet
of multiple stacked-pay reservoirs in many locations. Our returns are enhanced relative to our peers
because we do not make any significant royalty or other lease payments on over 60% of our mineral
acreage, which is held by us in fee.

Our large portfolio of low-risk and low-decline conventional opportunities comprises approximately
73% of our proved reserves across the four oil and natural gas basins in which we operate. We are in
various phases of developing many of our conventional assets, which we expect to continue to develop
by using internally generated cash flow and capital raised through joint ventures.

We also own or control a network of strategically placed infrastructure that integrates with and
complements our operations, to maximize the value generated from our production. This infrastructure
includes natural gas processing plants, power plants, oil and natural gas gathering systems and other
related assets.

Our 3D seismic library covers approximately 4,950 square miles, representing approximately 90%
of the 3D seismic data available in California. We have developed unique, proprietary stratigraphic and
structural models of the subsurface geology and hydrocarbon potential in each of the four basins in
which we operate. We have successfully implemented various exploration, drilling, completion and
enhanced recovery technologies to increase recoveries, growth and value from our portfolio.

We were formed in April 2014 and are currently listed on the New York Stock Exchange. All
references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation
and its subsidiaries.

Business Strategy

We provide ample, affordable and reliable energy, in a safe and responsible manner, to support
and enhance the quality of life for Californians and the local communities where 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. Our long-term, value-driven growth strategy is focused on five
key priorities:

(cid:129)

Utilize our technical knowledge and experience to focus on production, delineate expansion
areas and optimize hydrocarbon recovery;

(cid:129)

Use our Value Creation Index (VCI) metric to ensure consistent, disciplined and effective
capital allocation;
Optimize operational performance through streamlined processes, application of technology
and entrepreneurial thinking to capture efficiencies, improve results and reduce costs;
Strengthen our balance sheet by reducing absolute levels of our debt and fixed charges,
investing to grow cash flow, simplifying our capital structure and pursuing value-accretive
transactions, including joint ventures; and

(cid:129) Maintain a proactive and collaborative approach to safety, environmental protection and

community outreach while helping California meet its energy and water needs sustainably
with local resources.

Strengths

The following strengths position us to successfully execute our business strategy:

(cid:129)

Operational control over our diverse asset base provides us with flexibility.

We have ownership or operational control over substantially all our assets. This allows us to
adapt our investments by selecting drilling locations, the timing of development and the drilling
and completion techniques used in a manner designed to generate free cash flow over a wide
range of commodity prices.

We have a large and diverse mineral acreage position that permits a variety of recovery
mechanisms and product types. The majority of our interests are in producing properties
located in reservoirs that we believe have long-lived production profiles with repeatable
development opportunities. The low base decline of our conventional assets allows us to limit
production declines with minimal investment.

We are designing a carbon dioxide (CO2) capture and sequestration (CCS) project at our Elk
Hills field. The U.S. Department of Energy has awarded financial support for a Front End
Engineering and Design (FEED) study to capture CO2 produced at our Elk Hills power plant,
which we are conducting in partnership with the Electric Power Research Institute. Further,
with our significant land holdings in California, we have undertaken initiatives to unlock
additional value from our surface acreage, including pursuing renewable energy opportunities,
agricultural activities and other commercial uses.

(cid:129)

Largest mineral acreage position in a world-class oil and natural gas province.

Our operations are located exclusively in California, which is one of the most prolific oil and
natural gas producing regions in the world and is currently the seventh largest oil producing
state in the nation. According to information through 2018 from the California Department of
Conservation Geologic Energy Management Division (CalGEM), formerly the Division of Oil,
Gas, and Geothermal Resources, cumulative California production from all four basins in
which we operate is 36 billion barrels of oil equivalent (BBoe), including approximately 20
BBoe in the San Joaquin basin, 11 BBoe in the Los Angeles basin, 3 BBoe in the Ventura
basin and 2 BBoe in the Sacramento basin. Additionally, Kern County, located in the San
Joaquin basin, is the fifth largest oil producing county in the lower 48 states. California is also
the nation’s largest state economy, and the world’s fifth largest, with energy demands that
significantly exceed local supply. Our large mineral acreage position and diverse development
portfolio enable us to pursue the appropriate production strategy for the relevant commodity-
price environment without the need to acquire new mineral acreage. We also seek to quickly
deploy the knowledge we gain in our existing operations, together with our seismic data, to
other areas within our portfolio.

(cid:129)

Extensive drilling and workover portfolio focused on lower-risk conventional oil
opportunities.

Our drilling inventory at December 31, 2019 consisted of approximately 32,280 gross (24,350
net) identified well locations, of which approximately 95% target oil. In addition, we continue to
maintain our available workover projects that typically deliver high returns. Our inventory of
predominantly lower-risk conventional development opportunities has increased more than
our unconventional opportunities. In a sustained favorable oil and natural gas price
environment, we believe we can achieve further long-term production growth through the
development of unconventional reservoirs. In addition, our large conventional and
unconventional portfolio can provide attractive joint venture opportunities.

(cid:129)

Proven operational management and technical teams with extensive experience
operating in California.

The members of our operational management and technical teams have an average of over
26 years of experience in the oil and natural gas industry, with an average of over 17 years
focused on our California oil and natural gas operations through different price cycles. Our
teams have a proven track record of applying modern technologies and operating methods to
develop our assets and improve their operating efficiencies.

Operations

The following table highlights key information about our operations in the four California oil and

natural gas basins in which we operate as of and for the year ended December 31, 2019:

Mineral Acreage:
Net mineral acreage (thousands)
Average net mineral acreage held in fee (%)

Number of fields
Average net revenue interest (%)(a)
Average drilling rigs(b)
Net wells drilled and completed

Proved reserves:
Oil (MMBbl)
NGLs (MMBbl)
Natural gas (Bcf)

Total (MMBoe)

San
Joaquin
Basin

Los
Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total
Operations

1,390

67%

48
92%
7
117.8

280
49
525

417

30
46%

8
72%
1
25.2

168
—
13

170

232

79%

27
84%
—
2.0

35
3
26

512

37%

53
76%
—
2.4

—
—
90

2,164

61%

136

86%
8
147.4

483
52
654

644

Oil percentage of proved reserves

67%

99%

83%

—%

75%

Production:
Total production (MMBoe)
Average daily production (MBoe/d)
Oil percentage of production
Reserves to production ratio (years)(c)

34
94
55%

12.3

9
24
100%
18.9

2
5
80%

21.0

2
5
—%
7.5

47
128

63%

13.7

Note: MMBbl refers to millions of barrels; Bcf refers to billions of cubic feet; MMBoe refers to millions of barrels of oil equivalent;

and MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Natural gas volumes have been converted to
Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil
equivalence does not necessarily result in price equivalence.

(a) The average net revenue interest represents our interest in production after considering royalties and similar burdens and

third-party working interests.
Includes one internally funded rig and seven JV rigs.

(b)
(c) Calculated as total proved reserves as of December 31, 2019 divided by total production for the year ended December 31,

2019.

San Joaquin Basin

The San Joaquin basin contains some of the largest oil fields in the United States based on
cumulative production and proved reserves. Commercial petroleum development in the basin began in
the 1800s. The basin contains multiple stacked formations throughout its areal extent, and we believe
that the San Joaquin basin provides appealing opportunities for field re-development of existing wells,
as well as new discoveries and unconventional play potential. The complex geology in the San Joaquin
basin has allowed continuing discoveries of stratigraphic and structural traps. Approximately 75% of
California’s total daily oil production for 2018 was produced in the San Joaquin basin, according to
CalGEM.

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

producing asset and one of the largest fields in the continental U.S. based on proved reserves.

At Elk Hills we also 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, the Elk
Hills power plant generates sufficient electricity to operate the field, and sells excess power to the grid
and to a utility. Our operations at Elk Hills also include an advanced central control facility and remote
automation control on over 95% of our producing wells.

We believe our extensive 3D seismic library, which covers over 850,000 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. We have a large ownership interest in several
of the largest existing oil fields in the San Joaquin basin, including Elk Hills, Buena Vista and Kettleman
North Dome. We have also been successfully developing steamfloods in our Kern Front operations.

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 with 68 fields in an area of about
0.3 million acres. 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 include the Wilmington and
Huntington Beach fields, where we have significant operations.

The Wilmington field has been one of the largest fields in the continental U.S. based on proved

reserves. Most of our Wilmington production is subject to a set of contracts similar to production-
sharing contracts (PSCs) under which we recover the capital and operating costs we incur on behalf of
the state and the city of Long Beach and receive our share of profits.

Ventura Basin

The Ventura Basin is the oldest operating oil basin in California extending from northern Los
Angeles County to the coastal area of Ventura. The earliest discoveries were mines dug into hillsides
to mine active oil seeps. The first commercial oil well started in 1866. The entire sedimentary section is
productive at various locations, and most reservoirs are sandstones with favorable porosity and
permeability. As of December 31, 2019, we operated more than 20 oil fields in this historic and prolific
basin. The basin contains multiple stacked formations and provides an appealing inventory of existing
field re-development opportunities, as well as new exploration potential. We continue to explore over
10,000 feet of proven stacked oil reservoirs throughout the basin.

Sacramento Basin

The Sacramento basin is a deep, thick sequence of sedimentary deposits 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.

Mineral Acreage

The following table sets forth certain information regarding the total developed and undeveloped
mineral acreage in which we held an interest as of December 31, 2019. Approximately 60% of our total
net mineral interest position is held in fee, approximately 17% is held by production and the remainder
is subject to term leases.

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin
(in thousands)

Sacramento
Basin

Total

Developed(a)
Gross(b)
Net(c)

Undeveloped(d)

Gross(b)
Net(c)

Total

426
349

1,275
1,041

21
16

17
14

63
61

204
171

266
247

348
265

Gross(b)
Net(c)
(a) Mineral acres spaced or assigned to productive wells.
(b) Total number of mineral acres in which interests are owned.
(c) Net mineral acreage includes acreage reduced to our fractional ownership interest and interests under PSC-type

1,701
1,390

614
512

267
232

38
30

776
673

1,844
1,491

2,620
2,164

contracts.

(d) 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.

Our oil and natural gas leases have primary terms ranging from one to ten years. Once production

commences, leases are extended on the producing acreage through the end of their producing life.

Work programs are designed to ensure that the exploration 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. The combined net acreage covered by leases expiring in the next three years represented
approximately 15% of our total net undeveloped acreage at December 31, 2019 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 we will
need to do so in the future.

Production, Price and Cost History

The following table sets forth information regarding our production, average realized and
benchmark prices and production costs per Boe for the years ended December 31, 2019, 2018 and
2017. 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
and Prices.

Year Ended December 31,
2018

2017

2019

Average daily production:
Oil (MBbl/d)
NGLs (MBbl/d)
Natural gas (MMcf/d)
Total daily production (MBoe/d)(a)(b)

Total production (MMBoe)(a)(b)

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)

80
15
197
128

82
16
202
132

83
16
182
129

$
$
$
$

$
$
$

68.65 $
64.83 $
31.71 $
2.87 $

62.60 $
70.11 $
43.67 $
3.00 $

51.24
51.47
35.76
2.67

64.18 $
57.03 $
2.67 $

71.53 $
64.77 $
2.97 $

54.82
50.95
3.09

Production costs per Boe(b):
18.64
Production costs
Production costs, excluding effects of PSC-type contracts(c)
17.48
Note: Bbl refers to barrels; MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MMBtu

19.16 $
17.70 $

18.88 $
17.47 $

$
$

refers to millions of British Thermal Units.

(a) Our April 2018 acquisition of the remaining working interest in the Elk Hills unit added approximately 10 MBoe/d and 8
MBoe/d in 2019 and 2018, respectively. 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 May 2019. PSC-type contracts had no impact on our
oil production in 2019 compared to 2018. Our PSC-type contracts negatively impacted our oil production in 2018 by over 1
MBoe/d compared to 2017.

(b) Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet

of natural gas (Mcf) to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(c) The reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full
field, and reported volumes, which are only our net share, inflating the per barrel production costs. These amounts
represent production costs after adjusting for the excess costs attributable to PSC-type contracts.

The following table sets forth information regarding production, realized prices and production

costs per Boe for our two largest fields, Elk Hills and Wilmington, for the years ended December 31,
2019, 2018 and 2017:

Average daily production:

Oil (MBbl/d)
NGLs (MBbl/d)
Natural gas (MMcf/d)
Total production (MBoe/d)
Average realized prices(a):

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

Production costs per Boe(b)
Production costs per Boe, excluding effects
of PSC-type contracts(c)

Elk Hills
2018

2019

2017

2019

Wilmington
2018

2017

22
12
103
51

22
12
108
52

19
13
95
48

20
—
1
20

21
—
1
21

23
—
1
23

$ 68.33 $ 73.98 $ 55.58 $ 61.99 $ 67.81 $ 49.87
—
$ 31.62 $ 43.58 $ 36.26 $
$
2.12
2.52 $
$ 12.55 $ 12.07 $ 11.76 $ 31.12 $ 29.81 $ 27.91

— $
1.71 $

— $
2.06 $

2.67 $

2.87 $

N/A

$ 21.69 $ 21.02 $ 21.59

(a) Excludes the effect of hedges.
(b) Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet

of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

(c) The reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full
field, and reported volumes, which are only our net share, inflating the per barrel production costs. These amounts
represent production costs after adjusting for the excess costs attributable to PSC-type contracts.

Oil, NGLs and natural gas are commodities, and the price we receive for our production is largely
a function of market supply and demand. Product prices are affected by a variety of factors, including
changes in domestic and global supply and demand; domestic and global inventory levels; political and
economic conditions; the actions of Organization of the Petroleum Exporting Countries (OPEC) and
other significant producers and governments; changes or disruptions in actual or anticipated
production, refining and processing; worldwide drilling and exploration activities; government energy
policies and regulations, including with respect to climate change; the effects of conservation; weather
conditions and other seasonal impacts; speculative trading in derivative contracts; currency exchange
rates; technological advances; transportation and storage capacity, bottlenecks and costs in producing
areas; the price, availability and acceptance of alternative energy sources; regional market conditions
and other matters affecting the supply and demand dynamics for these products, along with market
perceptions with respect to all of these factors. Given the volatile oil price environment, as well as our
leverage, we have a hedging program to help protect our cash flow, operating margin and capital
program, while maintaining adequate liquidity.

Our production costs include variable costs that fluctuate with production levels, and 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. Overall, we
believe approximately one-third of our operating costs are fixed over the life cycle of our fields. We
actively manage our fields to optimize production and minimize costs. When we see growth in a field,
we increase capacities and, similarly, when a field nears the end of its economic life, we manage the
costs while it remains economically viable to produce.

Our share of production and reserves from operations in the Wilmington field is subject to

contractual arrangements similar to PSC-type contracts that are in effect through the economic life of
the assets. Under such contracts we are obligated to fund all capital and production costs. We record a
share of production and reserves to recover a portion of such capital and production costs and an
additional share for profit. Our portion of the production represents volumes: (i) to recover our partners’
share of capital and production 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 production costs. However, our net economic benefit is greater when product prices
are higher. These PSC-type contracts represented 15% of our production for the year ended
December 31, 2019.

In addition, in line with industry practice for reporting PSC-type contracts, we report 100% of
operating costs under such contracts in production 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 PSC-type contracts. 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.

Reserves

Volatility in oil prices may materially affect the quantities of oil and natural gas reserves we can

economically produce over the longer term. At December 31, 2019, our total estimated proved
reserves were 644 million barrels of oil equivalent (MMBoe), a decrease of 68 MMBoe from 712
MMBoe at December 31, 2018. During 2019, proved crude oil reserves decreased by 47 million barrels
(MMBbl), proved NGL reserves decreased by 8 MMBbl and proved natural gas reserves decreased by
80 billion cubic feet or 13 MMBoe, in each case from December 31, 2018.

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).

Proved oil, NGLs and natural gas reserves were estimated 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. Oil, NGLs and natural gas prices used for this purpose
were based on spot prices, adjusted for price differentials to account for gravity, quality and
transportation costs. For our 2019 reserves estimates, the average benchmark Brent oil price was
$63.15 per barrel and the average NYMEX gas price was $2.58 per MMBtu. The average realized
prices used for our 2019 reserves were $63.50 per barrel for oil, $30.91 per barrel for NGLs and $2.88
per Mcf for natural gas.

The following table sets forth our net operating and non-operating interests in quantities of proved

developed and undeveloped reserves of oil (including condensate), natural gas liquids (NGLs) and
natural gas as of December 31, 2019. Estimated reserves include our economic interests under
arrangements similar to PSCs at our Wilmington field in Long Beach.

Proved developed reserves:

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

Total (MMBoe)(a)(b)

Proved undeveloped reserves:

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

Total (MMBoe)(b)

Total proved reserves:

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

Total (MMBoe)(b)

San Joaquin
Basin

212
43
444

329

68
6
81

280
49
525

417

As of December 31, 2019
Ventura
Basin

Los Angeles
Basin

Sacramento
Basin

121
—
10

123

47
—
3

168
—
13

170

24
2
19

11
1
7

35
3
26

—
—
70

—
—
20

—
—
90

Total

357
45
543

493

126
7
111

151

483
52
654

644

(a) As of December 31, 2019, approximately 24% of proved developed oil reserves, 11% of proved developed NGLs

reserves, 13% of proved developed natural gas reserves and, overall, 21% of total proved developed reserves are
non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full peak production
response has not yet occurred due to the nature of such projects.

(b) Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet

of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

Changes to Proved Reserves

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

2019 were as follows:

Balance at December 31, 2018

Revisions related to price
Revisions related to performance
Removal of PUDs
Extensions and discoveries
Improved recovery
Divestitures
Production

Balance at December 31, 2019

San Joaquin
Basin

Los Angeles
Basin(a)

478
(8)
4
(41)
25
3
(10)
(34)

417

175
(11)
11
(2)
6
—
—
(9)

170

Ventura
Basin
(in MMBoe)
48
(1)
(3)
—
—
—
—
(2)

Sacramento
Basin

Total

11
—
4
—
2
—
—
(2)

712
(20)
16
(43)
33
3
(10)
(47)

644

Note: Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet

(a)

of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
Includes proved reserves related to PSC-type contracts of 125 MMBoe and 131 MMBoe at December 31, 2019 and 2018,
respectively.

Price-related revisions – We had negative price-related revisions of 20 MMBoe primarily resulting

from a lower commodity-price environment in 2019 compared to 2018.

Performance-related revisions – 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.

Removal of PUDs – We removed 43 MMBoe of PUD 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 PUDs 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 Improved Oil

Recovery (IOR) and Enhanced Oil Recovery (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.

We achieved an organic reserve replacement ratio of 111% from our capital program of

$455 million, including 16 MMBoe of net positive performance-related revisions. For further information
on our organic reserve replacement ratio, see the PV-10, Standardized Measure and Reserve
Replacement Ratio section below.

Proved Undeveloped Reserves

The total changes to our PUDs during the year ended December 31, 2019 were as follows:

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total

Balance at December 31, 2018

Revisions related to price
Revisions related to performance
Removal of PUDs
Extensions and discoveries
Improved recovery
Divestitures
Transfers to proved developed reserves

Balance at December 31, 2019

123
(1)
8
(41)
18
2
(6)
(15)

(in MMBoe)
15
—
(2)
—
—
—
—
—

43
(5)
9
(2)
5
—
—
(3)

1
—
1
—
1
—
—
—

182
(6)
16
(43)
24
2
(6)
(18)

151

Note: Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet

of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

Price-related revisions – We had negative price-related revisions of 6 MMBoe primarily resulting

from a lower commodity-price environment in 2019 compared to 2018.

Performance-related revisions – We had 16 MMBoe of net positive performance-related revisions.
We added 21 MMBoe that were 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 5 MMBoe in negative
performance-related revisions primarily related to a waterflood in the Ventura basin.

Removal of PUDs – We removed a total of 43 MMBoe of PUD reserves in 2019, of which 19
MMBoe related to expired projects not developed within the five-year window as the result of lower-
than-anticipated oil prices. The remaining 24 MMBoe had not yet expired but were no longer prioritized
in our development plans at lower-than-anticipated prices. The majority of these PUDs 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 24 MMBoe of PUDs through extensions and discoveries,

primarily resulting from successful drilling efforts in the San Joaquin and Los Angeles basins.

Improved recovery – We added proved reserves of 2 MMBoe from improved recovery through IOR
and EOR methods. The improved recovery additions were associated with the continued development
of steamflood and waterflood properties in the San Joaquin basin. Approximately 77% of the PUD
additions from extensions and discoveries and improved recovery were crude oil.

Divestitures – We had a reduction of 6 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.

Transfers to proved developed reserves – We converted 18 MMBoe of PUDs to proved developed

reserves, the majority of which were in the San Joaquin and Los Angeles basins. As a result, we
converted approximately 10% of our beginning-of-year PUDs, after adjusting for volumes divested
during the year, to proved developed reserves during the year, investing approximately $248 million of
drilling and completion capital.

Our year-end development plans and associated PUDs are consistent with SEC guidelines for
development within five years. We believe we will have sufficient capital to develop all year-end 2019
PUDs within five years of their original booking date. Management’s capital commitment assumes an
average $65 Brent price for 2020, $72 for 2021 and approximately $75 thereafter. Prices that are
significantly below these levels for a prolonged period could require us to reduce expected capital
investment over the next five years, potentially impacting either the quantity or the development timing
of proved undeveloped reserves. For example, if the average future price remained at $65 Brent, our
volumes ultimately recovered from PUDs would be reduced by approximately 5% to 10% over the long
term.

PV-10, Standardized Measure and Reserve Replacement Ratio

As of December 31, 2019, our standardized measure of discounted future net cash flows

(Standardized Measure) was $5.2 billion and PV-10 was approximately $6.8 billion.

PV-10 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 production
costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC Prices.
PV-10 differs from Standardized Measure because Standardized Measure includes 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 proved reserves

Organic reserve replacement ratio(a)

As of December 31, 2019
(in millions)

5,231
1,618

6,849

111%

(a) The organic reserve replacement ratio is calculated for a specified period using the proved oil-equivalent additions from

extensions and discoveries, improved recovery and net performance-related revisions, divided by oil-equivalent
production. There is no guarantee that historical sources of reserves additions will continue as many factors are fully or
partially outside management’s control, including commodity prices, availability of capital and the underlying geology, all
of which affect reserves additions. Management uses this measure to gauge the results of its capital program. Other oil
and natural gas producers may use different methods to calculate replacement ratios, which may affect comparability.

Reserves Evaluation and Review Process

Our estimates of proved reserves and associated discounted future net cash flows as of
December 31, 2019 were made by our technical personnel, such as 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. 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. Operating and capital costs are forecast using the current cost environment (without
accounting for possible cost changes) applied to expectations of future operating and development
activities related to the proved reserves.

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, Reserves and Corporate Development has primary responsibility for
overseeing the preparation of our reserves estimates. She has over 15 years of experience as an
energy sector engineer including as a Senior Reservoir Engineer with Ryder Scott Company, L.P.
(Ryder Scott). She is a member of the Society of Petroleum Engineers (SPE) for which she served as
past chair of the U.S. Registration Committee. She holds a Master of Business Administration from the
Massachusetts Institute of Technology, a Master of Engineering in Petroleum Engineering from the
University of Houston and a Bachelor of Science from the University of Florida. She is also a registered
Professional Engineer in the state of Texas.

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 2019. 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. Ryder Scott audited 42% of our total
proved reserves, all of which were in Elk Hills. NSAI audited 38% of our total proved reserves, all from
fields excluding Elk Hills. Over 95% of our total 2019 proved reserves were audited by independent
auditors at some time during 2015 through 2019.

NSAI was retained by us in 2019 to audit proved reserves from our fields other than in Elk Hills
due to their extensive California experience. Additionally, NSAI already performs audits on behalf of
several of our partners. Engaging NSAI to audit the fields they are already familiar with provides
efficiencies and facilitates interactions with our partners.

Our independent reserve engineers examined the assumptions underlying our reserves estimates,
adequacy and quality of our work product, and estimates of future production rates, net revenues, and
the present value of such net revenues. 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 auditors was
less than 10%, which was within SPE’s acceptable tolerance.

In the conduct of the reserves audits, our independent auditors 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 auditors 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 our proved reserves as of
December 31, 2019, which are attached as an exhibit to this Form 10-K.

Ryder Scott qualifications – The primary technical engineer responsible for our audit has 42 years
of petroleum engineering experience, the majority of which has been in the estimation and evaluation
of reserves. He serves on the Ryder Scott Board of Directors and is a registered Professional Engineer
in the state of Texas.

NSAI qualifications – The two technical persons primarily responsible for our audit have over 18

years and 40 years of petroleum engineering experience, respectively. Both individuals have the
education, training and experience to perform oil and gas reservoir studies and reserves evaluations.

Recovery Mechanisms

The following table sets forth our reserves and production by basin and recovery mechanism:

Total Proved
Reserves

% of Total Basin

MMBoe(a)

Average Net Daily
Production (MBoe/d)

Year ended
December 31, 2019

San Joaquin Basin

Primary
Waterfloods
Steamfloods
Unconventional

San Joaquin Basin

Los Angeles Basin

Waterfloods

Los Angeles Basin subtotal

Ventura Basin

Primary
Waterfloods

Ventura Basin subtotal

Sacramento Basin

Primary

Sacramento Basin subtotal

Total

14%
12%
32%
42%

100%

39%
61%

100%

417

170

644

15
11
23
45

3
2

128

(a) Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet

of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

Conventional Reservoirs

We seek to optimize the potential of our conventional assets by using primary recovery methods,
followed by IOR methods like waterflooding and EOR methods like steamflooding, both of which use
vertical and lateral drilling. We determine which development method to use based on reservoir
characteristics, reserves potential and expected returns. All of these techniques are well understood
technologies that we have used extensively in California.

Primary Recovery

Primary recovery is a reservoir drive mechanism that utilizes the natural flow of the reservoir and
is the first technique we use to develop a conventional reservoir. Our successful exploration program
continues to provide us with primary recovery opportunities in new reservoirs or through extensions of
existing fields. Our primary recovery programs create future opportunities to convert these reservoirs to
waterfloods or steamfloods after their primary production phase.

Waterfloods

Some of our fields have been partially produced and no longer have sufficient energy to drive oil to

our producing wellbores. Waterflooding is a well understood process that has been used in California
for over 50 years to re-introduce energy to the reservoir through water injection and to sweep oil to
producing wellbores. This process has been known to increase recovery factors from approximately
10% under primary recovery methods to up to approximately 20%. Our waterflood operations have
attractive margins and returns. These operations typically have low and predictable production declines
and allow us to extend the productive life of a reservoir and significantly increase our incremental
recovery after primary recovery. As a result, investments in waterfloods can yield attractive returns
even in a low oil price environment.

Steamfloods

Some of our fields contain heavy, thick oil. Steamfloods work by injecting steam into the reservoir

to heat the oil which allows it to flow more easily to the producing wellbores. Steamflooding is a well
understood process that has been used in California since the early 1960s. This process has been
known to increase recovery factors from approximately 10% under primary recovery methods to up to
approximately 75%. Thermal operations are most effective in shallow reservoirs containing heavy,
viscous oil. The steamflood process generally requires low capital investment with attractive margins
and returns even in a low oil price environment. The economics of steamflooding are largely a function
of the ratio between oil and natural gas prices as gas is used to generate steam production and,
therefore, offers favorable returns as long as the oil-to-gas price ratio is in excess of five. In 2019, the
oil-to-gas ratio averaged over 20. After drilling, these operations typically ramp up production over one
to two years as the steam continues to influence the oil production, and then exhibit a plateau for
several months, with a subsequent low, predictable production decline rate of 5% to 10% per year.
This gradual decline allows us to extend the productive life of a reservoir and significantly increase our
incremental recovery after primary production.

Unconventional Reservoirs

We have a significant portfolio of lower permeability unconventional reservoirs that typically utilize

enhanced completion techniques. We believe our undeveloped unconventional acreage has the
potential to provide significant long-term production growth. In total, we hold mineral interests in
approximately 1.3 million net acres with unconventional potential and have identified 4,440 gross
(4,420 net) unconventional drilling locations on this acreage, excluding unconventional exploration
drilling locations. Approximately 35% of our 2019 production was from unconventional reservoirs, all in
the San Joaquin basin. Our unconventional production from our largest field, the Elk Hills field in the
San Joaquin basin, decreased approximately 6% in 2019 from the prior year. As of December 31,
2019, we had proved reserves of approximately 175 MMBoe associated with our unconventional
properties, approximately 18% of which were proved undeveloped reserves.

We hold significant interests in the Monterey formation, which is divided into upper and lower

intervals. Prior to the severe price declines that began in late 2014, we were focused on developing
higher-value unconventional production from seven discrete stacked pay horizons within the Monterey
formation, primarily within the upper Monterey. We have continued our development activities in the
upper Monterey formation and delineation of the Kreyenhagen formation within our Kettleman North
Dome field. During the year ended December 31, 2019, we had unconventional production of
approximately 44 MBoe/d on average from the upper Monterey in the San Joaquin basin.

The lower Monterey is recognized as a world-class source rock but has an extremely limited
production history compared to the upper Monterey, and therefore very limited knowledge exists
regarding its potential. However, over the long term, we believe we will be able to apply knowledge we
gain from the upper Monterey to the lower Monterey, Kreyenhagen and Moreno formations, which
have similar geological attributes.

Drilling Locations

The table below sets forth our total gross identified drilling locations as of December 31, 2019,

excluding our unconventional exploration drilling locations.

Proven Drilling Locations

Total Identified Drilling Locations

Oil and
Natural Gas Wells

Injection
Wells

Oil and
Natural Gas Wells

Injection
Wells

San Joaquin Basin

Primary Conventional
Steamflood
Waterflood
Unconventional

San Joaquin Basin subtotal

Los Angeles Basin

Primary Conventional
Waterflood

Los Angeles Basin subtotal

Ventura Basin

Primary Conventional
Steamflood
Waterflood
Unconventional

Ventura Basin subtotal

Sacramento Basin

Primary Conventional

Sacramento Basin subtotal

90
730
120
120

1,060

—
500

500

30
—
70
—

100

—
170
50
—

220

—
130

130

—
—
60
—

—

Total Drilling Locations

1,690

410

8,640
7,750
1,920
4,440

22,750

60
1,510

1,570

1,630
90
1,560
—

3,280

2,210

29,810

—
450
1,000
—

1,450

—
460

460

—
—
560
—

560

—

2,470

Note: Total gross identified drilling locations are comprised of gross proven drilling locations of 2,100 gross (1,890 net), gross

unproven drilling locations of 16,270 gross (15,800 net) and gross conventional exploration drilling locations of 13,910
gross (6,660 net). Total gross identified drilling locations exclude gross unconventional exploration drilling locations of
6,400 gross (5,300 net).

Proven Drilling Locations

Based on our reserves report as of December 31, 2019, we have approximately 2,100 gross
(1,890 net) drilling locations attributable to our proved undeveloped reserves. We use production data
and experience gained from our development programs to identify and prioritize this proven drilling
inventory. These drilling locations are included in our reserves only after we have adopted a
development plan to drill them within a five-year time frame. 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.

Unproven Drilling Locations

We have also identified a multi-year inventory of 16,270 gross (15,800 net) drilling locations that
are not associated with proved undeveloped reserves but are specifically identified on a field-by-field
basis considering the applicable geologic, engineering and production data. We analyze past field
development practices and identify analogous drilling opportunities taking into consideration historical
production performance, estimated drilling and completion costs, spacing and other performance
factors. These drilling locations primarily include (i) infill drilling locations, (ii) additional locations due to
field extensions or (iii) potential IOR and EOR project expansions, some of which are currently in the
pilot phase across our properties but have yet to be moved to the proven category. We believe the
assumptions and data used to estimate these drilling locations are consistent with established industry
practices with well spacing selected based on the type of recovery process we are using.

Exploration Drilling Locations

Conventional – Our exploration portfolio contains approximately 13,910 gross (6,660 net) unrisked
prospective drilling locations in conventional reservoirs, the majority of which are located near existing
producing fields. We use internally generated information and proprietary geologic models consisting of
analog data, 3D seismic data, open hole and mud log data, cores and reservoir engineering data to
help define the extent of the targeted intervals and the potential ability of such intervals to produce
commercial quantities of hydrocarbons. Information used to identify exploration locations includes both
our own proprietary data, as well as industry data available in the public domain. After defining the
potential areal extent of an exploration prospect, we identify our exploration drilling locations within the
prospect by applying the well spacing historically utilized for the applicable type of recovery process
used in analogous fields.

Unconventional – We have approximately 6,400 gross (5,300 net) unrisked prospective resource
drilling locations identified in the lower Monterey, Kreyenhagen and Moreno unconventional reservoirs
based on screening criteria that include geologic and economic considerations and limited production
information. Prospective areas are defined by geologic data consisting of well cuttings, hydrocarbon
shows, open-hole well logs, geochemical data, available 3D or 2D seismic data and formation pressure
data, where available. Information used to identify our prospective locations includes both our own
proprietary data, as well as industry data available in the public domain. We identify our prospective
resource drilling locations based on an assumption of 80-acre spacing per well throughout the
prospective area.

Well Spacing Determination

Our well spacing determinations for identified well locations are based on actual operational

spacing within our existing producing fields, which we believe are reasonable for the particular
recovery process employed (e.g., primary, waterflood or steamflood). Due to the significant vertical
thickness and multiple stacked reservoirs, typical well spacing is generally less than 20 acres and often
10 acres or less in the majority of our fields unless specified differently above. These parameters also
meet the general well spacing restrictions imposed on certain oil and natural gas fields in California.

Drilling Schedule

Our identified drilling locations are either included in our drilling schedule or are expected to be

scheduled in the future. When we identify these locations, we make assumptions about the
consistency and accuracy of data that may prove inaccurate. For a discussion of the risks associated
with our drilling program, see Part I, Item 1A – Risk Factors – Risks Related to Our Business and
Industry.

Drilling Statistics

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

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total Net
Wells

2019
Productive

Exploratory
Development

Dry

Exploratory
Development

2018
Productive

Exploratory
Development

Dry

Exploratory
Development

2017
Productive

Exploratory
Development

Dry

Exploratory
Development

—
2.0

—
—

—
3.2

0.3
—

—
1.6

—
—

—
2.4

—
—

0.3
147.1

—
—

0.3
178.4

1.6
—

2.0
107.9

3.0
—

—
25.2

—
—

—
48.2

—
—

—
14.5

—
—

0.3
117.5

—
—

0.3
127.0

1.3
—

2.0
91.8

3.0
—

The following table sets forth information on our exploration and development wells where drilling

was either in progress or pending completion as of December 31, 2019, which is not included in the
above table.

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total

Exploratory and development wells

Gross(a)
Net(b)

22.0
—

4.0
3.6

—
—

2.0
0.8

28.0
4.4

(a) The total number of wells in which interests are owned, including MIRA and Alpine JV wells.
(b) Net wells include wells reduced to our fractional interest.

On a gross basis, these projects included two primary, four waterflood, eleven steamflood and

eleven unconventional wells.

Productive Wells

Productive wells are those that produce, or are capable of producing, commercial quantities of

hydrocarbons, regardless of whether they produce a reasonable rate of return. Our average working
interest in our producing wells is approximately 90%. Wells are categorized based on the primary
product they produce.

The following table sets forth our productive oil and natural gas wells (both producing and capable

of production) as of December 31, 2019, excluding wells that have been idle for more than five years:

As of December 31, 2019

Productive Oil Wells
Gross(a)

Net(b)

Productive Natural Gas
Wells

Gross(a)

Net(b)

8,525
1,457
730
—

10,712

248

7,559
1,410
726
—

9,695

234

160
—
—
926

155
—
—
848

1,086

1,003

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 Program

We have an active exploration program in both conventional and unconventional plays. We
believe our experienced technical staff, proprietary geological models, mineral acreage position and
extensive 3D seismic library give us a strong competitive advantage in our exploration efforts.
California basins have generated billions of barrels of oil and trillions of cubic feet of natural gas and
have established production from over 400 identified reservoir intervals in both structural and
stratigraphic trap configurations. Historical industry activity has focused on the primary and secondary
development of known hydrocarbon accumulations, many of which were discovered over a century
ago. We have significant land positions in under-explored hydrocarbon reservoirs in each of
California’s four major oil and natural gas basins.

Our exploration program is designed to extend fields and add new trends and resource plays to
our already broad portfolio, targeting new oil and natural gas accumulations and leveraging our existing
infrastructure. We continue to focus on growing our exploration drilling locations and resource
identification, in some cases working with JV partners, in the San Joaquin, Sacramento and Ventura
Basins. We have a ranked near-field portfolio of over 150 exploration prospects across the
San Joaquin, Sacramento and Ventura basins.

We have executed a deliberate approach to fund a portion of our exploration program through

farmouts and joint ventures allowing us to test multiple prospects for minimal net investment.
Generally, our partners fund the drilling activity in an exploration area on a promoted basis with any
future development wells funded in proportion to the respective working interest percentages.

Marketing Arrangements

Crude Oil – We sell nearly all of our crude oil into the California refining markets, which offer
favorable pricing for comparable grades relative to other U.S. regions. Currently, the majority of our
crude oil sales contracts are index-based and have 30- to 90-day terms.

Although California state policies actively promote and subsidize renewable energy, including

solar, wind, biomass and geothermal resources, the demand for oil and natural gas in California
remains strong. California is heavily reliant on imported sources of energy, with approximately 72% of
oil and 90% of natural gas consumed in 2019 imported from outside the state. Nearly all of the
imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have
typically purchased crude oil at international waterborne-based Brent prices. We believe that the
limited crude transportation infrastructure from other parts of the U.S. into California will continue to
contribute to higher realizations than most other U.S. oil markets for comparable grades.

The International Maritime Organization has ruled that beginning in 2020 (IMO 2020), the marine

sector will have to reduce sulfur emissions by over 80% by either switching to lower sulfur fuels or
installing scrubbing facilities. The majority of the oil we produce has a lower sulfur content than the
average oil produced in California and other oil imported into the state. As a result of IMO 2020, we
may see an increased demand for low-sulfur crude oil, which could favorably affect our realized prices.

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.

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

on a monthly basis at market-based 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 favorable margins relative to out-of-state producers due to lower transportation costs on
the delivery of our natural gas. Changes in natural gas prices have a smaller impact on our operating
results than changes in oil prices as only approximately 25% of our total equivalent production volume
and even a smaller percentage of our revenue is from natural gas.

In addition to selling natural gas, we also use natural gas 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 higher revenue. Conversely, lower natural gas prices
lower the operating costs but have a net negative effect on our financial results.

We currently have sufficient firm transportation capacity contracts to transport our natural gas,
where some capacity volumes vary by month. We sell virtually all of our natural gas production under
individually negotiated contracts using market-based pricing on a monthly or shorter basis.

NGLs – NGL price realizations are related to the supply and demand for the products making up

these liquids. Some of them more typically correlate to the price of oil while others are affected by
natural gas prices as well as the demand for certain chemical products for which they are used as
feedstock. In addition, infrastructure constraints and seasonality can magnify price volatility.

Our earnings are also affected by the performance of our complementary 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 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 pipeline delivery contracts to transport 16,500 barrels per day of NGLs to
market. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold
pursuant to one-year contracts that are renewed annually. Approximately 32% of our NGLs are sold to
export markets. Our contracts to deliver NGLs require us to cash settle any shortfall between the
committed quantities and volumes actually delivered. For one of these contracts we expect to cash
settle approximately $20 million in April 2020.

Electricity – Part of the electrical output of the Elk Hills power plant operated by one of our

subsidiaries is used by Elk Hills and other nearby fields, which reduces operating costs and increases
reliability. We sell the excess electricity generated to the grid and a local utility. The power sold to the
utility is subject to agreements through the end of 2023, which include a monthly capacity payment
plus a variable payment based on the quantity of power purchased each month. The prices obtained
for excess power impact our earnings but generally by an insignificant amount.

Delivery Commitments

We have short-term commitments to certain refineries and other buyers to deliver oil, natural gas
and NGLs. As of December 31, 2019, we had oil and NGL delivery commitments of 51 and 17 MBbl/d
through March 2020, respectively, and natural gas commitments of 29 MMcf/d through the end of
2020. 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 are index-based contracts
with prices set at the time of delivery.

Hedging

We maintain a commodity hedging program primarily focused on crude oil to help protect our cash
flows, margins and capital program from the volatility of commodity prices and to improve our ability to
comply with the covenants under our credit facilities. We build our commodity hedge positions to
protect our downside risk without significantly limiting our upside potential, but we can give no
assurances that our hedges will be adequate to accomplish our objectives. We will continue to be
strategic and opportunistic in implementing our hedging program. 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. For more on our
current derivative contracts, see Part II, Item 7 – Management’s Discussion and Analysis of Financial
Condition and Results of Operations, Liquidity and Capital Resources.

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.

For the year ended December 31, 2019, our principal customers, Phillips 66 Company and Valero
Marketing & Supply Company, each accounted for at least 10%, and collectively accounted for 46%, of
our oil and natural gas sales before the effects of hedging. For the year ended December 31, 2018, our
principal customers, Phillips 66 Company and Valero Marketing & Supply Company, each accounted
for at least 10%, and collectively accounted for 43%, of our oil and natural gas sales before the effects
of hedging. For the year ended December 31, 2017, our principal customers, Phillips 66 Company,
Andeavor Logistic LP, Valero Marketing & Supply Company and Shell Trading (US) Company, each
accounted for at least 10%, and collectively accounted for 67%, of our oil and natural gas sales before
the effects of hedging.

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. In
addition, substantially all of our properties have been pledged as collateral for our secured debt.

Competition

We encounter strong competition from numerous parties in the oil and natural gas industry doing
business in California, ranging from small independent producers to major international oil companies.
The oil market in California is a captive market with no interstate crude pipelines and only limited rail
access and unloading capacity for refineries. California imports 72% of the oil it consumes and virtually
all of that arrives from waterborne sources. Our proximity to the California refineries gives us a
competitive advantage through 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.
However, the California energy industry has experienced only limited cost inflation in recent years due
to excess capacity in the service and supply sectors. At current commodity price levels, we expect
limited cost inflation to continue in 2020. Further, our relative size and activity levels, compared to other
in-state producers, favorably influences the pricing we receive from third-party providers in the local
markets in which we operate.

We also face indirect competition from alternative energy sources, including wind and solar power.

Competitive conditions could be affected by future legislation and regulation as California develops
renewable energy and implements climate-related policies.

Infrastructure

We own or control a network of infrastructure that is integral to and complements our operations.

The significant scale of our integrated infrastructure helps us connect to third-party transportation
pipelines, providing us with a competitive advantage by reducing our operating costs. Our
infrastructure includes the following:

Description

Quantity

Unit(a)

Capacity

San Joaquin Basin

Gas Processing Plants
Power Plants
Steam Generators/Plants
Compressors
Water Management Systems
Water Softeners
Oil and NGL Storage
Gathering Systems

9
3
>50
400
22
30

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

610
600
220
300
2,400
265
580

Other
Basins

50
50
—
20
2,100
—
660

Total

660
650
220
320
4,500
265
1,240
>8,000

(a) MW refers to megawatts of power; MBbl/d refers to thousand barrels of steam per day; MHp refers to thousand

horsepower; MBw/d refers to thousand barrels of water per day; MBbl refers to thousands of barrels.

Natural Gas Processing

We believe we own or control the largest gas processing system in California. In the San Joaquin

basin, the Elk Hills cryogenic gas plant has a capacity of 200 MMcf/d of inlet gas, bringing our total
processing capacity in the basin to over 610 MMcf/d. We also own and operate a system of natural gas
processing facilities in the Ventura basin that are capable of processing our equity and third-party
wellhead gas from the surrounding areas. 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.

Electricity

Our 550-megawatt combined-cycle Elk Hills power plant, located adjacent to the Elk Hills natural

gas processing facility, 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 our
operations and our subsidiary sells the excess to the grid and to a local utility. The Elk Hills power plant
also provides primary steam supply to our cryogenic gas plant. We also operate, as needed, a
45-megawatt cogeneration facility at Elk Hills that provides additional flexibility and reliability to support
field operations. Within our Long Beach operations in the Los Angeles basin, we operate a
48-megawatt power generating facility that provides over 40% of our Long Beach operation’s electricity
requirements. All of these facilities are integrated with our operations to improve their reliability and
performance while reducing operating costs.

Water and Steam Infrastructure

We own, control and operate water management and steam-generation infrastructure, including
steam generators, steam plants, steam distribution systems, steam injection lines and headers, water
softeners and water processing systems. We soften and self-supply water to generate steam, reducing
our operating costs. This infrastructure is integral to our operations in the San Joaquin basin and
supports our high-margin oil fields such as Kern Front.

Gathering Systems

We own an extensive network of over 8,000 miles of oil and natural gas gathering lines. These
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. These lines
connect our producing wells and facilities to gathering networks, natural gas collection and
compression systems, and water and steam processing, injection and distribution systems. Our oil
gathering systems connect to multiple third-party transportation pipelines, which increases our flexibility
to ship to various parties. In addition, virtually all of our natural gas facilities connect with major third-
party natural gas pipeline systems. As a result of these connections, we typically have the ability to
access multiple delivery points to improve the prices we obtain for our oil and natural gas production.

Oil and NGL Storage

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.

Employees

We had approximately 1,250 employees as of December 31, 2019. Approximately 900 were
employed in field operations, of which approximately 70 were represented by labor unions. We have
not experienced any strikes or work stoppages by our employees. We also utilized the services of
independent contractors to perform drilling, well work, operations, construction and other services,
including construction contractors whose workforce is represented by labor unions.

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

Federal, state and local laws and regulations govern most aspects of exploration and production in

California, including:

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oil and natural gas production, including siting and spacing of wells and facilities on federal,
state and private lands with associated conditions or mitigation measures;

(cid:129) methods of constructing, drilling, completing, stimulating, operating, inspecting, maintaining

(cid:129)

and abandoning wells;
the design, construction, operation, inspection, maintenance and decommissioning of
facilities, such as natural gas processing plants, power plants, compressors and liquid and
natural gas pipelines or gathering lines;

(cid:129)
(cid:129)

(cid:129)

improved or enhanced recovery techniques such as fluid injection for pressure management;
sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and
improved or enhanced recovery processes;
imposition of taxes and fees with respect to our properties and operations;
the conservation of oil and natural gas, including provisions for the unitization or pooling of oil
and natural gas properties;
posting of bonds or other financial assurance to drill, operate and abandon or decommission
wells and facilities; and
health, safety and environmental matters and the transportation, marketing and sale of our
products as described below.

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.

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 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, effective in 30 days, until the
County makes certain revisions to the EIR and recertifies it. This process may take several months,
during which time drilling and other permits may be delayed in Kern County. We do not currently
expect this process to materially affect our plans and operations at Elk Hills or other fields we operate
in Kern County as the Court of Appeal’s ruling does not invalidate existing permits and we maintain a
robust drilling permit inventory. In addition, other governmental agencies have previously conducted
several environmental reviews for activities at Elk Hills, including under NEPA and CEQA, which we
believe provide additional support for continued issuance of drilling and other permits at Elk Hills.

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 November 2019, the State Department of
Conservation issued a press release announcing three actions by CalGEM: (1) a moratorium on
approval of new high–pressure cyclic steam wells pending a study of the practice to address surface
expressions experienced by certain operators; (2) review and updating of regulations regarding public
health and safety near oil and natural gas operations pursuant to additional duties assigned to CalGEM
by the Legislature in 2019; and (3) a performance audit of CalGEM’s permitting processes for well
stimulation treatment (WST) permits and project approval letters for underground injection (PALs) by
the State Department of Finance and an independent review and approval of the technical content of
pending WST and PAL applications by Lawrence Livermore National Laboratory. While we do not use
high-pressure cyclic steam injection and have not historically utilized well stimulation techniques to
complete the majority of our wells, additional state regulation of exploration and production activities
could result in increased operating costs or delays in or the inability to obtain permits, or otherwise
adversely affect production from the underlying properties.

In 2013 California State Legislature (Legislature) enacted Senate Bill 4 (SB 4), which increased

regulation of certain well stimulation techniques, including acid matrix stimulation and hydraulic
fracturing, which involves the injection of fluid under pressure into underground rock formations to
create or enlarge fractures to allow oil and natural gas to flow more freely into producing wells. Among
other things, SB 4 requires operators to obtain specific WST permits, make detailed disclosures and
implement groundwater monitoring and water management plans. After allegations of conflicts of
interest by certain oil and natural gas regulators, the State Oil and Gas Supervisor was replaced, and
the state has not issued new WST permits since July 2019, pending completion of Lawrence Livermore
National Laboratory’s review of the technical content of each new WST permit. The U.S. Environmental
Protection Agency (EPA) and the BLM also regulate certain well stimulation activities. In 2017, the
BLM rescinded its nationwide hydraulic fracturing regulations; however, the rescission is subject to
ongoing legal challenge. Separately, the BLM’s implementation of its 2014 Resource Management
Plan (RMP) for leasing of federal lands in portions of Kern, Ventura and other counties has been
delayed by litigation and a settlement from a 2017 court order that required the BLM to prepare a
Supplemental Environmental Impact Statement (SEIS) addressing hydraulic fracturing in greater detail.
In the fourth quarter of 2019, the BLM issued the SEIS and its Record of Decision approving the 2014
RMP without changes, and the state has challenged the BLM’s decision in court. The implementation
of well stimulation regulations has delayed, and increased the cost of, certain operations.

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 2020 regarding
digital mapping of such lines. The Office of the State Fire Marshal (OSFM) has proposed regulations
that are expected to take effect 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 Pipeline and Hazardous
Materials Safety Administration issued new regulations in October 2019 expanding integrity
management, leak detection and reporting requirements for liquid pipelines and natural gas
transmission pipelines, with various implementation periods beginning in July 2020 and specific
requirements dependent upon the characteristics of the line and its location.

In 2019, Assembly Bill 345 (AB 345) was introduced but failed to advance in the Legislature to
impose a statewide setback distance of 2,500 feet between certain oil and natural gas operations and
residences, schools and healthcare facilities. CalGEM is commencing public health and safety
workshops in the first quarter of 2020 to be followed by an associated rulemaking process that will
consider various measures, including potential land use setbacks. In January 2020, the State
Assembly passed an amended version of AB 345 that, if passed by the State Senate and signed by the
Governor, would require CalGEM to adopt a land use setback in its rulemaking by July 2022. As
amended, the bill no longer specifies a mandatory setback distance, but would require CalGEM to
consider a 2,500-foot setback as well as enhanced monitoring and maintenance requirements.

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. The most
onerous of these local measures was adopted in 2016 by Monterey County, where we owned mineral
rights but have no production. As written, the measure sought to prohibit the drilling of new oil and
natural gas wells, hydraulic fracturing and other well-stimulation techniques and to phase out the
injection of produced water. This measure was challenged in state court and the Monterey County
Superior Court issued a decision in 2017, finding that the bans on drilling new wells and water injection
are preempted by and invalid under existing state and federal regulations and, if implemented, would
constitute a taking of our property and that of other mineral rights owners without compensation. The
court did not rule on the ban on hydraulic fracturing because the court found that the issue was not ripe
since hydraulic fracturing is not currently being conducted in Monterey County, noting that the ban
could be challenged in the event a project involving hydraulic fracturing is proposed. Although the
County is complying with and declined to appeal the Court’s decision and settled the litigation,
sponsors of the ballot measure have appealed.

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:

(cid:129)

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;

(cid:129)
(cid:129) may expose us to litigation with government authorities, counterparties, special interest

groups or others; and

(cid:129) may restrict our rate of oil, NGLs, natural gas and electricity production.

Due to recent droughts and 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 is an essential
component of 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.

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 Safe
Drinking Water Act (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. As previously noted, the State Department of Finance is conducting a performance audit of
CalGEM’s permitting process for injection projects, with an independent review of the technical content
of pending injection PALs by Lawrence Livermore National Laboratory.

Separately, the state began a review in 2015 of permitted surface discharge of produced water

and the use of reclaimed water for agricultural irrigation, which led to additional permitting and
monitoring requirements in 2017 for surface discharge. To date, the foregoing regulatory actions have
not affected our oil and natural gas operations in a material way. These reviews are ongoing, and
government authorities may ultimately restrict injection of produced water or other fluids in additional
formations or certain wells, restrict the surface discharge or use of produced water or take other
administrative actions. The foregoing reviews could also give rise to litigation with government
authorities and third parties.

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. In November 2019, the U.S. formally announced
its withdrawal from the 2015 Paris Agreement on climate change, effective in November 2020.
Notwithstanding this action, the EPA has adopted federal regulations to:

(cid:129)

(cid:129)
(cid:129)

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

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

state laws and regulations:

(cid:129)

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;

(cid:129) mandated that California derive 60% of its electricity for retail customers from renewable

(cid:129)

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

(cid:129) 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.

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 increased the flexibility of certain of its
federal methane regulations in 2019, 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, which may affect the prices we realize.

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:

(cid:129)

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;

(cid:129)
(cid:129) market transparency rules with respect to natural gas and power markets;
(cid:129)

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.

(cid:129)

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 report on Form 10-K,

quarterly reports on Form 10-Q, current reports on Form 8-K, our annual 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. Our website contains additional important
information such as our Sustainability Report and descriptions of our health, safety, environmental and
community outreach programs, as well as reconciliations of non-GAAP financial measures and
additional information on performance measures. Unless otherwise provided herein, information
contained on our website is not part of this report. The SEC maintains an internet site, http://
www.sec.gov, that contains reports, proxy and information statements, and other information regarding
issuers that file electronically with the SEC.

ITEM 1A

RISK FACTORS

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

Prices for our products can fluctuate widely and an extended period of low prices could
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. Under these conditions, if we were unable to improve
liquidity through additional financing, asset monetizations, restructuring of our debt obligations, equity
issuances or otherwise, cash flow from operations and expected available credit capacity could be
insufficient to meet our commitments. Successfully completing these actions could have significant
adverse effects such as higher operating and financing costs, dilution of equity and further covenant
restrictions. Past refinancing activities have resulted in increases in our annual interest expense and
future refinancing activities may have the same or greater effect.

Historically, the markets for oil, natural gas and NGLs have been volatile and they are likely to

continue to be so. We are particularly dependent on Brent crude prices that have been as low as
$27.88 per barrel and as high as $115.19 per barrel during the period between 2014 and 2019. Factors
affecting these commodity prices include:

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changes in domestic and global supply and demand;
domestic and global inventory levels;
political and economic conditions;
the actions of OPEC and other significant producers and governments;
changes or disruptions in actual or anticipated production, refining and processing;
worldwide drilling and exploration activities;
government energy policies and regulation, including with respect to climate change;
the effects of conservation;
weather conditions and other seasonal impacts;
speculative trading in derivative contracts;
currency exchange rates;
technological advances;
transportation and storage capacity, bottlenecks and costs in producing areas;
the price, availability and acceptance of alternative energy sources;
regional market conditions; and
other matters affecting the supply and demand dynamics for these products.

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

and cash flow, including:

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reducing our proved oil and natural gas reserves over time, including as a result of
impairments of existing reserves;
limiting our ability to grow or maintain future production including a delay in the reversion
dates of certain of our JVs;

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causing a reduction in our borrowing base under our 2014 Revolving Credit Facility, which
could affect our liquidity;
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;
forcing monetization events of certain assets under one of our JV arrangements;
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 of our equity and debt securities.

Our hedging program does not provide downside protection for all of our production in 2020 and

beyond. As a result, our hedges do not fully protect us from commodity price declines, and we may be
unable to enter into acceptable additional hedges in the future.

Our lenders could limit our borrowing capabilities and restrict our ability to use or access
capital.

Our 2014 Revolving Credit Facility is an important source of our liquidity. Our ability to borrow

under our 2014 Revolving Credit Facility is limited by our borrowing base, the size of our lenders’
commitments and our ability to comply with covenants, including a minimum month-end liquidity
requirement of $150 million. As of December 31, 2019, we had approximately $317 million of available
borrowing capacity, before taking into account the minimum month-end liquidity requirement.

The borrowing base under our 2014 Revolving Credit Facility is redetermined semi-annually on
May 1 and November 1. Our lenders determine our borrowing base by reference to the value of our
reserves and other factors that the administrative agent may deem appropriate in good faith in
accordance with its usual and customary oil and gas lending criteria as they exist at the particular time.
The lenders under our 2014 Revolving Credit Facility may also factor other liabilities, including our
other indebtedness, into the determination of our borrowing base. Currently, our borrowing base is set
at $2.3 billion and the lenders’ aggregate commitment under our 2014 Revolving Credit Facility is
$1 billion. However, the $1.3 billion outstanding under our 2017 Credit Agreement is taken into account
in limiting the amount of such commitment. Thus, any reduction in our borrowing base would have the
effect of reducing capacity under the 2014 Revolving Credit Facility. Any such reduction requires the
consent and approval of the lenders holding 66 2/3% of the commitments under the 2014 Revolving
Credit Facility.

We have informed the Administrative Agent under our 2014 Revolving Credit Facility of the
proposed exchange offers described in our Form 8-K filed on February 21, 2020 and discussions are
ongoing. Initially, the Administrative Agent expressed its own view that consummation of the exchange
transactions may present material concerns to our first lien lenders, including lenders under the 2014
Revolving Credit Facility who could seek a significant reduction in our borrowing base on or before our
next scheduled borrowing base redetermination. We have not received similar communications from
other large lenders in our 2014 Revolving Credit Facility, some of which are dealer managers in the
proposed exchange offers. Our more recent discussions with the Administrative Agent have focused
on our need to address the debt maturities in 2021 and 2022, the subsequent steps that we plan to
take to address refinancing these debt maturities and that the transactions described herein are a first
step toward that objective. The Administrative Agent has indicated that if we address these maturities
before the next redetermination date, a more muted response from the first lien lenders may be
possible. The Administrative Agent did note, however, that many considerations will go into the
ultimate decision by the lenders under the 2014 Revolving Credit Facility and the weight of those
considerations may vary given conditions of both the lending market and the general upstream industry
at the time.

We cannot assure you that the lenders under the 2014 Revolving Credit Facility will not reduce our

borrowing base by a material amount as a result of the proposed exchange offers or otherwise. Any
reduction in our $2.3 billion borrowing base would only have the effect of reducing the commitment
under the 2014 Revolving Credit Facility by up to $100 million unless the borrowing base reduction
exceeded $1.4 billion, at which point the reduction and loss of availability would be dollar for dollar. Any
reduction in our borrowing base could materially and adversely affect our liquidity and may hinder our
ability to execute on our development plan. We would seek to reduce our capital program and
expenses and potentially monetize assets among other things to address tighter liquidity constraints.
However, there can be no assurances that such actions will be possible or adequate to address such a
reduction in our borrowing base. If the reduction in our borrowing base were sufficiently severe that we
were unable to maintain adequate liquidity to conduct operations and meet our obligations, we could
ultimately be forced to seek bankruptcy protection.

The financial covenants that we must satisfy under our 2014 Revolving Credit Facility include a

month-end minimum liquidity test, certain financial ratios that measure our leverage and fixed interest
charges on a quarterly basis, and the present value of our reserves on a semi-annual basis. These
covenants could limit our ability to borrow under our 2014 Revolving Credit Facility or obtain additional
financing through the capital markets or otherwise. Certain other agreements governing our long-term
indebtedness also include financial ratios that are generally less restrictive than our 2014 Revolving
Credit Facility.

If we were to breach any of the covenants under our 2014 Revolving Credit Facility or any of our
other credit agreements or indentures, the lenders under our 2014 Revolving Credit Facility would be
permitted to cease lending under the facility, accelerate the repayment of the outstanding amounts due
and foreclose against the assets securing them.

For a further description of our 2014 Revolving Credit Facility and our other credit agreements,

see Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of
Operations, Liquidity and Capital Resources – Credit Agreements.

We have significant indebtedness that could limit our financial and operating flexibility and
make us more vulnerable in economic downturns.

As of December 31, 2019, the face value of our outstanding long-term consolidated indebtedness

was $4.98 billion. Our financing agreements permit us to incur significant additional indebtedness as
well as certain other obligations. In addition, we may seek amendments or waivers from our existing
lenders and bondholders to the extent we need to incur indebtedness above amounts currently
permitted by our financing agreements.

Our level of indebtedness may have adverse effects on our business, financial condition, cash

flows or results of operations, including:

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jeopardizing our ability to execute our business plans;
increasing our vulnerability to adverse changes in economic and industry conditions related to
our business;
putting us at a disadvantage against competitors that have lower fixed obligations and more
cash flow to devote to their businesses;
limiting our ability to obtain favorable financing for working capital, capital investments and
general corporate and other purposes;
limiting our ability to enter into hedging contracts;
limiting our ability to fund capital investments, react to competitive pressures and engage in
certain transactions that might otherwise be beneficial to us;

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defaulting on a commercial agreement with one of our JVs; and
failing to redeem the interests held by one of our JV partners.

Our financing agreements also include covenants that restrict management’s discretion to operate
our business in certain circumstances. These restrictions include limitations that could affect our ability
to:

incur additional indebtedness and grant additional liens;
repay junior indebtedness, including our Second Lien Notes and Senior Notes;

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enter into JVs;
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pay dividends and make other restricted payments;
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sell assets;
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use the proceeds of asset sales for certain purposes;
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enter into mergers or acquisitions; and
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release collateral.
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These limitations are further described in Item 7 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations – Liquidity and Capital Resources – Credit Agreements
and the documents governing our indebtedness that are filed with the SEC.

Our financing agreements, including the 2014 Revolving Credit Facility, contain customary cross-

default mechanisms that provide that an event of default under any one of those agreements may
trigger an event of default under all of those agreements. In such an event, we might not be able to
obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it
on terms acceptable to us, which would negatively affect our ability to implement our business plan,
make capital expenditures or finance our operations.

A significant portion of our outstanding indebtedness bears interest at variable rates. Although we

have purchased derivative contracts that limit our interest rate exposure for a portion of this
indebtedness, a rise in interest rates will increase our interest expense to the extent we do not have
interest-rate hedges and could limit our liquidity and our ability to comply with our debt covenants.

Our ability to meet our debt obligations and other financial needs will depend on our future

performance, which is influenced by market, financial, business, economic, regulatory and other
factors. If our cash flow is not sufficient, we may be required to refinance debt, sell assets or issue
additional equity on terms that may be unattractive, if these can be done at all. Failure to make a
scheduled payment or to comply with covenants relating to our indebtedness could result in a default.
In addition, any perceived or actual deterioration in our liquidity or credit position could cause our
counterparties to require new letters of credit or to increase the amounts covered by existing letters of
credit. Any of these factors could result in a material adverse effect on our business, financial
condition, cash flows or results of operations and a default on our indebtedness could result in
acceleration of all of our debt and foreclosure against assets constituting collateral for our
indebtedness.

A significant portion of our long-term indebtedness will mature within two years and will likely
need to be refinanced. There can be no assurances we will be able to refinance this
indebtedness on acceptable terms or at all.

Approximately $2 billion of our long-term indebtedness will mature in 2021, including amounts

outstanding under our 2014 Revolving Credit Facility and 2016 Credit Agreement. An additional
$1 billion under our 2017 Credit Agreement will mature in October 2021 if more than $100 million is
outstanding under our 2016 Credit Agreement at that time. Finally, our Second Lien indenture will
require us to make a principal repayment of $287 million in June 2021. Our ability to satisfy these
maturities and obligations will likely require us to refinance a large portion of this indebtedness. Our
ability to refinance indebtedness will depend on the condition of the capital markets and credit markets
and our financial condition and credit rating. The terms of existing debt instruments may restrict us
from pursuing certain refinancing strategies as well as other strategies to reduce indebtedness. Any
refinancing of our indebtedness could be at higher interest rates and may require us to comply with
more onerous covenants, which could further restrict our business operations. There can be no
assurances we will be able to refinance this indebtedness on acceptable terms or at all, and if we are
unable to do so we may not be able to satisfy these maturities and obligations as they become due.

Our stock price and trading volume may be volatile, which could result in losses for our
stockholders.

The public market for our common stock has been characterized by significant price and volume
fluctuations. Our stock price and volume may be affected by our operating results in any period which
fail to meet the investment community’s expectations and our stock price has experienced extreme
volatility that has often been unrelated to our operating performance. There can be no assurance that
the market price of our common stock will not decline below its current or historic price ranges. These
highly volatile market conditions, particularly in the oil and natural gas sector, could result in a
stockholder losing a substantial part or all of its investment in our common stock. In the past, following
periods of volatility in the market price of a company’s securities, securities litigation has been initiated.
Should litigation be initiated against us, whether or not successful, it could result in substantial costs
and diversion of our management’s attention, both of which could harm our business and financial
condition.

Our business requires substantial capital investments, which may include acquisitions or JVs.
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.

Our exploration, development and acquisition activities require substantial capital investments.

Historically, we have funded our capital investments through a combination of cash flow from
operations, borrowings under our 2014 Revolving Credit Facility and joint ventures. We seek to
manage our internally funded capital investments to closely align with projected 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 of external sources of financing.

Access to future capital may be limited by our lenders, our JV partners, 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 JVs.

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.

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

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

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

Our ability to add reserves, other than through acquisitions, depends on the success of improved

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

Generally, lower prices adversely affect the quantity of our reserves as those reserves expected to

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

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

Although 80% of our 2019 proved reserve estimates were audited by our independent petroleum
engineers, Ryder Scott Company, L.P. and Netherland, Sewell & Associates, Inc., 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 2014
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.

Acquisition and disposition activities and our JVs involve substantial risks.

Our acquisition activities carry risks that we may:

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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;
experience share price declines based on the market’s evaluation of the activity;
assume liabilities that are greater than anticipated; and
be exposed to currency, political, marketing, labor and other risks, particularly associated with
investments in foreign assets.

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 entering into JVs and divesting non-core assets. Our JVs

and disposition activities carry risks that we may:

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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 successfully enter into new JVs or that JVs will

occur in the time frames or with economic terms that we expect. We may also be unable to divest
assets on financially attractive terms or at all. Our ability to enter into JVs and sell assets is also limited
by the agreements governing our indebtedness.

If we are not able to sell assets as needed or enter into JVs, we may not be able to generate

proceeds to support our liquidity and capital investments.

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. Federal, state and local agencies may assert
overlapping authority to regulate these areas. For example, the jurisdiction, duties and enforcement
authority of various state agencies have significantly increased with respect to oil and natural gas
activities in recent years, and these state agencies as well as certain cities and counties have
significantly revised their regulations, regulatory interpretations and data collection and reporting
requirements and plan to issue additional regulations of certain oil and natural gas activities in 2020. In
addition, certain of these federal, state and local 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.

See Items 1 and 2 – Business and Properties – Regulation of the Oil and Natural Gas Industry for

a description of laws and regulations that affect our business. 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, fluid injection and disposal and water recycling and reuse. Failure to
comply may result in the assessment of administrative, civil and/or criminal fines and penalties and
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. Under certain environmental laws and regulations, we could be
subject to strict or joint and several liability for the removal or remediation of contamination, including
on properties over which we and our predecessors had no control, without regard to fault, legality of
the original activities, or ownership or control by third parties.

Our customers, including refineries and utilities, and the businesses that transport our products to

customers, are also highly regulated. For example, various government authorities have sought to
restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics.
Federal and state pipeline safety agencies have adopted or proposed regulations to expand their
jurisdiction to include more gas and liquid gathering lines and pipelines and to impose additional
mechanical integrity, leak detection and reporting requirements. The state has adopted additional
regulations on the storage of natural gas that could affect the demand for or availability of such
storage, increase seasonal volatility, or otherwise affect the prices we receive from customers. The
CPUC has 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. Certain municipalities
have enacted restrictions on the installation of natural gas appliances and infrastructure in new
residential or commercial construction, which could affect the retail natural gas market for our utility
customers and the demand and prices we receive for the natural gas we produce.

Costs of compliance may increase and operational delays or restrictions may occur as existing
laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to
our operations, each of which has occurred in the past.

Government authorities and other organizations continue to study health, safety and

environmental aspects of oil and natural gas operations, including those related to air, soil and water
quality, ground movement or seismicity and natural resources. For example, the Legislature expanded
CalGEM’s duties in 2019 to include public health and safety and CalGEM is commencing public health
and safety workshops in the first quarter of 2020 to be followed by an associated rulemaking process.
Government authorities have also adopted or proposed new or more stringent requirements for
permitting, inspection and maintenance of wells, pipelines and other facilities, and public disclosure or
environmental review of, or restrictions on, oil and natural gas operations, including proposed setback
distances from other land uses. Such requirements or associated litigation could result in potentially
significant added costs to comply, delay or curtail our exploration, development, fluid injection and
disposal or production activities, preclude us from drilling, completing or stimulating wells, or otherwise
restrict our ability to access and develop mineral rights, any of which could have an adverse effect on
our expected production, other operations and financial condition.

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 or 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.

Drilling for and producing oil and natural gas carry significant operational and financial risk 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 VCI.

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.

We allocate capital by reference to a VCI metric. We calculate the VCI of a well or project at the
time capital is allocated and frequently re-calculate the VCI after a well or project is completed. VCI is
calculated based on internal estimates of future cash flows and capital investment, which are inherently
uncertain. In addition, future cash flows are dependent on our production costs. Our production cost
per barrel is higher than that of many of our peers due to the extraction methods we use, the large
number of wells we operate and the effects of our PSC-type contracts.

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 VCI 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 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 approximately 15% of our total net
undeveloped acreage at December 31, 2019.

Part of our strategy involves 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.

One of our important assets is our acreage in the Monterey shale play in the San Joaquin, Los
Angeles and Ventura basins. The geology of the Monterey shale is highly complex and not uniform due
to localized and varied faulting and changes in structure and rock characteristics. As a result, it differs
from other shale plays that can be developed in part on the basis of their uniformity. Instead, individual
Monterey shale drilling sites may need to be more fully understood and may require a more precise
development approach, which could affect the timing, cost and our ability to develop this asset.

Our commodity-price risk-management activities may prevent us from fully benefiting from
price increases and may expose us to other risks.

Our commodity-price risk-management activities may prevent us from realizing the full benefits of

price increases above any levels set in certain derivative instruments we may use to manage price risk.
In addition, our commodity-price risk-management activities may expose us to the risk of financial loss
in certain circumstances, including instances in which the counterparties to our hedging or other price-
risk management contracts fail to perform under those arrangements.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the 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 may affect both the size of positions that
we may enter and the ability or willingness of counterparties to trade opposite us, potentially increasing
costs for transactions. Moreover, the effects of these regulations could reduce our hedging
opportunities which could adversely affect our revenues and cash flow during periods of low
commodity prices.

Recently, proposals have been made by U.S. regulators which would implement a new approach

for calculating the exposure of derivative contracts under the applicable agencies’ regulatory capital
rules, referred to as the standardized approach for counterparty credit risk or SA-CCR. If adopted as
proposed, certain financial institutions would be required to comply with the new SA-CCR rules
beginning on July 1, 2020 and the rules could significantly increase the capital requirements for certain
participants in the OTC derivatives market in which we participate. 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
effects of these regulations could reduce our hedging opportunities or substantially increase the cost of
hedging, which could adversely affect our revenues and cash flow.

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.

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. 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.

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.

Concerns about climate change and other air quality issues may 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 as
discussed in Part I, Items 1 and 2 – Business and Properties – Regulation of the Oil and Natural Gas
Industry. 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 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.

Concern over climate change and GHG and other emissions has also resulted in increasing
political risks in California and the United States, including climate change related pledges made by
various candidates for federal, state and local offices in California and certain candidates seeking the
office of the President of the United States in 2020. These include threats to ban hydraulic fracturing
and other stimulation of oil and natural gas wells and permitting of various operations, pipeline
infrastructure and other oil and gas facilities on government or private lands, which could negatively
impact our operations and properties. Other actions that could be pursued by presidential candidates
may include the reversal of the United States’ withdrawal from the Paris Agreement in November 2020,
as well as reversing various regulatory changes made or proposed by the Trump Administration to
promote energy production and other development. Additionally, various claimants, including certain
municipalities, have filed litigation alleging that energy producers are liable for damages attributed to
climate change.

In addition, other current and proposed international agreements and federal, state and local laws,
regulations and policies seek to restrict or reduce the use of petroleum products in transportation fuels,
electricity generation, plastics and other applications, prohibit future sale or use of vehicles, appliances
or equipment that require petroleum fuels, impose additional taxes and costs on producers and
consumers of petroleum products and require or subsidize the use of renewable energy. The state has
set an ambitious goal by executive order to be “carbon-neutral” by 2045 and initiated and funded
studies to identify strategies to implement this goal. The Legislature, state agencies and various
municipalities have adopted or proposed laws, regulations and policies that seek to significantly reduce
emissions from vehicles, increase the use of “zero emission” vehicles, reduce the use of plastics,
increase renewable energy mandates for utilities and in residential and commercial construction, and
replace natural gas appliances and infrastructure in residential and commercial buildings with electric
appliances.

Government authorities can impose administrative, civil and/or criminal penalties for

non-compliance with air permits or other requirements of the federal Clean Air Act and associated state
laws and regulations, and various state and local agencies are conducting increased regional,
community and field air monitoring specifically with respect to oil and natural gas operations. In
addition, California air quality laws and regulations, particularly in Southern and Central California
where most of our operations are located, are in most instances more stringent than analogous federal
laws and regulations. For example, the San Joaquin Valley will be required to adopt more rigorous
attainment plans under the Clean Air Act to comply with federal ozone and particulate matter
standards, and these efforts could affect our activities in the region and our ability and cost to obtain
permits for new or modified 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. Shareholders currently invested 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. Additionally, environmental activists, proponents of the
Paris Agreement, and other governmental and non-governmental organizations concerned about
climate change have sought to pressure public and private investment funds not to invest in oil and gas
companies and institutional lenders to restrict oil and gas companies’ access to capital. Limitation of
investments in and financings for oil and gas companies like us could result in the restriction, delay or
cancellation of drilling programs or development or production activities.

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 that align with the
state’s long-term goals and support our ability to continue to efficiently implement federal, state and
local laws, regulations and policies, including those relating to air quality and climate, in the future.
However, there can be no assurances that we will be able to design, permit, fund and implement such
projects in a timely and cost-effective manner or at all, or that we, our customers or end users of our
products will be able to satisfy long-term environmental, air quality or climate goals if those are applied
as enforceable mandates.

The adoption and implementation of new or more stringent international, federal, state or local
legislation, regulations or policies that impose more stringent standards for GHG or other emissions
from our operations or otherwise restrict the areas in which we may produce oil, natural gas, NGLs or
electricity or generate GHG or other emissions could result in increased costs of compliance or costs of
consuming, and thereby reduce demand for or 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.

We may incur substantial losses and be subject to substantial liability claims as a result of
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. In addition, events such as earthquakes, floods, mudslides, wildfires,
power outages, high winds, droughts, cyber-security, 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.

Information technology failures and cyber-security attacks 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.

Cyber-security attacks on businesses have escalated and become more sophisticated in recent

years and include attempts to gain unauthorized access to data, malicious software, ransomware and
other electronic security breaches that could lead to disruptions in critical systems, unauthorized
release of confidential information or the corruption of data. In addition, our vendors, customers and
other business partners may separately suffer disruptions or breaches from cyber-security attacks that,
in turn, could adversely impact our operations and compromise our information. 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. As the sophistication of
cyber-security attacks continues to evolve, we may be required to expend additional resources to
further enhance our security.

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 8 Lawsuits,
Claims, Commitments and Contingencies.

ITEM 4

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information for Common Stock

Our common stock is listed under the symbol “CRC” on the New York Stock Exchange.

Holders of Record

Our common stock was held by approximately 20,160 stockholders of record at December 31,

2019.

Dividend Policy

We currently do not pay, and do not anticipate paying, dividends on our common stock in the
foreseeable future. In addition, covenants under our 2014 Revolving Credit Facility generally restrict
the payment of cash dividends on our stock, subject to certain exceptions.

Securities Authorized for Issuance Under Equity Compensation Plans

We currently maintain two equity compensation plans that were approved by our shareholders.

The aggregate number of shares of our common stock authorized for issuance under these stock-
based compensation plans for our executives, employees and non-employee directors is 8.8 million, of
which approximately 5.8 million had been issued or reserved through December 31, 2019.

A warrant for 1,250,000 shares was issued in July 2019 with a $40.00 exercise price in connection

with one of our development joint ventures, the Alpine JV. The holder of the warrant will be entitled to
exercise the warrant in tranches as funding milestones are achieved. Each tranche has a five-year
term commencing on the date on which such tranche becomes exercisable. As of December 31, 2019,
200,000 shares of our common stock were exercisable under this warrant. For more on the Alpine JV
transaction, see Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and
Results of Operation, Joint Ventures.

The following is a summary of the securities available for issuance as of December 31, 2019:

Plan Category

Equity compensation plans
approved by security holders
Equity compensation plan not
approved by security holders(4)

Total

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)

2,477,714(1)

$59.00(2)

3,012,096(3)

1,250,000

3,727,714

$40.00

—

3,012,096

(1) We net settle shares issued upon exercise of options granted under our equity compensation plan. As a result, the
number of shares actually issued, if any, will be less than the amount shown. A description of our stock-based
compensation plans approved by security holders can be found in Part II, Item 8 – Financial Statements and
Supplementary Data, Note 11 Stock-Based Compensation.

(2) Exercise price applies only to approximately 1.4 million options included in column (a) and not to any other awards.
(3)

Includes 451,412 shares available under our 2014 Employee Stock Purchase Plan for purchase at 85% of the lower of
the market price at either (i) the beginning of a quarter or (ii) the end of a quarter.

(4) Represents the maximum number of shares issuable under the warrant agreement. The holder may elect to net settle
shares issued upon exercise of the warrant, in which case the number of shares issued, if any, will be less than the
amount shown.

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 (with reinvestment of all dividends). The graph assumes that on
December 31, 2014, $100 was invested in our common stock, in each index and in each of the peer
group companies’ common stock weighted by their relative market values within the peer group, and
that all dividends were reinvested. The results shown are based on historical results and are not
intended to suggest future performance.

Our 2019 peer group consists of Cabot Oil & Gas Corporation; Callon Petroleum Company;
Carrizo Oil & Gas, Inc.; Cimarex Energy Co.; Denbury Resources, Inc.; Diamondback Energy, Inc.; EP
Energy Corporation; Gulfport Energy Corporation; Laredo Petroleum, Inc.; Matador Resources
Company; Murphy Oil Corporation; Newfield Exploration Company; Oasis Petroleum Inc.; Parsley
Energy, Inc.; PDC Energy, Inc.; QEP Resources, Inc.; Range Resources Corporation; SM Energy
Company; Southwestern Energy Company; Whiting Petroleum Corporation and WPX Energy, Inc.
Excluded from the table below are Carrizo Oil & Gas, Inc. and Newfield Exploration Company, which
were acquired by Callon Petroleum Company and Encana Corporation, respectively, in 2019.

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

$200

$180

$160

$140

$120

$100

$80

$60

$40

$20

12/14

12/15

12/16

12/17

12/18

12/19

California Resources Corp

S&P 500

Dow Jones US Exploration & Production

Peer Group

2014

2015

2016

2017

2018

2019

December 31,

CRC
S&P 500
Dow Jones US Exploration & Production
2019 Peer Group

$
$
$
$

100
100
100
95

$
$
$
$

43
101
76
57

$
$
$
$

39
114
95
85

$
$
$
$

35
138
96
71

$
$
$
$

31
132
79
46

$
$
$
$

16
174
88
41

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

ITEM 6

SELECTED FINANCIAL DATA

The following table presents selected consolidated financial data that should be read in

conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 –
Financial Statements and Supplementary Data of this report.

Statements of Operations
Revenues
Net income (loss)
Net (loss) income attributable to common stock

Per common share

Basic
Diluted

Statements of Cash Flows
Net cash provided by operating activities
Capital investments
Acquisitions and other
Debt transactions, (decrease) increase in debt
Contributions from noncontrolling interest holders,

net

Distributions paid to noncontrolling interest

holders

Dividends per common share

2019

$ 2,634
99
$
(28)
$

Year Ended December 31,
2017

2018

2016

(in millions, except for per share data)
$ 1,547
$ 2,006
$ 3,064
279
$
(262)
$
429
$
279
$
(266)
$
328
$

2015

$ 2,403
$ (3,554)(a)
$ (3,554)(a)

$
$

$
$
$
$

$
$

(0.57)
(0.57)

676
(455)
(18)
(181)

$
$

$
$
$
$

6.77
6.77

$
$

(6.26)
(6.26)

461
$
$
(690)
(553)(b) $
$

(26)

248
(371)
(2)
(18)

796

$
$

$
$
$
$

6.76
6.76

$ (92.79)
$ (92.79)

130
$
$
(75)
— $
$
(73)

403
(401)
(151)
356

— $

—

(151)

$
— $

(121)

$
— $

(8)
$
— $

— $
— $

—
0.30

(a)
(b)

Includes asset impairments of $3.2 billion, net of $1.7 billion tax benefit.
Includes the acquisition of the remaining working, surface and mineral interests in the Elk Hills unit from Chevron U.S.A.,
Inc. For more information, see Part II, Item 8 Financial Statements and Supplementary Data, Note 4 Acquisitions and
Divestitures.

Balance Sheets
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
Deferred gain and issuance costs, net
Other long-term liabilities
Mezzanine equity
Equity attributable to common stock

2019

$
491
$ 6,352
$ 6,958
$
709
$ 4,877
146
$
720
$
802
$
(389)
$

As of December 31,
2017

2018

2016

2015

$
640
$ 6,455
$ 7,158
$
607
$ 5,251
216
$
575
$
756
$
(361)
$

(in millions)
$
483
$ 5,696
$ 6,207
$
732
$ 5,306
287
$
602
$
$
$

(814)

$
425
$ 5,885
$ 6,354
$
726
$ 5,168
397
$
620
$
— $
$

$
438
$ 6,312
$ 7,053
$
605
$ 6,043
491
$
830
$
—
— $
(916)
$

(557)

ITEM 7

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

We are an independent oil and natural gas exploration and production company operating

properties exclusively within California. We are incorporated in Delaware and became a publicly traded
company on December 1, 2014. 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.

The following discussion should be read in conjunction with the other sections of this 2019 10-K,
including Part I, Item 1A – Risk Factors and Part II, Item 8 – Financial Statements and Supplementary
Data.

Basis of Presentation and Certain Factors Affecting Comparability

All financial information presented consists of our consolidated results of operations, financial

position and cash flows unless otherwise indicated. The assets and liabilities in the consolidated
financial statements are presented on a historical cost basis. 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.

Production and Prices

The following table sets forth our average net production volumes of oil, NGLs and natural gas per

day for the years ended December 31, 2019, 2018 and 2017:

Oil (MBbl/d)

San Joaquin Basin
Los Angeles Basin
Ventura Basin

Total

NGLs (MBbl/d)

San Joaquin Basin
Ventura Basin

Total

Natural gas (MMcf/d)
San Joaquin Basin
Los Angeles Basin
Ventura Basin
Sacramento Basin

Total

Total Production (MBoe/d)(a)(b)

2019(a)

2018(a)

2017(a)

52
24
4

15
—

162
2
5
28

197

128

53
25
4

15
1

165
1
7
29

202

132

52
27
4

15
1

140
1
8
33

182

129

Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to

thousands of barrels of oil equivalent per day.

(a) Our acquisition of the remaining working interest in the Elk Hills unit added approximately 10 MBoe/d and 8 MBoe/d in
2019 and 2018, respectively. 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 2019. PSC-type contracts had no impact on our oil
production in 2019 compared to 2018. Our PSC-type contracts negatively impacted our oil production in 2018 by over 1
MBoe/d compared to 2017.

(b) Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic
feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

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 table sets forth average benchmark prices, average realized
prices and price realizations as a percentage of average benchmark prices for our products for the
years ended December 31, 2019, 2018 and 2017:

2019

2018

2017

Price

Realization

Price

Realization

Price

Realization

Oil ($ per Bbl)
Brent

Realized price without hedge
Settled hedges

Realized price with hedge

WTI
Realized price without hedge
Realized price with hedge

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

Natural gas
NYMEX ($/MMBTU)

Realized price without hedge

($/Mcf)

Settled hedges

Realized price with hedge ($/Mcf)

$ 64.18

$ 64.83
3.82

$ 68.65

$ 57.03
$ 64.83
$ 68.65

101%

$ 71.53

$ 70.11
(7.51)

98%

$ 54.82

$ 51.47
(0.23)

94%

107%

$ 62.60

88%

$ 51.24

93%

114%
120%

$ 64.77
$ 70.11
$ 62.60

108%
97%

$ 50.95
$ 51.47
$ 51.24

$ 31.71
$ 31.71

49%
56%

$ 43.67
$ 43.67

61%
67%

$ 35.76
$ 35.76

2.67

2.87
(0.01)

2.86

2.97

3.00
(0.02)

2.98

107%

$ 3.09

101%

$ 2.67
—

86%

100%

$ 2.67

86%

101%
101%

65%
70%

Note: We adopted a new revenue recognition standard on January 1, 2018 that required certain sales-related costs to be

reported as expense as opposed to being netted against revenue. The adoption of this standard did not affect net
income. Results for reporting periods beginning January 1, 2018 are presented under the new accounting standard
while prior periods are not adjusted and continue to be reported under accounting standards in effect for the applicable
period.

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

Joint Ventures

We have entered into a number of joint ventures that allow us to use outside sources of capital to
accelerate the development of our assets while providing us with operational and financial flexibility as
well as near-term production benefits.

Development Joint Ventures

Alpine JV

In July 2019, we entered into a development joint venture with Alpine Energy Capital, LLC (Alpine)

to develop portions of our Elk Hills field (Alpine JV). Alpine is a joint venture between subsidiaries of
Colony Capital, Inc. (Colony) and Equity Group Investments. Alpine committed to invest $320 million,
which may be increased to a total investment of $500 million, subject to the mutual agreement of the
parties. The initial commitment is expected to be invested over a period of up to three years in
accordance with a 275-well development plan. Alpine will fund 100% of the drilling and completion
costs of these wells, in which they will earn a 90% working interest. If Alpine receives an agreed upon
return, our working interest in those wells will increase from 10% to 82.5%. Our consolidated financial
statements reflect only our working interest share in the productive wells.

In connection with the Alpine JV, Colony received a warrant to purchase up to 1.25 million shares

of our common stock at an exercise price of $40 per share. Colony will be entitled to exercise the
warrant in tranches as funding milestones are achieved. The value of each tranche is recognized in our
consolidated balance sheets when a funding milestone begins. Each tranche has a five-year term
commencing on the date on which such tranche becomes exercisable. As of December 31, 2019,
200,000 shares of our common stock were exercisable under this warrant. Colony may elect, in its sole
discretion, to pay cash or to exercise the warrant on a cashless basis, pursuant to which Colony will
not be required to pay cash for shares of our common stock upon exercise of the warrant but will
instead receive fewer shares.

Royale JV

In October 2018, we entered into a three-year development joint venture for a 20-well program

with Royale Energy, Inc. (Royale) where Royale committed approximately $23 million, of which
$8 million has been funded to date. We committed to investing approximately $13 million, of which
$4 million has been funded to date. Our consolidated results reflect only our 40% working interest
share of production from these wells.

MIRA JV

In April 2017, we entered into a development joint venture with Macquarie Infrastructure and Real

Assets Inc. (MIRA) to develop certain of our oil and natural gas properties in exchange for a 90%
working interest in the related properties (MIRA JV). MIRA funded 100% of the drilling and completion
costs of agreed-upon wells in the drilling program. Our 10% working interest increases to 75% if MIRA
receives cash distributions equal to a predetermined threshold return. Of the initial $140 million agreed-
upon capital commitment, $138 million was funded through December 31, 2019. Our consolidated
results reflect only our working interest share in the productive wells.

BSP JV

In February 2017, we entered into a development joint venture with Benefit Street Partners (BSP)

where BSP cumulatively contributed $200 million over a period of approximately two years in exchange
for preferred interests in the BSP JV (BSP JV). BSP is entitled to preferential distributions and, if BSP
receives cash distributions equal to a predetermined threshold, the preferred interest is automatically
redeemed in full with no additional payment. The funds contributed by BSP were used to develop
certain of our oil and natural gas properties.

The BSP JV holds net profits interests (NPI) in existing and future cash flow from certain of our

properties and the proceeds from the NPI are used by the BSP JV to (1) pay quarterly minimum
distributions to BSP, (2) make additional distributions to BSP until the predetermined threshold is
achieved, and (3) pay for development costs within the project area, upon mutual agreement between
members. 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.

The following table summarizes the cumulative investment through December 31, 2019 by our

development joint venture partners, before transaction costs:

Alpine
Royale
MIRA
BSP

Total Capital

Midstream JV

Ares JV

Cumulative
Investment
through
December 31, 2019
(in millions)

134
8
138
200

480

In February 2018, we entered into a midstream joint venture with ECR Corporate Holdings L.P.
(ECR), a portfolio company of Ares Management L.P. (Ares). This joint venture (Ares JV) holds the Elk
Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/d cryogenic gas
processing plant. We hold 50% of the Class A common interest and 95.25% of the Class C common
interest in the Ares JV. ECR holds 50% of the Class A common interest, 100% of the Class B preferred
interest and 4.75% of the Class C common interest. We received $750 million in proceeds upon
entering into the Ares JV, before $3 million of transaction costs.

The Class A common and Class B preferred interests held by ECR are reported as redeemable

noncontrolling interests in mezzanine equity due to an embedded optional redemption feature. The
Class C common interest held by ECR is reported in equity on our consolidated balance sheets.

The Ares JV is required to make monthly distributions to the Class B holder. The Class B preferred
interest has a deferred payment feature whereby a portion of the monthly distributions may be deferred
for the first three years to the fourth and fifth year. The deferred amounts accrue an additional return.
Distributions to the Class B preferred interest holders are reported as a reduction to mezzanine equity
on our consolidated balance sheets. Monthly, the Ares JV is required to distribute its excess cash flow
over its working capital requirements to the Class C common interests on a pro-rata basis.

We can cause the Ares JV to redeem ECR’s Class A and Class B interests, in whole, but not in
part, at any time by paying $750 million for the Class B interest and $60 million for the Class A interest,
plus any previously accrued but unpaid preferred distributions and a make-whole payment if the
redemption happens prior to five years from inception. We have the option to extend the redemption
period for up to an additional two and one-half years, in which case the interests can be redeemed for
$750 million for the Class B interest and $80 million for the Class A interest, plus any previously
accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior
to seven and one-half years from inception. If we do not exercise a redemption at the end of the seven
and one-half year period, ECR can either sell its Class A and Class B interests or cause the sale or
lease of the Ares JV assets.

Our consolidated statements of operations reflect the full operations of our Ares JV, with ECR’s

share of net income reported in net income attributable to noncontrolling interests.

Additionally, in the first quarter of 2018, an Ares-led investor group purchased approximately
2.3 million shares of our common stock in a private placement for an aggregate purchase price of
$50 million.

Exploration JVs

Since 2016, we have entered into multiple exploration joint ventures that have allowed us to
successfully explore multiple, diverse conventional exploration prospects with industry-leading success
with minimal internally funded capital. In 2019, we drilled three exploration prospects with our partners
under these agreements.

We entered into additional exploration joint ventures in 2019 that generally provided for our

partners to invest in seismic and/or drilling activity across our assets on a promoted basis.

Acquisitions and Divestitures

Acquisitions

In April 2018, we acquired from Chevron U.S.A., Inc. (Chevron) its share of the remaining working,

surface and mineral interests in the approximately 47,000-acre Elk Hills unit (the Elk Hills transaction)
for approximately $518 million, including $7 million of liabilities assumed relating to asset retirement
obligations. We accounted for the Elk Hills transaction as a business combination and allocated
$435 million to proved properties, $77 million to other property, plant and equipment and $6 million to
materials and supplies. The consideration paid consisted of $460 million in cash and 2.85 million
shares of CRC common stock issued at the close of the transaction (valued at $51 million).

As part of the Elk Hills transaction, Chevron reduced its royalty interest in one of our oil and
natural gas properties by half and extended the time frame to invest the remainder of our capital
commitment on that property by two years, to the end of 2020. As of December 31, 2019, our
remaining commitment was approximately $12 million. In addition, the parties mutually agreed to
release each other from pending claims with respect to the former Elk Hills unit.

In April 2018, we acquired an office building and land in Bakersfield, California for $48 million. For
the initial eight months in 2018, a former owner of the building occupied most of the space as a tenant,
from which we generated approximately $4 million in rental income. In December 2018, this tenant
downsized the space they are leasing through December 2022, with a corresponding reduction in rent.
The vacated space not used by us will be available to lease to other tenants to generate additional
income. In addition, the unimproved land may be monetized in the future. Approximately $6 million of
the purchase price was allocated to the in-place leases, which is included in other assets and is being
amortized into other expenses, net.

Additionally, we had several other acquisitions totaling approximately $6 million in 2019 and

$39 million in 2018.

Divestitures

In May 2019, we sold 50% of our working interest and transferred operatorship in certain zones

within our Lost Hills field, located in the San Joaquin basin, for total consideration in excess of
$200 million, consisting of approximately $168 million and a carried 200-well development program to
be drilled through 2023 with an estimated value of $35 million (Lost Hills divestiture). We received cash
proceeds of $164 million after transaction costs and purchase price adjustments, which were used to
pay down our 2014 Revolving Credit Facility.

In 2018, we divested non-core assets resulting in $18 million of proceeds and a $5 million gain. In

2017, we divested non-core assets resulting in $33 million of proceeds and a $21 million gain.

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

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

did not record a significant income tax provision (benefit) in any of the years ended December 31,
2019, 2018 and 2017.

Our effective tax rate differs from the amounts computed by applying the U.S. federal statutory tax

rate to pre-tax income (loss) as follows:

For the years ended
December 31,
2018

2017

2019

U.S. federal statutory tax rate
State income taxes, net
Exclusion of tax attributable to noncontrolling interests, net
Decrease in U.S. federal corporate tax rate
Tax credits, net
Nondeductible compensation, net
Stock-based compensation, net
Change in valuation allowance, net
Other, net

Effective tax rate

21%
7
(35)
—
(9)
3
—
14
—

21%
6
(5)
—
(6)
—
—
(17)
1

—%

(35)%
(6)
—
91
(19)
—
1
(33)
1

—%

Our effective tax rate is primarily affected by state income taxes, income included in our
consolidated results which is taxed to noncontrolling interests and the benefit of income tax credits.
Our U.S. federal deferred tax assets and liabilities were remeasured due to the reduction of the top
corporate tax rate from 35% to 21% under the Tax Cuts and Jobs Act (TCJA) enacted on
December 22, 2017. The TCJA also included significant changes to the deduction for executive
compensation by public corporations. Given our income tax position, any item affecting our effective
tax rate described above is generally offset by an equal change in the valuation allowance.

Under the TCJA, for taxable years beginning in 2018, our deduction for business interest is limited

to 30% of our adjusted taxable income. For purposes of this limitation, adjusted taxable income is
computed without regard to net business interest expense and, in the case of taxable years beginning
before January 1, 2022, any deduction allowable for depreciation, amortization or depletion. Proposed
Treasury Regulations issued in December 2018 provide that depreciation, amortization or depletion
expense that is capitalized to inventory is not treated as depreciation, amortization or depletion for the
purposes of computing adjustable taxable income. It is reasonably possible that the composition of our
deferred tax assets, specifically the amount reported for net operating loss and business interest
expense carryforwards, could significantly change when the Internal Revenue Service finalizes and
issues regulations. Our carryforwards for business interest expense do not expire.

Management assesses the available positive and negative evidence to estimate whether sufficient

future taxable income will be generated to permit use of existing deferred tax assets. A significant
piece of evidence evaluated is a history of operating losses. Such evidence limits our ability to consider
other evidence such as projections for growth. As of December 31, 2019, we concluded that we could
not realize, on a more-likely-than-not basis, any of our deferred tax assets and there is not sufficient
evidence to support the reversal of all or any portion of this allowance. Given our recent and
anticipated future earnings trends, we do not believe any of the valuation allowance as of
December 31, 2019 will be released within the next 12 months. Changes in assumptions or changes in
tax laws and regulations could materially affect the recognized amounts of valuation allowance.

We paid approximately $1 million to California for alternative minimum taxes in 2019. We did not
make any United States federal and state income tax payments in 2018 or 2017. We do not expect to
make any significant income tax payments in the foreseeable future, although this estimate could
change.

For additional information on tax-related items, see information set forth in Part II, Item 8 –

Financial Statements and Supplementary Data, Note 10 Income Taxes.

Balance Sheet Analysis

Balance sheet components and changes in these components as of December 31, 2019 and

2018, are discussed below:

Cash
Trade receivables
Inventories
Other current assets, net
Property, plant and equipment, net
Other assets
Current maturities of long-term debt
Accounts payable
Accrued liabilities
Long-term debt
Deferred gain and issuance costs, net
Other long-term liabilities
Mezzanine equity
Equity attributable to common stock
Equity attributable to noncontrolling interests

2019

2018

(in millions)
17
277
67
130
6,352
115
100
296
313
4,877
146
720
802
(389)
93

$
$
$
$
$
$
$
$
$
$
$
$
$
$
$

17
299
69
255
6,455
63
—
390
217
5,251
216
575
756
(361)
114

$
$
$
$
$
$
$
$
$
$
$
$
$
$
$

Cash at December 31, 2019 and 2018 included $3 million and $2 million, respectively, that is
restricted under one of our joint venture agreements. See Liquidity and Capital Resources for our cash
flow analysis.

The decrease in trade receivables was largely driven by lower natural gas trading activity in
December 2019 as compared with December 2018, as well as a decline in production and natural gas
and NGL realized prices in the fourth quarter of 2019 compared to the fourth quarter of 2018. These
decreases were partially offset by higher realized oil prices in December 2019 compared to December
2018.

The decrease in other current assets, net primarily reflected a decrease in the fair value of the
current portion of our derivative assets, which primarily resulted from a lower percentage of our oil
production hedged between comparative periods.

The decrease in property, plant and equipment, net primarily resulted from depreciation, depletion

and amortization (DD&A) and the Lost Hills divestiture, partially offset by capital investments and
increases in our asset retirement obligations (ARO) resulting from idle well regulations enacted in the
first quarter of 2019.

The increase in other assets was primarily due to recording a long-term operating lease asset as a

result of accounting rules adopted on January 1, 2019 and prepaid power plant major maintenance,
partially offset by a decrease in the fair value of long-term derivative assets.

Current maturities of long-term debt reflected $100 million for our 5% senior notes due in January

2020, which were repaid in full upon maturity.

The decrease in accounts payable at December 31, 2019 compared to December 31, 2018
reflected the decrease in capital investments and gas-trading activities, which were lower in the fourth
quarter of 2019 compared to the fourth quarter of 2018.

The increase in accrued liabilities reflected the current portion of our operating lease liability
resulting from the adoption of new lease accounting rules, the timing of payments due to our joint
venture partners, severance costs related to our October 2019 organizational restructure and
increased obligation to purchase greenhouse gas allowances.

Long-term debt decreased due to repurchases of our Second Lien Notes, reclassification of

$100 million of our Senior Notes to current maturities of long-term debt, pay down of the 2014
Revolving Credit Facility from the proceeds of the Lost Hills divestiture and positive cash flow.

The decrease in deferred gain and issuance costs, net was largely the result of repurchases of our

Second Lien Notes and amortization.

Other long-term liabilities reflected the increase in ARO primarily due to idle well regulations

enacted in the first quarter of 2019, long-term operating lease liabilities due to the adoption of new
lease accounting rules and postretirement benefits primarily resulting from the October 2019
organizational restructure. The annual incremental cash expenditures for ARO resulting from the idle
well regulations and postretirement benefits resulting from the October 2019 organizational restructure
are not expected to be material in the foreseeable future.

Mezzanine equity reflected the carrying amount of the Class A common and Class B preferred

interests held by ECR in our midstream JV.

Equity attributable to common stock decreased as a result of a decrease in net income between
periods and an increase in the income allocated to ECR for a full 12 months in 2019 as compared to
nine months in the prior year.

Equity attributable to noncontrolling interests includes the Class C interest in the midstream joint

venture held by ECR and BSP’s preferred interest in the BSP JV. The decrease in 2019 primarily
related to distributions to the noncontrolling interest holders.

Statement of Operations Analysis

Results of Oil and Natural Gas Operations

The following represents key operating data for our oil and natural gas operations, excluding

corporate items, on a per Boe basis for the years ended December 31, 2019, 2018 and 2017:

Production costs
Production costs, excluding effects of PSC-type contracts(a)
Field general and administrative expenses(b)
Field depreciation, depletion and amortization
Field taxes other than on income

2019

2018

2017

$
$
$
$
$

19.16
17.70
1.20
9.40
2.59

$
$
$
$
$

18.88
17.47
1.01
9.71
2.42

$
$
$
$
$

18.64
17.48
0.70
10.85
2.34

(a) As described in Items 1 and 2 – Business and Properties – Operations – Production, Price and Cost History, the reporting
of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported
volumes, which are only our net share, inflating the per barrel production costs. These amounts represent our production
costs after adjusting for this difference.

(b) Field general and administrative expenses increased in 2019 compared to 2018, primarily due to the Elk Hills transaction
that occurred in April 2018 since certain costs are no longer recovered from our former working interest partner. Our 2019
costs include 12 months without such cost recovery compared to nine months without cost recovery in 2018.
Field general and administrative expenses also increased in 2018 compared to 2017 primarily due to the Elk Hills
transaction, with 2018 costs including nine months without cost recovery compared to 12 months of cost recovery in 2017.

Consolidated Results of Operations

The following represents key operating data for consolidated operations for the years ended

December 31, 2019, 2018 and 2017:

Oil and natural gas sales(a)
Net derivative (loss) gain from commodity contracts
Other revenue(a)
Production costs
General and administrative expenses(b)
Depreciation, depletion and amortization
Taxes other than on income
Exploration expense
Other expenses, net(a)
Interest and debt expense, net
Net gain on early extinguishment of debt
Gain on asset divestitures
Other non-operating expenses(b)

Income (loss) before income taxes

Income tax provision

Net income (loss)
Net income attributable to noncontrolling interests

Net (loss) income attributable to common stock

Adjusted net income (loss)(c)
Adjusted EBITDAX(c)
Effective tax rate

2019

$ 2,270
(59)
423
(895)
(290)
(471)
(157)
(29)
(363)
(383)
126
—
(72)

100
(1)

99
(127)

(28)

2018
(in millions)
$ 2,590
1
473
(912)
(299)
(502)
(149)
(34)
(399)
(379)
57
5
(23)

429
—

429
(101)

328

$
70
$ 1,142

$
61
$ 1,117

—%

2017

$ 1,936
(90)
160
(876)
(249)
(544)
(136)
(22)
(106)
(343)
4
21
(17)

(262)
—

(262)
(4)

(266)

(187)
779

—%

$
$

(a) We adopted the revenue recognition standard on January 1, 2018 that required certain sales-related costs to be

(b) New accounting rules related to the presentation of net periodic benefit costs for pension and postretirement benefits in
the Consolidated Statements of Operations were adopted on January 1, 2018. For the year ended December 31, 2017,
certain pension benefit costs of $10 million were reclassified from general and administrative expenses to other
non-operating expenses to conform with the new rules.

section below for a reconciliations to their nearest GAAP measures.

Year Ended December 31, 2019 vs. 2018

Oil and natural gas sales – Oil and natural gas sales, excluding the impact of settled hedges,
decreased 12%, or $320 million, in 2019 compared to 2018, due to changes in realized prices and
production as reflected in the following table:

Year ended December 31, 2018
Changes in realized prices
Changes in production

Year ended December 31, 2019

Oil

NGLs

Natural
Gas

Total

(in millions)

$ 2,110
(159)
(67)

$ 260
(71)
(10)

$ 220
(9)
(4)

$ 2,590
(239)
(81)

$ 1,884

$ 179

$ 207

$ 2,270

Note: See Production and Prices for average benchmark and realized prices, realizations and production.

The effect of settled hedges is not included in the table above. Proceeds from settled hedges were

$111 million for the year ended December 31, 2019 compared to payments of $228 million in 2018,
which had a positive impact of $339 million on our total revenue between years. Including the effect of
settled hedges, our oil and natural gas sales increased by $19 million or 1% compared to the same
period of 2018.

Net derivative (loss) gain from commodity contracts – Net derivative loss from commodity contracts

was $59 million for the year ended December 31, 2019 compared to a gain of $1 million in the same
period of 2018, representing an overall change of $60 million as reflected in the following table. The
non-cash changes in the fair value of our outstanding derivatives resulted from the positions held as well
as the relationship between contract prices and the associated forward curves at the end of each year.

Non-cash derivative (loss) gain, excluding noncontrolling interest
Non-cash derivative (loss) gain, noncontrolling interest

Total non-cash changes
Net proceeds (payments) on settled commodity derivatives

Net derivative (loss) gain from commodity contracts

Year ended
December 31,

2019

2018

(in millions)
(166) $
(4)

(170)
111

(59) $

224
5

229
(228)

Other revenue – Other revenue was $423 million for the year ended December 31, 2019 compared to
$473 million in the same period of 2018, representing a decrease of $50 million as reflected in the following
table. This decrease was largely the result of lower trading activity in 2019; however, the operating margin
before transportation charges in 2019 was $85 million compared to $80 million in 2018.

Trading
Electricity sales
Other

Total other revenue

Year ended
December 31,

2019

2018

(in millions)
286 $
112
25

423 $

330
111
32

473

Production costs – Production costs for the year ended December 31, 2019 decreased $17 million
to $895 million, compared to $912 million for the same period of 2018, resulting in a 2% decrease. The
decrease primarily related to cost savings resulting from our October 2019 organizational redesign and
less downhole maintenance activity in 2019 compared to the prior year.

General and administrative expenses – Our general and administrative expenses decreased
$9 million to $290 million for the year ended December 31, 2019 compared to the same period of 2018,
predominantly due to cost savings attributable to our October 2019 organizational redesign and lower
cash-settled stock-based compensation expense resulting from the approximately $8 decline in our
stock price at December 31, 2019 compared to December 31, 2018. See the Stock-Based
Compensation section below.

Other expenses, net – Other expenses, net was $363 million for the year ended December 31,
2019 compared to $399 million for the same period of 2018, representing a decrease of $36 million as
reflected in the following table. The decrease was largely the result of lower trading activity, partially
offset by higher Elk Hills Power costs and transportation costs.

Trading purchases
Elk Hills Power costs
Transportation costs
Other expenses

Total other expenses, net

Year ended
December 31,

2019

2018

(in millions)
201 $
68
40
54

363 $

250
61
36
52

399

Other non-operating expenses – Other non-operating expenses for the year ended December 31,

2019 increased $49 million to $72 million, compared to $23 million for the same period of 2018,
resulting in an approximately 200% increase. This increase was primarily due to the implementation of
fourth quarter 2019 operational efficiencies and an organizational redesign that reduced our workforce
to approximately 1,250 employees, which is slightly more than half the employees we had at the time
of our inception in 2014. We recorded a charge to other non-operating expenses of $41 million,
consisting of $29 million in salary and severance expense and $12 million for other termination
benefits.

Net income attributable to noncontrolling interests – The increase in net income attributable to
noncontrolling interests of $26 million reflected the additional net income (loss) allocated to ECR for the
full year of 2019 compared to 2018 starting in April, partially offset by the change in the fair value of
derivative instruments held by the BSP JV in 2019.

Stock-Based Compensation

Our consolidated results of operations for the years ended December 31, 2019 and 2018 include
the effects of long-term stock-based compensation plans under which awards are granted annually to
executives, non-executive employees and non-employee directors that are either settled with shares of
our common stock or cash. Our equity-settled awards granted to executives include stock options,
restricted stock units and performance stock units that either cliff vest at the end of a three-year period
or vest ratably over a three-year period, some of which are partially settled in cash. Our equity-settled
awards granted to non-employee directors are stock grants that vest immediately or restricted stock
units that cliff vest after one year. Our cash-settled awards granted to non-executive employees vest
ratably over a three-year period.

Changes in our stock price introduce volatility in our results of operations because we pay cash-

settled awards based on our stock price on the vesting date and accounting rules require that we
adjust our obligation for unvested awards to the amount that would be paid using our stock price at the
end of each reporting period. Cash-settled awards, including executive awards partially settled in cash,
account for almost 70% of our total outstanding awards. Equity-settled awards are not similarly
adjusted for changes in our stock price.

Our ending stock price for each of the quarters in 2019 and 2018 was as follows:

First quarter
Second quarter
Third quarter
Fourth quarter

2019

2018

$
$
$
$

25.71
19.68
10.20
9.03

$
$
$
$

17.15
45.44
48.53
17.04

Stock-based compensation is included in both G&A expenses and production costs as shown in

the table below (in millions, except per Boe amounts):

G&A expenses
Cash-settled awards
Equity-settled awards

Total stock-based compensation in G&A

Total stock-based compensation in G&A per Boe

Production costs
Cash-settled awards
Equity-settled awards

Total stock-based compensation in production costs

Total stock-based compensation in production costs per Boe

Total stock-based compensation

Total stock-based compensation per Boe

Year Ended December 31, 2018 vs. 2017

2019

2018

14 $
11

25 $

23
13

0.54 $

0.75

4 $
3

7 $

0.15 $

32 $

0.69 $

6
3

0.19

0.94

See Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of
Operations, Statement of Operations Analysis in our 2018 Form 10-K for our analysis of the changes in
our consolidated statements of operations for the year ended December 31, 2018 compared to
December 31, 2017.

Non-GAAP Financial Measures

Adjusted net income (loss) – Our results of operations, which are presented in accordance with
U.S. generally accepted accounting principles (GAAP), can include the effects of unusual, out-of-period
and infrequent transactions and events affecting earnings that vary widely and unpredictably (in
particular certain non-cash items such as derivative gains and losses) in nature, timing, amount and
frequency. Therefore, management uses a measure called adjusted net income (loss) that excludes
those items. This measure is not meant to disassociate these items from management’s performance
but rather is meant to provide useful information to investors interested in comparing our performance
between periods. Reported earnings are considered representative of management’s performance
over the long term. Adjusted net income (loss) is not considered to be an alternative to net income
(loss) reported in accordance with GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to

the non-GAAP financial measure of adjusted net income (loss) and presents the GAAP financial
measure of net income (loss) attributable to common stock per diluted share and the non-GAAP
financial measure of adjusted net income (loss) per diluted share:

Net income (loss)
Net income attributable to noncontrolling interests

Net (loss) income attributable to common stock
Unusual, infrequent and other items:

Non-cash derivative loss (gain) from commodities, excluding
noncontrolling interest
Non-cash derivative loss from interest-rate contracts
Severance and termination benefits
Net gain on early extinguishment of debt
Gain on asset divestitures
Other, net

Total unusual, infrequent and other items

Adjusted net income (loss)

2018
2017
2019
(in millions, except share data)
$ 429
(101)

99
(127)

$ (262)
(4)

(28)

328

(266)

166
4
47
(126)
—
7

(224)
6
4
(57)
(5)
9

(267)

78
—
5
(4)
(21)
21

$ (187)

Net (loss) income attributable to common stock per diluted share
Adjusted net income (loss) per diluted share

$ (0.57)
$ 1.40

$ 6.77
$ 1.27

$ (6.26)
$ (4.40)

Adjusted EBITDAX – We define Adjusted EBITDAX as earnings before interest expense; income

taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and
out-of-period items; and other non-cash items. We believe this measure provides useful information in
assessing our financial condition, results of operations and cash flows and is widely used by the
industry, the investment community and our lenders. Although this is a non-GAAP measure, the
amounts included in the calculation were computed in accordance with GAAP. Certain items excluded
from this non-GAAP measure are significant components in understanding and assessing our financial
performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable
and depletable assets. This measure should be read in conjunction with the information contained in
our financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX is a
material component of certain of our financial covenants under our 2014 Revolving Credit Facility and
is provided in addition to, and not as an alternative for, income and liquidity measures calculated in
accordance with GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to

the non-GAAP financial measure of Adjusted EBITDAX:

Net income (loss)

Interest and debt expense, net
Depreciation, depletion and amortization
Exploration expense
Unusual, infrequent and other items
Other non-cash items

2019

2018
(in millions)

2017

99 $

383
471
29
98
62

429 $
379
502
34
(267)
40

(262)
343
544
22
79
53

Adjusted EBITDAX

1,142 $

1,117 $

779

The following table sets forth a reconciliation of the GAAP measure of net cash provided by

operating activities to the non-GAAP financial measure of Adjusted EBITDAX:

2019

2018
(in millions)

2017

Net cash provided by operating activities

676 $
439
18
8
1

461 $
441
17
199
(1)

1,142 $

1,117 $

Cash interest
Exploration expenditures
Working capital changes
Other, net

Adjusted EBITDAX

Liquidity and Capital Resources

Cash Flow Analysis

Net cash provided by operating activities
Net cash used in investing activities:

Capital investments
Changes in capital investment accruals
Acquisitions, divestitures and other

Net cash (used) provided by financing activities:

$
$
$

Debt transactions
$
(Distributions) contributions with noncontrolling interest holders, net $
$
Issuance of common stock and other, net

2019

2018

(in millions)
676 $

(455) $
(85) $
146 $

(181) $
(102) $
1 $

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 increased 47%, or $215 million, to $676 million for the year ended December 31,
2019 from $461 million in the same period of 2018 primarily due to net proceeds on settled commodity
derivatives of $111 million in 2019 compared to payments of $228 million in 2018, which was partially
offset by a decrease in oil and gas revenue as a result of lower realized prices and production in 2019.

248
396
20
94
21

779

461

(690)
69
(535)

(26)
675
43

Changes in operating assets and liabilities increased our operating cash flow in 2019 by
$210 million compared to 2018, which was largely the result of purchasing more greenhouse gas
allowances in 2018. The increase was also attributable to a decrease in purchased hedges and the
timing of payments for capital investments.

Cash flows from investing activities – Our net cash used in investing activities of $394 million for

the year ended December 31, 2019 included $455 million of capital investments (excluding $85 million
in negative capital-related accrual changes), of which $48 million was funded by BSP. These uses of
cash were partially offset by $164 million in proceeds related to the Lost Hills divestiture.

Our net cash used in investing activities of $1,156 million for the year ended December 31, 2018

included $690 million of capital investments (excluding $69 million in positive capital-related accrual
changes), of which $49 million was funded by BSP, and $547 million of acquisition costs primarily
related to the Elk Hills transaction and a building in Bakersfield. These uses of cash were partially
offset by $18 million in proceeds from the sale of non-core assets.

The amounts in the table below reflect our capital investment, excluding changes in capital

investment accruals, for the years ended December 31, 2019 and 2018:

Oil and natural gas
Exploration
Corporate and other

Total internally funded capital

BSP-funded capital

Total capital

2019

2018

(in millions)
379 $
9
19

407
48

455 $

610
21
10

641
49

690

Cash flows from financing activities – Our net cash used in financing activities of $282 million for

the year ended December 31, 2019 primarily resulted from $156 million of debt repurchases on our
Second Lien Notes, $151 million of distributions to our noncontrolling interest holders and $23 million in
net payments on our 2014 Revolving Credit Facility, partially offset by $49 million in net contributions
from BSP.

For the year ended December 31, 2018, our net cash provided by financing activities of

$692 million primarily resulted from $796 million in net contributions from our noncontrolling interest
holders, $177 million in net borrowings on our 2014 Revolving Credit Facility and $54 million from the
issuance of common stock to an Ares-led investor group in connection with the Ares JV, partially offset
by $199 million used for debt repurchases on our Senior Notes and $121 million of distributions paid to
our noncontrolling interest holders.

Liquidity

Our primary sources of liquidity and capital resources are cash flows from operations and
available borrowing capacity under our 2014 Revolving Credit Facility. We also rely on other sources
such as joint ventures and non-core asset sales to supplement our capital program and fund other
corporate purposes. Our working capital requirements are primarily driven by the level of activity in our
business and debt service requirements. Our 2020 capital program will be dynamic and will be
adjusted based on realized price trends during the year.

As of December 31, 2019, we had available liquidity of $331 million, which consisted of $14 million

in unrestricted cash and $317 million of available borrowing capacity under our 2014 Revolving Credit
Facility (before a $150 million month-end minimum liquidity requirement). However, as of
December 31, 2019, we had approximately $4.9 billion of debt outstanding, a substantial portion of
which will mature in 2021. We have undertaken a variety of measures to reduce debt such as
repurchasing outstanding notes and selling non-core assets. We have also increased our margins by
reducing our workforce and consolidating our office space.

On February 20, 2020, we launched offers to exchange a significant portion of our Second Lien

Notes and senior notes into (1) notes and equity interests issued by a non-consolidated entity that will
hold a term royalty interest in our Elk Hills unit and/or (2) a new first-lien last-out Company term loan
and warrants convertible into our common stock. If fully subscribed, the transaction would have the
effect of reducing our net debt by almost $1 billion. The transaction is expected to close on March 20,
2020.

We are continuing to evaluate and consider a number of additional opportunities to delever,
including liability management transactions, monetization of royalty and other property interests and
other similar transactions. Such transactions, if any, will depend on prevailing market conditions,
contractual restrictions and other factors. Our ability to pay the principal and interest on our long-term
debt and to satisfy our other liabilities will depend upon oil and natural gas prices, the success of our
development activities, our success with respect to our deleveraging efforts and our ability to refinance
our debt as it becomes due. Our future operating performance and ability to refinance will be affected
by the results of our operations, economic and capital market conditions, oil and natural gas prices and
other factors, many of which are beyond our control. See “We have significant indebtedness that could
limit our financial and operating flexibility and make us more vulnerable in economic downturns,” “Our
lenders require us to comply with covenants that limit our borrowing capabilities and could restrict our
ability to use or access capital” and “A significant portion of our long-term indebtedness will mature
within two years and will likely need to be refinanced. There can be no assurances we will be able to
refinance this indebtedness on acceptable terms or at all.” in Part I, Item 1A – Risk Factors for
additional information about our indebtedness and restrictions on our use of and access to capital.

We believe that our operating cash flows and availability under our 2014 Revolving Credit Facility

will be sufficient to meet our obligations and working capital requirements for the next 12 months.

Debt

As of December 31, 2019, our long-term debt consisted of the following credit agreements, second

lien notes and senior notes:

Credit Agreements

Outstanding
Principal
(in millions)

2014 Revolving Credit Facility

518

2017 Credit Agreement

1,300

Interest Rate(a)

Maturity

Security

LIBOR plus
3.25%-4.00%
ABR plus
2.25%-3.00%
LIBOR plus 4.75%
ABR plus 3.75% December 31, 2022(b) Shared First-Priority Lien

Shared First-Priority Lien

June 30, 2021

2016 Credit Agreement

1,000

ABR plus 9.375% December 31, 2021

First-Priority Lien

LIBOR plus
10.375%

Second Lien Notes
Second Lien Notes

Senior Notes

1,815

December 15, 2022(c)

Second-Priority Lien

5% Senior Notes due 2020
5 1⁄ 2% Senior Notes due 2021
6% Senior Notes due 2024

Total

Less: Current Maturities

Long-Term Debt

100
100
144

4,977

(100)

4,877

5%
5.5%
6%

January 15, 2020
September 15, 2021
November 15, 2024

Unsecured
Unsecured
Unsecured

(a) London Interbank Offered Rates (LIBOR) will be phased out after 2021 and replaced with the Secured Overnight
Financing Rate within the United States for U.S. dollar-based LIBOR. Our credit agreements contemplate a
discontinuation of LIBOR and have an alternate borrowing rate. We do not expect the discontinuation of LIBOR to have a
significant impact on our carrying charges.

(b) The 2017 Credit Agreement is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit
Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.

(c) The Second Lien Notes require principal repayments of approximately $287 million in June 2021, $57 million in December

2021 and $59 million in June 2022 and $1,412 million in December 2022.

As of December 31, 2019, we had approximately $317 million of available borrowing capacity,
subject to a $150 million month-end minimum liquidity requirement. Our 2014 Revolving Credit Facility
also includes a sub-limit of $400 million for the issuance of letters of credit. As of December 31, 2019
and 2018, we had letters of credit of approximately $165 million and $162 million, respectively. These
letters of credit were issued to support ordinary course marketing, insurance, regulatory and other
matters.

For additional information on long-term debt, see information set forth in Part II, Item 8 – Financial

Statements and Supplementary Data, Note 6 Debt.

Derivatives

Commodity Contracts

Our strategy for protecting our cash flow, operating margin and capital program, while maintaining

adequate liquidity, also includes our hedging program. We did not have any commodity derivatives
designated as accounting hedges as of and during the year ended December 31, 2019. We currently
have the following Brent-based crude oil contracts, as of February 26, 2020:

Purchased Puts:
Barrels per day
Weighted-average price per barrel

Sold Puts:

Barrels per day
Weighted-average price per barrel

Swaps:

Barrels per day
Weighted-average price per barrel

Q1
2020

Q2
2020

Q3
2020

Q4
2020

30,000
$ 70.83

30,000
$ 56.67

20,000
67.50

20,000
53.75

—
— $

5,000
70.05

13,000
65.00

18,000
54.31

5,000
65.00

8,000
65.00

13,000
53.81

5,000
65.00

Our counterparties have an option to increase volumes by up to 5,000 barrels per day for the
second quarter of 2020 at a weighted-average Brent price of $70.05. A counterparty has an option to
increase volumes by up to 5,000 barrels per day for the second half of 2020 at a weighted-average
Brent price of $65.00.

The BSP JV entered into crude oil derivatives for insignificant volumes through 2021 that are
included in our consolidated results but not in the above table. The BSP JV also entered into natural
gas swaps for insignificant volumes for periods through May 2021. The hedges entered into by the
BSP JV could affect the timing of the reversion of BSP’s preferred interest.

Interest-Rate Contracts

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.

Capital Program

We seek to create value by investing our operating cash flow back into our business. We respond
to economic conditions by adjusting the amount and allocation of our capital program while continuing
to identify efficiencies and cost savings.

We focus our capital program on oil projects that provide high margins and low decline rates. We

believe investing in these projects will generate positive cash flow allowing us to fund future capital
programs and grow production over the longer term. Our low decline rates compared to our industry
peers together with our high level of operational control give us the flexibility to adjust the level of our
capital investments as circumstances warrant.

We develop our capital program by prioritizing life-of-project returns to grow our net asset value
over the long term, while balancing the short- and long-term growth potential of each of our assets. We
use a Value Creation Index (VCI) metric for project selection and capital allocation across our asset
portfolio. We calculate the VCI for each of our projects by dividing the net present value of the project’s
expected pre-tax cash flow over its life by the net present value of the investments, each using a 10%
discount rate. Projects included in our capital program are expected to meet a VCI of 1.3, meaning that
30% of expected value is created above our cost of capital for every dollar invested over the life of the
project.

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. As a result, we expect many projects that do not currently meet our VCI
threshold today will do so by the time of development. 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.

Actions we have taken to streamline our business and reduce costs enable us to invest in our
business to support production. In addition, we will continue to build our inventory of available projects,
which we believe will position us to accelerate value by utilizing JV capital and take advantage of
potential future commodity price increases.

2019 Capital Program

Sources of our 2019 capital program were as follows:

Internally funded capital
BSP-funded capital

Capital investment included in our financial statements

MIRA-funded capital
Alpine-funded capital

Total capital investment

2019
(in millions)
$

407
48

455
23
134

612

Our capital program targeted oil-weighted projects in the San Joaquin and Los Angeles basins.

The table below sets forth our total 2019 capital program:

Conventional

Unconventional

Primary Waterflood

Steamflood

Total
(in millions)

Primary

Other

Total Capital
Investments

Basin:

San Joaquin
Los Angeles
Ventura
Sacramento
Exploration and
other

Capital included in
our financial
statements
MIRA-funded capital
Alpine-funded capital

32 $
—
10
11

—

53
23
1

Total

77 $

72
93
4
—

—

169
—
—

169

40 $
—
—
—

144 $
93
14
11

—

40
—
57

—

262
23
58

162 $
—
—
—

— $
—
—
—

—

162
—
76

31
—
—

97 $

343 $

238 $

31 $

306
93
14
11

455
23
134

612

The table below sets forth our capital investments by activity type for the year ended

December 31, 2019:

Drilling

Workovers

Facilities

Exploration

Other

Total
Capital

Internally funded
BSP

249 $
45

53 $
—

(in millions)
77 $
—

9 $
3 $

19 $
— $

Capital investments
included in our
financial statements
MIRA-funded capital
Alpine-funded capital

294
23
134

53
—
—

77
—
—

Total

451 $

53 $

77 $

12 $
— $
— $

12 $

19 $
— $
— $

19 $

407
48

455
23
134

612

2020 Capital Program

We entered 2020 with an internally funded capital program of $100 million to $300 million, which
may be adjusted during the course of the year depending on commodity prices. Additionally, existing
JV partners will increase our capital program by approximately $160 million to $200 million for a
program total of $260 million to $500 million. We are currently operating seven drilling rigs funded by
JV capital and one internally funded drilling rig.

We are focusing our 2020 capital on short payout projects like capital workovers, especially in the

first half of the year, as well as primary drilling of vertical and lateral wells and low-risk projects
including waterflood and steamflood investments that maintain base production. Early in the year, our
capital will be mostly focused on high-VCI short-payout workovers in addition to safety and
maintenance-related projects. We may add more drilling projects as the year progresses depending on
the overall commodity price environment. Our approach to our 2020 drilling and overall capital program
is consistent with our stated strategy to remain financially disciplined and fund projects through either
internally generated cash flow or JV capital. We will continue to deploy our partners’ capital as part of
our Alpine joint venture and opportunistically pursue additional strategic relationships. We will deploy
capital to projects that help continue to stabilize our production, develop our long-term resources and
return our production to a growth profile. Our current drilling inventory comprises a diversified portfolio
of oil and natural gas locations that are economically viable in a variety of operating and commodity
price conditions.

We will continue to focus our internally funded capital program on our core areas: Elk Hills,

Wilmington, Huntington Beach, Buena Vista, Mount Poso and other appraisal long-term prospects. Our
Alpine JV is focused exclusively on Elk Hills.

We plan to invest approximately 40% of our internally funded 2020 capital program in capital
workovers of existing well bores. Capital workovers in Elk Hills and other fields are some of the highest
VCI projects in our portfolio and generally include well deepenings, recompletions, changes in lift
methods and other activities designed to add incremental productive intervals and reserves.

We plan to invest approximately 35% of our capital on the development of conventional and

unconventional projects. The depth of our conventional wells is expected to range from 2,000 to 12,000
feet. Our conventional program includes wells located primarily in the Los Angeles basin, Mount Poso
and other appraisal long-term prospects primarily focused on waterflood and primary drilling. We also
intend to drill unconventional wells mainly in the Buena Vista area. With continued focus on cost
savings and efficiencies, many of our deep conventional and unconventional wells have become more
competitive.

Further, approximately 20% of our 2020 capital program is intended for facilities development for
our newer projects, including pipeline and gathering line interconnections, gas compression and water
management systems, and for mechanical integrity and health, safety and environmental projects.
About 5% is intended to be used for exploration and other corporate uses.

Efficiency gains in our capital costs have enabled us to maintain a robust capital program even in
a low commodity price environment. We will continue to build our inventory of available projects, which
will position us to accelerate value by utilizing third-party capital and take advantage of potential future
commodity price increases.

Off-Balance-Sheet Arrangements

We have no off-balance-sheet arrangements other than the purchase obligations described in the

Contractual Obligations section below.

Contractual Obligations

The table below summarizes and cross-references our contractual obligations as of December 31,

2019. This summary indicates on- and off-balance-sheet obligations as of December 31, 2019.

Payments Due by Year

Total

Less than
1 Year

1-3 Years
(in millions)

3-5 Years

More than
5 Years

—
—
489
134
23
—

668

On-Balance Sheet
Long-term debt(a)
Interest on long-term debt(b)
Asset retirement obligations(c)
Pension and postretirement
Operating and finance leases(d)
Other long-term liabilities

Off-Balance Sheet

Purchase obligations(e)

4,977
988
517
183
92
6

153

100
398
28
13
33
2

4,733
573
—
18
21
4

144
17
—
18
15
—

Total

6,916

662

5,373

213

(a)

In performing the calculation, the 2014 Revolving Credit Facility borrowings outstanding at December 31, 2019 of
$518 million were assumed to be outstanding for the entire term of the agreement. See Part II, Item 8 – Financial
Statements and Supplementary Data, Note 6 Debt for more information.

(b) The calculation of cash interest payments on our variable interest-rate debt assumes the interest rate at December 31,

2019 will continue for the entire term and no settlement payments will be received under our interest-rate cap
agreements.

asset retirement obligations by year as we are not able to precisely predict the timing of these amounts. Because these
costs typically extend many years into the future, estimating these future costs requires management to make estimates
and judgments that are subject to revisions based on numerous factors, including the rate of inflation, changing
technology, and changes to federal, state and local laws and regulations. See Part II, Item 8 – Financial Statements and
Supplementary Data, Note 1 Nature of Business, Summary of Significant Accounting Policies and Other for more
information.

(d) 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.

(e) 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 easements. Purchase obligations for
pipeline capacity are based on contractual volumes and our internal estimate of future prices during the contract period.
Land easements include obligations for fixed payments under our term contracts, and those held by production cannot
be reliably estimated.

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, 2019 and 2018 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 would
not be material to our consolidated financial position or results of operations.

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 8 Lawsuits, Claims,

Commitments and Contingencies.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates include property, plant and equipment and fair value
measurements. See Part II, Item 8 – Financial Statements and Supplementary Data, Note 1 Nature of
Business, Summary of Significant Accounting Policies and Other for details on these 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.

Significant Accounting and Disclosure Changes

See Part II, Item 8 – Financial Statements and Supplementary Data, Note 2 Accounting and

Disclosure Changes for a discussion of new accounting standards.

FORWARD-LOOKING STATEMENTS

The information included herein contains forward-looking statements that involve risks and
uncertainties that could materially affect our expected results of operations, liquidity, cash flows and
business prospects. Such statements include those regarding our expectations as to our future:

(cid:129)

(cid:129)
(cid:129)
(cid:129)
(cid:129)

financial position, liquidity, cash flows
and results of operations
business prospects
transactions and projects
operating costs
Value Creation Index (VCI) metrics,
which are based on certain estimates
including future production rates, costs
and commodity prices

(cid:129)

(cid:129)
(cid:129)
(cid:129)

operations and operational results
including production, hedging and
capital investment
budgets and maintenance capital
requirements
reserves
type curves
expected synergies from acquisitions
and joint ventures

Actual results may differ from anticipated results, sometimes materially, and reported results
should not be considered an indication of future performance. While we believe assumptions or bases
underlying our expectations are reasonable and make them in good faith, they almost always vary from
actual results, sometimes materially. We also believe third-party statements we cite are accurate but
have not independently verified them and do not warrant their accuracy or completeness. Factors (but
not necessarily all the factors) that could cause results to differ include:

(cid:129)
(cid:129)

(cid:129)

commodity price changes
debt limitations on our financial
flexibility
insufficient cash flow to fund planned
investments, debt repurchases or
changes to our capital plan
inability to enter desirable transactions
including acquisitions, asset sales and
joint ventures
legislative or regulatory changes,
including those related to drilling,
completion, well stimulation, operation,
inspection, maintenance or
abandonment of wells or facilities,
managing energy, water, land,
greenhouse gases or other emissions,
protection of health, safety and the
environment, or transportation,
marketing and sale of our products
joint ventures and acquisitions and our
ability to achieve expected synergies
the recoverability of resources and
unexpected geologic conditions
incorrect estimates of reserves and
related future cash flows and the
inability to replace reserves
changes in business strategy

(cid:129)

(cid:129)
(cid:129)

(cid:129)

PSC effects on production and unit
production costs
effect of stock price on costs
associated with incentive compensation
insufficient capital or liquidity, including
as a result of lender restrictions,
unavailability of capital markets or
inability to attract potential investors
effects of hedging transactions
equipment, service or labor price
inflation or unavailability
availability or timing of, or conditions
imposed on, permits and approvals
lower-than-expected production,
reserves or resources from
development projects, joint ventures or
acquisitions, or higher-than-expected
decline rates
disruptions due to accidents,
mechanical failures, power outages,
transportation or storage constraints,
natural disasters, pandemics, labor
difficulties, cyber attacks or other
catastrophic events
factors discussed in Part I, Item 1A –
Risk Factors.

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, whether as
a result of new information, future events or otherwise, except as required by applicable law.

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. In 2020, we

expect that price changes at current levels of production, excluding the impact of existing hedges
discussed below, would affect our pre-tax annual income and cash flows as follows:

Pre-tax 2020 Price Sensitivities
$1 change in Brent index – Oil(a)
$1 change in Brent index – NGLs
$0.10 change in NYMEX – Natural gas(b)

(in millions)

23.0
2.9
2.6

$
$
$

(a) Assumes no hedges.
(b) Amount reflects the sensitivity with respect to unhedged volumes and includes the offsetting effect of gas used in our

operations.

Due to our income tax position, there is no difference between the impact on our income and cash

flows. These price-change sensitivities include the impact on income of volume changes under
PSC-type contracts. If production and price levels change in the future, the sensitivity of our results to
prices also will change.

As of December 31, 2019, we had net assets of $35 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. A 10% increase or decrease in the fair value of our net
derivative assets would affect pre-tax earnings by approximately $4 million. See additional hedging
information in Part II, Item 7 – Management’s Discussion and Analysis of Financial Condition and
Results of Operations, Liquidity and Capital Resources.

Our current oil hedge positions provide for the following expected outcomes:

Q1
2020

Q2
2020

Q3
2020

Q4
2020

Barrels per day

30,000
Receive Brent if
Brent > $71
Receive $71
if Brent between
$57 and $71
Receive Brent +
$14
if Brent < $57

20,000
Receive Brent if
Brent > $68
Receive $68
if Brent between
$54 and $68
Receive Brent +
$14
if Brent < $54
5,000 (a)

Receive $70
Brent
at all prices

13,000
Receive Brent if
Brent > $65
Receive $65
if Brent between
$54 and $65
Receive Brent +
$11
if Brent < $54
5,000 (b)
Receive $65
Brent at all prices
except when
Brent < $55 then
receive Brent +
$10

8,000
Receive Brent if
Brent > $65
Receive $65
if Brent between
$53 and $65
Receive Brent +
$12
if Brent < $53
5,000 (b)
Receive $65
Brent at all prices
except when
Brent < $55 then
receive Brent +
$10

(a) Our counterparties have the option to increase volumes by up to an additional 5,000 barrels per day at the same price at a

weighted-average Brent price of $70.05

(b) A counterparty has the option to increase volumes by up to an additional 5,000 barrels per day at a weighted-average

Brent price of $65.

Counterparty Credit Risk

Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit

exposure for each customer is monitored for outstanding balances and current activity. For derivative
instruments entered into as part of our hedging program, we are subject to counterparty credit risk to
the extent the counterparty is unable to meet its settlement commitments. We actively manage this
credit risk by selecting counterparties that we believe to be financially strong and continue to monitor
their financial health. Concentration of credit risk is regularly reviewed to ensure that counterparty
credit risk is adequately diversified.

As of December 31, 2019, the substantial majority of the credit exposure related to our derivative
financial instruments was with investment grade counterparties. We believe exposure to credit-related
losses at December 31, 2019 was not material and losses associated with credit risk have been
insignificant for all years presented.

Interest-Rate Risk

As of December 31, 2019, we had borrowings of $1.3 billion outstanding under our 2017 Credit

Agreement, $1 billion outstanding under our 2016 Credit Agreement and $518 million outstanding
under our 2014 Revolving Credit Facility, all of which carry variable interest rates. A one-eighth percent
change in the interest rates on these outstanding borrowings under these facilities would result in an
approximately $4 million change in annual interest expense assuming no payments are received under
our interest-rate cap agreements described below.

As of December 31, 2019, we had interest-rate caps that limit our interest rate exposure with
respect to $1.3 billion of our variable-rate indebtedness. The 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. We have not received any
settlement payments under our interest-rate contracts.

The following table shows the face value and fair value of our fixed- and variable-rate debt as of

December 31, 2019:

Year of Maturity

2020
2021
2022(a)
2023
2024

Total

Weighted-average interest rate

Fair value

U.S. Dollar
Fixed-Rate
Debt

U.S. Dollar
Variable-
Rate Debt

(in millions)

100
444
1,471
—
144

2,159

7.61%

1,017

—
1,518
1,300
—
—

2,818

8.44%

2,818

Total

100
1,962
2,771
—
144

4,977

8.08%

3,835

(a) The $1.3 billion U.S. dollar variable-rate debt is subject to a springing maturity of 91 days prior to the maturity of our 2016

Credit Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.

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, 2019 and 2018, the related consolidated
statements of operations, comprehensive income, equity, and cash flows for each of the years in the
three-year period ended December 31, 2019, and the related notes (collectively, the consolidated
financial statements). We also have audited the Company’s internal control over financial reporting as
of December 31, 2019, based on criteria established in Internal Control – Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the consolidated financial statements referred to above present fairly, in all material
respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of
its operations and its cash flows for each of the years in the three-year period ended December 31,
2019, in conformity with U.S. generally accepted accounting principles (GAAP). Also in our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2019, based on criteria established in Internal Control – Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Change in Accounting Principle

As discussed in Notes 2 and 7 to the consolidated financial statements, the Company has changed its
method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards
Codification Topic 842, Leases.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, for
maintaining effective internal control over financial reporting, and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management’s
Annual Assessment of and Report on Internal Control Over Financial Reporting. Our responsibility is to
express an opinion on the Company’s consolidated financial statements and an opinion on the
Company’s internal control over financial reporting based on our audits. We are a public accounting
firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are
required to be independent with respect to the Company in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require
that we plan and perform the audits to obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement, whether due to error or fraud, and whether
effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks
of material misstatement of the consolidated financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test
basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our
audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements.
Our audit of internal control over financial reporting included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the
risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the
consolidated financial statements that were communicated or required to be communicated to the audit
committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial
statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matters
below, providing separate opinions on the critical audit matters or on the accounts or disclosures to
which they relate.

Assessment 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,
capitalized costs of producing oil and gas properties, along with support equipment and facilities,
are amortized based on proved oil, and gas reserves. For the year ended December 31, 2019, the
Company recorded depreciation, depletion and amortization expense of $471 million. Estimating
proved oil and gas reserves requires the expertise of professional petroleum reservoir engineers,
who take into consideration forecasted production, operating and capital cost assumptions, and
commodity prices inclusive of market differentials. The Company’s internal technical personnel,
such as reservoir engineers and geoscientists, estimate proved oil, NGLs, and natural gas
reserves. The Company engages independent reservoir engineering specialists to perform an
independent evaluation of a portion of the Company’s proved oil and gas reserve estimates.

We identified the assessment of estimated oil and gas reserves on depletion expense for proved
oil and gas properties as a critical audit matter. Complex auditor judgment was required in
evaluating the Company’s estimate of proved oil and gas reserves, which is an input to the
determination of depletion expense. Specifically, auditor judgment was required to evaluate the
assumptions used by the Company related to forecasted production and operating and capital
costs.

The primary procedures we performed to address this critical audit matter included the following.
We tested certain internal controls over the Company’s depletion process, including controls over
the estimation of proved oil and gas reserves. We evaluated the competence, capabilities, and
objectivity of the internal technical personnel who estimated the proved oil and gas reserves and
the independent reservoir engineering specialists engaged by the Company. We analyzed and
assessed the determination of depletion expense for compliance with industry and regulatory
standards. We assessed the methodology used by the Company’s internal technical personnel to
estimate proved oil and gas reserves and the methodology used by the independent reservoir
engineering specialists to evaluate those reserve estimates for compliance with industry and
regulatory standards. We compared the forecasted production assumptions used by the
Company’s internal technical personnel to historical production rates. We evaluated the operating
and capital cost assumptions used by the Company’s internal technical personnel by comparing
them to historical costs. We compared the commodity prices used by the Company’s internal
technical personnel to publicly available prices and tested the relevant market differentials. We
read and considered the reports of the independent reservoir engineering specialists in connection
with our evaluation of the Company’s reserves estimates.

Assessment of impairment triggering events for proved oil and gas properties

As discussed in Note 1 to the consolidated financial statements, the Company periodically
assesses their proved oil and gas properties for triggering events that could indicate impairment. If
a triggering event is identified, an undiscounted cash flows analysis would be required to
determine the recoverability of those oil and gas properties. The Company analyzes indicators for
possible triggers of impairment such as significant other than temporary decreases in commodity
prices, significant increases in expected operating and development costs, significant declines in
reserves estimates, or significant adverse changes in the legislative or regulatory environments in
which the company operates.

We identified the assessment of impairment triggering events for proved oil and gas properties as
a critical audit matter. Specifically, complex auditor judgment was required in evaluating the
Company’s identification of triggering events for proved oil and gas properties due to the
uncertainty associated with future commodity prices, estimated oil and gas reserves, and
operating and development costs.

The primary procedures we performed to address this critical audit matter included the following.
We tested certain internal controls over the Company’s assessment of indicators for possible
triggers of impairment, including controls over the evaluation commodity prices, estimated oil and
gas reserves, and capital and operating and development costs. We assessed the changes in
commodity prices period over period in consideration of the estimated future commodity prices
and tested the relevant market differentials. We compared estimated future commodity prices
used in the Company’s assessment to publicly available market information. We analyzed the
historical operating margins of those oil and gas properties by comparing period over period
results. We evaluated the competence, capabilities, and objectivity of the internal technical
personnel who estimated the oil and gas reserves and the independent reservoir engineering
specialists engaged by the Company. We evaluated the Company’s assessment of the indicators
for possible triggers of impairment related to estimated oil and gas reserves by comparing the
Company’s forecasted production, operating and development cost assumptions to historical
amounts. In addition, to evaluate the Company’s assessment of indicators for possible triggers of
impairment, we considered evidence that might be contrary to assumptions used by the Company,
including changes in the legislative and regulatory environments, publicly available information,
and other relevant information.

/s/ KPMG LLP

We have served as the Company’s auditor since 2014.

Los Angeles, California
February 26, 2020

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2019 and 2018
(in millions, except share data)

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

TOTAL ASSETS

CURRENT LIABILITIES

Current maturities of long-term debt
Accounts payable
Accrued liabilities

Total current liabilities

LONG-TERM DEBT
DEFERRED GAIN AND ISSUANCE COSTS, NET
OTHER LONG-TERM LIABILITIES
MEZZANINE EQUITY

Redeemable noncontrolling interests

EQUITY

2019

2018

17 $

277
67
130

491
22,889
(16,537)

6,352
115

6,958 $

100
296
313

709
4,877
146
720

802

17
299
69
255

640
22,523
(16,068)

6,455
63

7,158

—
390
217

607
5,251
216
575

756

Preferred stock (20 million shares authorized at $0.01 par value);
no shares outstanding at December 31, 2019 or 2018
Common stock (200 million shares authorized at $0.01 par
value); 49,175,843 shares outstanding at December 31, 2019,
48,650,420 shares outstanding at December 31, 2018
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss

Total equity attributable to common stock

Noncontrolling interests

Total equity

—

—
5,004
(5,370)
(23)

(389)
93

(296)

—
4,987
(5,342)
(6)

(361)
114

(247)

TOTAL LIABILITIES AND EQUITY

6,958 $

7,158

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Operations
For the years ended December 31, 2019, 2018 and 2017
(in millions, except per share data)

2019

2018

2017

2,270 $ 2,590 $ 1,936
(90)
160

(59)
423

1
473

2,634

3,064

2,006

895
290
471
157
29
363

912
299
502
149
34
399

876
249
544
136
22
106

2,205

2,295

1,933

429

769

(383)
126
—
(72)

100
(1)

(117)
(10)

(127)

(379)
57
5
(23)

429
—

429

(99)
(2)

(101)

(343)
4
21
(17)

(262)
—

(262)

—
(4)

(4)

(28) $

328 $

(266)

(0.57) $
(0.57) $

6.77 $
6.77 $

(6.26)
(6.26)

REVENUES

Oil and natural gas sales
Net derivative (loss) gain from commodity contracts
Other revenue

Total revenues

COSTS

Production costs
General and administrative expenses
Depreciation, depletion and amortization
Taxes other than on income
Exploration expense
Other expenses, net

Total costs

OPERATING INCOME

NON-OPERATING (LOSS) INCOME

Interest and debt expense, net
Net gain on early extinguishment of debt
Gain on asset divestitures
Other non-operating expenses

INCOME (LOSS) BEFORE INCOME TAXES
Income tax provision

NET INCOME (LOSS)

NET INCOME ATTRIBUTABLE TO NONCONTROLLING

INTERESTS
Mezzanine equity
Equity

Net income attributable to noncontrolling interests

NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK

Net (loss) income attributable to common stock per share
Basic
Diluted

$
$

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income
For the years ended December 31, 2019, 2018 and 2017
(in millions)

Net income (loss)
Net income attributable to noncontrolling interests
Other comprehensive income (loss) items:

Reclassification of unrealized gains (losses) on pension and

postretirement losses(a)

Reclassification of realized losses on pension and

postretirement to income(a)

Total other comprehensive income (loss)

2019

2018

2017

99 $

(127)

429 $
(101)

(262)
(4)

(24)

(17)

(14)

(9)

Comprehensive (loss) income attributable to common stock

(45) $

345 $

(275)

(a) No associated tax for 2019, 2018 and 2017. See Part II, Item 8 Financial Statements and Supplementary Data, Note 14

Pension and Postretirement Benefit Plans for additional information.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Equity
For the years ended December 31, 2019, 2018 and 2017
(in millions)

Additional
Paid-in
Capital

Accumulated
(Deficit)
Earnings

Accumulated
Other
Comprehensive
(Loss) Income

Equity
Attributable to
Common Stock

Equity
Attributable to
Noncontrolling
Interests

Total
Equity

Balance, December 31, 2016

Net (loss) income
Contribution from noncontrolling

interest holders, net

Distributions paid to

noncontrolling interest holders

Other comprehensive loss
Share-based compensation, net

Balance, December 31, 2017

Net income
Contribution from noncontrolling

interest holders, net

Distributions paid to

noncontrolling interest holders

Issuance of common stock(a)
Other comprehensive income
Share-based compensation, net

Balance, December 31, 2018

Net income
Contribution from noncontrolling

interest holders, net

Distributions paid to

noncontrolling interest holders

Other comprehensive income
Warrant
Share-based compensation, net

4,861
—

(5,404) $
(266)

(14) $
—

(557) $
(266)

— $
4

(557)
(262)

—

—
—
18

—

—
—
—

—

—
(9)
—

—

—
(9)
18

4,879
—

(5,670) $
328

(23) $
—

(814) $
328

—

—
101
—
7

—

—
—
—
—

—

—
—
17
—

—

—
101
17
7

4,987
—

(5,342) $
(28)

(6) $
—

(361) $
(28)

—

—
—
3
14

—

—
—

—

—
(17)

—

—
(17)
3
14

(8)
—
—

94 $

(64)
—
—
—

114 $

(80)
—

—

(8)
(9)
18

(720)
330

(64)
101
17
7

(247)
(18)

(80)
(17)
3
14

Balance, December 31, 2019

5,004

(5,370)

(23) $

(389) $

93 $

(296)

Note: Excludes amounts related to redeemable noncontrolling interests recorded in mezzanine equity. See Part II, Item 8 –

(a)

Financial Statements and Supplementary Data, Note 5 Joint Ventures for more information.
Includes 2.85 million shares of common stock (valued at $51 million at issuance) issued to Chevron in connection with our
acquisition of Chevron’s working interest in the Elk Hills unit and 2.3 million shares of common stock (valued at $50 million
at issuance) issued to an Ares-led investor group. See Part II, Item 8 – Financial Statements and Supplementary Data,
Note 4 Acquisitions and Divestitures and Part II, Item 8 – Financial Statements and Supplementary Data, Note 5 Joint
Ventures for more information.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
For the years ended December 31, 2019, 2018 and 2017
(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
Net derivative loss (gain) from commodity contracts
Net proceeds (payments) on settled commodity

derivatives

Net gain on early extinguishment of debt
Amortization of deferred gain
Gain on asset divestitures
Other non-cash charges to income, net
Dry hole expenses

Changes in operating assets and liabilities, net:

Decrease (increase) in trade receivables
(Increase) decrease in inventories
Increase in other current assets
Decrease in accounts payable and accrued liabilities

Net cash provided by operating activities

CASH FLOW FROM INVESTING ACTIVITIES

Capital investments
Changes in capital investment accruals
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 2017 Term Loan
Payments on 2014 Term Loan
Debt repurchases
Debt transaction costs
Contributions from noncontrolling interest holders, net
Distributions paid to noncontrolling interest holders
Issuance of common stock
Shares canceled for taxes

Net cash (used) provided by financing activities

(Decrease) increase in cash

Cash—beginning of year

Cash—end of year

2019

2018

2017

99 $

429 $

(262)

471
59

111
(126)
(70)
—
131
7

22
—
(1)
(27)

676

(455)
(85)
164
(6)
(12)

(394)

2,330
(2,353)
—
—
(156)
(2)
49
(151)
4
(3)

(282)

—

502
(1)

(228)
(57)
(76)
(5)
97
16

(23)
(6)
(9)
(178)

461

(690)
69
18
(547)
(6)

(1,156)

2,823
(2,646)
—
—
(199)
(4)
796
(121)
54
(11)

692

(3)

17 $

544
90

(7)
(4)
(74)
(21)
77
2

(45)
2
(2)
(52)

248

(371)
27
33
—
(2)

(313)

1,696
(2,180)
1,274
(650)
(116)
(42)
98
(8)
3
(2)

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

NOTE 1 NATURE OF BUSINESS, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER

Nature of Business

We are an independent oil and natural gas exploration and production company operating
properties exclusively within California. We were incorporated in Delaware as a wholly owned
subsidiary of Occidental Petroleum Corporation (Occidental) on April 23, 2014, and we became an
independent, publicly traded company on December 1, 2014.

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. The assets and liabilities in the consolidated financial statements are
presented on a historical cost basis. We have eliminated 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 consolidated balance sheets, statements of operations and
cash flows.

Risks and Uncertainties

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 and 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.

Concentration of Customers

For the year ended December 31, 2019, our principal customers, Phillips 66 Company and Valero
Marketing & Supply Company, each accounted for at least 10%, and collectively accounted for 46%, of
our oil and natural gas sales before the effects of hedging. For the year ended December 31, 2018, our
principal customers, Phillips 66 Company and Valero Marketing & Supply Company, each accounted
for at least 10%, and collectively accounted for 43%, of our oil and natural gas sales before the effects
of hedging. For the year ended December 31, 2017, our principal customers, Phillips 66 Company,
Andeavor Logistic LP, Valero Marketing & Supply Company and Shell Trading (US) Company, each
accounted for at least 10%, and collectively accounted for 67%, of our revenue excluding the impact of
derivative gains and losses.

Critical Accounting Policies

Property, Plant and Equipment

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 given 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 additional 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 – A portion of the carrying value of our oil and natural gas properties is
attributable to unproved properties. At December 31, 2019, the net capitalized costs attributable to
unproved properties were approximately $232 million. 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 based on the initially determined rate, not based on specific areas, leases or
other units. 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.

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. Other non-producing property and equipment is depreciated using the
straight-line method based on expected initial lives of the individual assets or group of assets of up to
20 years.

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 using a risk-adjusted discount rate.

Commodity and interest-rate derivatives are carried at fair value. For commodity derivatives, we

utilize the mid-point between bid and ask prices for valuing these instruments. For interest-rate
derivatives, we utilize the London Interbank Offered Rate (LIBOR) forward curve. In addition to using
market data in determining these fair values, we make assumptions about the risks inherent in the
inputs to the valuation technique. 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) is written down to fair value if we determine that there

has been an impairment in its value. The fair value is determined as of the date of the assessment
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 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.

Other Accounting Policies

Revenue Recognition

We recognize revenue in accordance with ASC 606, Revenue from Contracts with Customers,

which is more fully described in Note 15 Revenue Recognition.

Inventories

Materials and supplies 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 market. Inventories as of December 31, 2019 and 2018 consisted of the
following:

Materials and supplies
Finished goods

Total

2019

2018

(in millions)
64 $
3

67 $

65
4

Derivative Instruments

Our derivative contracts are carried at fair value and on a net basis when a legal right of offset
exists with the same counterparty. Since we did not apply hedge accounting for any of the periods
presented, we recognize any fair value gains or losses on a net basis, over the remaining term of the
instrument, in our consolidated statement 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

We have stockholder-approved stock-based incentive plans for certain executives, employees and

non-employee directors that are more fully described in Note 11 Stock Compensation.

Earnings Per Share

We compute basic and diluted earnings per share (EPS) using the two-class method required for
participating securities. 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. For basic EPS, the weighted-average number of common shares outstanding
excludes outstanding shares related to unvested restricted stock awards. For diluted EPS, the basic
shares outstanding are adjusted by adding potentially dilutive securities.

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 estimated based on future retirement cost estimates and
incorporates many assumptions such as time of abandonment, current regulatory requirements,
technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is
initially recorded, we capitalize the cost by increasing the related property, plant and equipment
(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 summarizes the activity of our ARO, of which $489 million and $402 million are

included in other long-term liabilities, with the remaining portion in accrued liabilities at December 31,
2019 and 2018, respectively.

Beginning balance
Liabilities incurred, capitalized to PP&E
Liabilities settled and paid
Accretion expense
Acquisitions, capitalized to PP&E(a)
Dispositions, reduction to PP&E
Other
Revisions

Ending balance

For the years ended
December 31,

2019

2018

(in millions)
433 $
(5)
(26)
36
—
(10)
4
85

517 $

422
4
(15)
27
8
(1)
(1)
(11)

433

(a) For the year ended December 31, 2018, amount includes $7 million related to the Elk Hills transaction and $1 million

related to other acquisitions.

The timing of our cash flows and additional testing costs associated with our future asset

retirement activities were adjusted in 2019 due to new idle well regulations enacted in the first quarter.
These new regulations require operators to either (1) submit annual idle well management plans
describing how they will plug and abandon or reactivate a specified percentage of long-term idle wells
or (2) pay additional annual fees and perform additional testing to retain greater flexibility to return
long-term idle wells to service in the future. These regulations provide a six-year implementation period
for testing existing idle wells not scheduled for plugging and abandonment. Newly idle wells must be
tested within two years after becoming idle and, thereafter, are subject to the same testing schedule for
existing idle wells.

Other 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 loss 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 production
costs. We record a share of production and reserves to recover a portion of such capital and
production costs and an additional share for profit. Our portion of the production represents volumes:
(i) to recover our partners’ share of capital and production 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 production costs. However, our net economic benefit is greater
when product prices are higher. The contracts represented approximately 15% of our production for
the year ended December 31, 2019.

In line with industry practice for reporting PSC-type contracts, 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 PSC-type contracts. 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
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 using a December 31 measurement date.

We determine our defined benefit pension and postretirement benefit plan obligations based on

various assumptions and discount rates. The discount rate assumptions used are meant to reflect the
interest rate at which the obligations could effectively be settled on the measurement date. We
estimate the rate of return on assets with regard to current market factors but within the context of
historical returns.

Pension plan assets are measured at fair value. Publicly registered mutual funds are valued using
quoted market prices in active markets. Commingled funds are valued at the fund units’ net asset value
(NAV) provided by the issuer, which represents the quoted price in a non-active market. Guaranteed
deposit accounts are valued at the book value provided by the issuer.

Actuarial gains and losses that have not yet been recognized through income are recorded in
accumulated other comprehensive income within equity, net of taxes, until they are amortized as a
component of net periodic benefit cost.

Cash

Cash at December 31, 2019 and 2018 included approximately $3 million and $2 million,

respectively, that is restricted under one of our joint venture (JV) agreements.

Other Current Assets

Other current assets, net as of December 31, 2019 and 2018 consisted of the following:

Net amounts due from joint interest partners(a)
Derivative assets
Prepaid expenses
Other

Other current assets, net

2019

2018

(in millions)
70
$
39
19
2

130

(a)

Included in the 2019 and 2018 net amounts due from joint interest partners are allowances for doubtful accounts of
$22 million and $31 million, respectively.

Accrued Liabilities

Accrued liabilities as of December 31, 2019 and 2018 consisted of the following:

Accrued employee-related costs
Accrued taxes other than on income
Asset retirement obligation
Accrued interest
Lease liability
Other

Accrued liabilities

2019

2018

(in millions)
116
57
28
13
28
71

313

68
168
16
3

255

109
38
31
15
—
24

217

100

In the fourth quarter of 2019, we implemented operational efficiencies and an organizational
redesign that reduced our workforce to approximately 1,250 employees. We recorded a related charge
to other non-operating expenses of $41 million, consisting of $29 million in salary and severance
expense and $12 million for other termination benefits. As of December 31, 2019, our remaining
associated liability of $19 million was included in accrued employee-related costs.

Supplemental Cash Flow Information

We did not make any significant U.S. federal and state income tax payments in 2019, 2018 or

2017. Interest paid, net of capitalized amounts, totaled approximately $425 million, $433 million and
$393 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Non-cash financing activities during 2019 included valuing the first two tranches of a warrant to
purchase 0.4 million shares of our common stock (valued at $3 million) issued in connection with a
development joint venture. See Note 12 Equity for more information. Non-cash financing activities in
2018 included 2.85 million shares of common stock (valued at $51 million) issued in connection with
the Elk Hills transaction. See Note 4 Acquisitions and Divestitures for more on the Elk Hills transaction.

NOTE 2 ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

We adopted the Financial Accounting Standards Board’s new lease accounting rules (ASC 842),
as of January 1, 2019, using the modified retrospective approach where the new lease standard is not
applied to prior comparative periods, which continue to be presented under accounting standards in
effect for those prior periods. Under the modified retrospective approach, we recognized right-of-use
(ROU) assets and lease liabilities of $66 million as of the adoption date. The adoption of the new lease
accounting rules did not materially impact our consolidated results of operations and had no impact on
cash flows or beginning retained earnings. The new lease standard does not affect our liquidity and
has no impact on our debt-covenant calculations under our 2014 Revolving Credit Facility, 2016 Credit
Agreement and 2017 Credit Agreement. See Note 7 Leases for more information.

NOTE 3 PROPERTY, PLANT AND EQUIPMENT

The carrying value of our PP&E represents the cost incurred to acquire or develop the asset,
including any ARO and capitalized interest, net of accumulated DD&A and any impairment charges.
For assets acquired, initial PP&E cost is based on fair values at the acquisition date. ARO are
capitalized and recovered over the lives of the related assets. No impairment charges were recorded in
2019, 2018 or 2017.

Property, plant and equipment, net as of December 31, 2019 and 2018 consisted of the following:

Proved oil and natural gas properties
Unproved oil and natural gas properties(a)
Facilities and other

Total property, plant and equipment

Accumulated depreciation, depletion and amortization

2019

2018

(in millions)
$

21,285
1,055
549

22,889
(16,537)

20,882
1,103
538

22,523
(16,068)

Total property, plant and equipment, net

6,352

6,455

(a)

Includes accumulated valuation allowance for total unproved properties of $823 million and $819 million at December 31,
2019 and 2018, respectively.

101

The following table summarizes the activity of capitalized exploratory well costs for the years

ended December 31:

2017

2019

2018
(in millions)
4
$
19
(2)
(16)

5
12
(3)
(7)

4
4
(2)
(2)

Balance, beginning of year
Additions to capitalized exploratory well costs
Reclassification to property, plant and equipment
Charged to expense

Balance, end of year

NOTE 4 ACQUISITIONS AND DIVESTITURES

Acquisitions

Elk Hills Transaction

In April 2018, we acquired the remaining working, surface and mineral interests in the

approximately 47,000-acre Elk Hills unit from Chevron U.S.A., Inc. (Chevron) (the Elk Hills transaction)
for approximately $518 million, including $7 million of liabilities assumed relating to ARO. We
accounted for the Elk Hills transaction as a business combination. As of December 31, 2019, we held
all of the working, surface and mineral interests in the former Elk Hills unit. The effective date of the
transaction was April 1, 2018.

As part of the Elk Hills transaction, Chevron reduced its royalty interest in one of our oil and
natural gas properties by half and extended the time frame to invest the remainder of our capital
commitment on that property by the end of 2020. As of December 31, 2019, the remaining commitment
was approximately $12 million. In addition, the parties mutually agreed to release each other from
pending claims with respect to the former Elk Hills unit.

The following table summarizes the total consideration, including customary closing adjustments,

and the allocation of the consideration based on the fair value of the assets acquired as of the
acquisition date:

Consideration:

Cash
Common stock issued (2.85 million shares)
Liabilities assumed

Identifiable assets acquired:

Proved properties
Other property and equipment
Materials and supplies

(in millions)
460
$
51
7

518

435
77
6

518

The results of operations for the Elk Hills transaction were included in our consolidated financial

statements subsequent to the closing date.

102

Bakersfield Office Building

In April 2018, we also acquired an office building and land in Bakersfield, California for $48 million.

For the initial eight months in 2018, a former owner of the building occupied most of the space as a
tenant, from which we generated approximately $4 million in rental income. In December 2018, this
tenant downsized the space they are leasing through December 2022, with a corresponding reduction
in rent. The vacated space not used by us will be available to lease to other tenants to generate
additional income. In addition, the unimproved land may be monetized in the future. Approximately
$6 million of the purchase price was allocated to the in-place leases in 2018, which is included in other
assets and is being amortized into other expenses, net.

Other

In 2019, we had several other acquisitions totaling approximately $6 million. In 2018, we had other

upstream acquisitions totaling approximately $39 million, excluding assumed ARO liabilities of
$1 million.

Divestitures

Lost Hills Divestiture

In May 2019, we sold 50% of our working interest and transferred operatorship in certain zones

Other

In 2018, we divested non-core assets resulting in $18 million of proceeds and a $5 million gain.

103

NOTE 5

JOINT VENTURES

Noncontrolling Interests

The following table presents the changes in noncontrolling interests for our consolidated JVs

(described in greater detail below), which are reported in equity and mezzanine equity on the
consolidated balance sheets for the years ended December 31, 2019 and 2018:

Equity Attributable
to Noncontrolling Interests
Total
BSP JV

Ares JV

Mezzanine
Equity –
Redeemable
Noncontrolling
Interest
Ares JV

Balance, December 31, 2017
Net (loss) income attributable to noncontrolling

interests

Contributions from noncontrolling interest holders, net
Distributions to noncontrolling interest holders

Balance, December 31, 2018
Net (loss) income attributable to noncontrolling

interests

Contributions from noncontrolling interest holders, net
Distributions to noncontrolling interest holders

$ — $

(in millions)
$

(11)
33
(7)

13
49
(57)

2
82
(64)

114

(7)
—
(8)

17
49
(72)

10
49
(80)

—

99
714
(57)

756

117
—
(71)

802

Balance, December 31, 2019

$ — $

Ares Management L.P. (Ares)

In February 2018, we entered into a midstream JV with ECR Corporate Holdings L.P. (ECR), a

portfolio company of Ares Management L.P. (Ares). This JV (Ares JV) holds the Elk Hills power plant
(a 550-megawatt natural gas fired power plant) and a 200 million cubic foot per day cryogenic gas
processing plant. We hold 50% of the Class A common interest and 95.25% of the Class C common
interest in the Ares JV. ECR holds 50% of the Class A common interest, 100% of the Class B preferred
interest and 4.75% of the Class C common interest. We received $750 million in proceeds upon
entering into the Ares JV, before $3 million of transaction costs.

The Class A common and Class B preferred interests held by ECR are reported as redeemable

noncontrolling interest in mezzanine equity due to an embedded optional redemption feature. The
Class C common interest held by ECR is reported in equity on our consolidated balance sheets.

The Ares JV is 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. The Class B preferred interest has a deferred payment feature whereby a portion of the monthly
distributions may be deferred for the first three years to the fourth and fifth year. The deferred amounts
accrue an additional return. Distributions to the Class B preferred interest holders are reported as a
reduction to mezzanine equity on our consolidated balance sheets.

104

We can cause the Ares JV to redeem ECR’s Class A and Class B interests, in whole, but not in
part, at any time by paying $750 million for the Class B interest and $60 million for the Class A interest,
plus any previously accrued but unpaid preferred distributions and a make-whole payment if the
redemption happens prior to five years from inception. We have the option to extend the redemption
period for up to an additional two and one-half years, in which case the interests can be redeemed for
$750 million for the Class B interest and $80 million for the Class A interest, plus any previously
accrued but unpaid preferred distributions and a make-whole payment if the redemption happens prior
to seven and one-half years from inception. If the Ares JV does not exercise its redemption option at
the end of the seven and one-half year period, ECR can either sell its Class A and Class B interests or
cause the sale or lease of the Ares JV assets.

Our consolidated statements of operations reflect the full operations of our Ares JV, with ECR’s

share of net income reported in net income attributable to noncontrolling interests.

Additionally, in 2018, an Ares-led investor group purchased approximately 2.3 million shares of our

common stock in a private placement for an aggregate purchase price of $50 million.

Benefit Street Partners (BSP)

In February 2017, we entered into a development joint venture with BSP (BSP JV) where BSP will

contribute up to $250 million, subject to agreement of the parties, in exchange for a preferred interest
in the BSP JV. BSP is entitled to preferential distributions and, if it receives cash distributions equal to
a predetermined threshold, the preferred interest is automatically redeemed in full with no additional
payment. To date, BSP funded a total of $200 million in four equal tranches, before transaction costs.
The funds contributed by BSP were used to develop certain of our oil and natural gas properties.

The BSP JV holds net profits interests (NPI) in existing and future cash flow from certain of our

properties and the proceeds from the NPI are used by the BSP JV to (1) pay quarterly minimum
distributions to BSP, (2) make distributions to BSP until the predetermined threshold is achieved, and
(3) pay for additional development costs within the project area, upon mutual agreement between
members.

Our consolidated results reflect the full operations of the BSP JV, with BSP’s share of net income
being reported in net income attributable to noncontrolling interests on our consolidated statements of
operations.

Other

Alpine JV

In July 2019, we entered into a development joint venture with Alpine Energy Capital, LLC (Alpine)

105

In connection with the Alpine JV, Colony received a warrant to purchase up to 1.25 million shares

of our common stock at an exercise price of $40 per share. Colony will be entitled to exercise the
warrant in tranches as funding milestones are achieved. Each tranche will have a five-year term
commencing on the date on which such tranche becomes exercisable. As of December 31, 2019,
200,000 shares of our common stock were exercisable under this warrant. Colony may elect, in its sole
discretion, to pay cash or to exercise the warrant on a cashless basis, pursuant to which Colony will
not be required to pay cash for shares of our common stock upon exercise of the warrant but will
instead receive fewer shares.

MIRA JV

In April 2017, we entered into a development joint venture with Macquarie Infrastructure and Real

Assets Inc. (MIRA) to develop certain of our oil and natural gas properties in exchange for a 90%
working interest in the related properties (MIRA JV). MIRA funded 100% of the drilling and completion
costs of agreed-upon wells in the drilling program. Our 10% working interest increases to 75% if MIRA
receives cash distributions equal to a predetermined threshold return. Of the initial agreed-upon capital
program of $140 million, $138 million was funded through December 31, 2019. Our consolidated
results reflect only our working interest share in the productive wells.

NOTE 6 DEBT

As of December 31, 2019 and 2018, our long-term debt consisted of the following credit

agreements, Second Lien Notes and Senior Notes:

Outstanding Principal

Interest Rate(a)

Maturity

Security

Credit Agreements

2019

2018

(in millions)

2014 Revolving Credit
Facility

518 $

540

2017 Credit Agreement

1,300

2016 Credit Agreement

1,000

Second Lien Notes

1,815

2,067

Senior Notes

5% Senior Notes due

2020

5 1⁄ 2% Senior Notes

due 2021

6% Senior Notes due

2024

100

144

100

144

Total Debt

4,977 $

5,251

Less:

Current Maturities

(100)

—

Long-Term Debt $

4,877 $

5,251

LIBOR plus
3.25%-4.00%
ABR plus
2.25%-3.00%
LIBOR plus 4.75%
ABR plus 3.75%
LIBOR plus
10.375%
ABR plus 9.375%

5.5%

June 30, 2021

December 31, 2022(b)

December 31, 2021

December 15, 2022(c)

Shared First-
Priority Lien
Shared First-
Priority Lien

First-Priority
Lien

Second-
Priority Lien

January 15, 2020

Unsecured

September 15, 2021 Unsecured

November 15, 2024 Unsecured

(a) London Interbank Offered Rates (LIBOR) will be phased out after 2021 and replaced with the Secured Overnight Financing
Rate within the United States for U.S. dollar-based LIBOR. Our credit agreements contemplate a discontinuation of LIBOR
and have an alternate borrowing rate. We do not expect the discontinuation of LIBOR to have a significant impact on our
interest expense.

106

(b) The 2017 Credit Agreement is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if

more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.

(c) The Second Lien Notes require principal repayments of approximately $287 million in June 2021, $57 million in December

2021 and $59 million in June 2022 and $1,412 million in December 2022.

Credit Agreements

2014 Revolving Credit Facility

In September 2014, we entered into a Credit Agreement with JPMorgan Chase Bank, N.A, as
administrative agent, and certain other lenders. This credit agreement currently consists of a $1 billion
senior revolving loan facility (2014 Revolving Credit Facility), which we are permitted to increase by up
to $50 million if we obtain additional commitments from new or existing lenders.

As of December 31, 2019, we had approximately $317 million of available borrowing capacity,
before a $150 million month-end minimum liquidity requirement. Our 2014 Revolving Credit Facility
also includes a sub-limit of $400 million for the issuance of letters of credit. As of December 31, 2019
and 2018, we had letters of credit of approximately $165 million and $162 million, respectively. These
letters of credit were issued to support ordinary course marketing, insurance, regulatory and other
matters.

Security – The lenders share a first-priority lien on a substantial majority of our assets with the
lenders under of 2017 Credit Agreement, excluding the Elk Hills power plant and midstream assets that
are part of the Ares JV.

Interest Rate – We can elect to borrow at either LIBOR or an alternate base rate (ABR), in each
case 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’s prime rate and (iii) the one-month LIBOR rate plus 1.00%.
The applicable margin is adjusted based on the borrowing base utilization percentage under the 2014
Revolving Credit Facility and will vary from (i) in the case of LIBOR loans, 3.25% to 4.00% and (ii) in
the case of ABR loans, 2.25% to 3.00%. 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.

Maturity Date – Our 2014 Revolving Credit Facility matures on June 30, 2021.

Amortization Payments – The 2014 Revolving Credit Facility does not include any obligation to

make amortization payments.

Borrowing Base – The borrowing base is redetermined each May 1 and November 1 and was

most recently reaffirmed at $2.3 billion in November 2019. The borrowing base is based upon a
number of factors, including commodity prices and reserves, declines in which could cause our
borrowing base to be reduced. Increases in our borrowing base require approval of at least 80% of our
lenders while decreases or affirmations require a two-thirds approval, in each case as measured by
relative commitment amount. We and the lenders (requiring a request from the lenders holding
two-thirds of the commitments) each may request a special redetermination once in any period
between three consecutive scheduled redeterminations. We will be permitted to have collateral
released when both (i) our credit ratings are at least Baa3 from Moody’s and BBB- from S&P, in each
case with a stable or better outlook, and (ii) certain permitted liens securing other debt are released.

107

Financial Covenants – As of December 31, 2019, our financial performance covenants included a

monthly minimum liquidity requirement of not less than $150 million and the following:

Ratio

Components(a)

Required Levels

Tested

Maximum leverage
ratio

Ratio of indebtedness under
our 2014 Revolving Credit
Facility to trailing four-quarter
Adjusted EBITDAX

Not greater than 1.90 to 1.00
through 2019
Not greater than 1.50 to 1.00
after 2019

Quarterly

Minimum interest
coverage ratio

Ratio of Adjusted EBITDAX to
consolidated cash interest
charges

Minimum asset
coverage ratio

Ratio of PV-10 to first lien
indebtedness

Not less than 1.20 to 1.00

Quarterly

Not less than 1.20 to 1.00

Quarterly

(a) Refer to the terms of our credit agreements for more detailed descriptions of the components of our financial covenants.

Other Covenants – Our 2014 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 from paying cash dividends on our
stock. Generally, these covenants include exceptions that allow us to pursue some of these activities in
certain circumstances. In addition to these covenants, we must also apply cash on hand in excess of
$150 million daily to repay amounts outstanding. Finally, we are also subject to a cross-default
provision that causes a default under this facility if certain defaults occur under any of our other credit
agreements or bond indentures.

Except for dispositions to development JVs, we must generally apply all of the proceeds from the

sale of assets included in our borrowing base to repay loans outstanding under our 2014 Revolving
Credit Facility. With respect to the sale of non-borrowing base assets (other than the Elk Hills power
plant), we must apply the net cash proceeds to repay outstanding loans as follows:

(cid:129)
(cid:129)
(cid:129)

25% of such proceeds for all net cash proceeds received up to $500 million
50% of such proceeds for all net cash proceeds received between $500 million and $1 billion
75% of such proceeds for all net cash proceeds received in excess of $1 billion.

We are permitted to use the balance of proceeds from non-borrowing base asset sales for general
corporate purposes including acquisitions and to repurchase our Second Lien Notes and Senior Notes
subject to certain conditions, including pro-forma compliance with our financial performance covenants
and that we have minimum liquidity of $300 million following such repurchase.

Events of Default and Change of Control – Our 2014 Revolving Credit Facility provides for certain
events of default, including upon a change of control, that entitle our lenders to declare the outstanding
loans immediately due and payable, subject to certain limitations and conditions.

Recent Amendments – Our 2014 Revolving Credit Facility was most recently amended in August

2019 to provide us with flexibility in connection with potential royalty transactions.

108

2017 Credit Agreement

In November 2017, we entered into a $1.3 billion credit agreement with The Bank of New York

Mellon Trust Company, N.A., as administrative agent, and certain other lenders (2017 Credit
Agreement). The net proceeds were used to pay the $559 million remaining balance of our term loan
under our 2014 Revolving Credit Facility (2014 Term Loan), resulting in a loss on the early
extinguishment of debt of $8 million, reduce the balance of our 2014 Revolving Credit Facility and pay
accrued interest. The proceeds received were net of a $26 million original issue discount and
$38 million in transaction costs. As of December 31, 2019, we had a $1.3 billion term loan outstanding
under our 2017 Credit Agreement.

Security – Our 2017 Credit Agreement is secured by the same shared first-priority lien used to

secure our 2014 Revolving Credit Facility.

Maturity Date – The loans mature on December 31, 2022, subject to a springing maturity of 91
days prior to the maturity of our 2016 Credit Agreement if more than $100 million is outstanding at that
time. Prepayment more than 90 days prior to maturity is subject to a 2% premium.

Financial and Other Covenants – We are required to maintain a first-lien asset coverage ratio of
not less than 1.20 to 1.00 as of any June 30 and December 31. In addition, our 2017 Credit Agreement
provides for customary covenants and events of default consistent with, or generally less restrictive
than, the covenants in our 2014 Revolving Credit Facility. The covenants include limitations on
additional indebtedness, liens, asset dispositions and investments, among others, and are in each
case subject to certain limitations and exceptions. We are also restricted from paying cash dividends
on our stock.

Events of Default and Change of Control – Our 2017 Credit Agreement provides for certain events

of default, including upon a change of control, that entitle our lenders to declare the outstanding loans
immediately due and payable, subject to certain limitations and conditions. We are also subject to a
cross-default provision that causes a default under this credit agreement if certain defaults occur under
any of our other credit agreements or indentures.

2016 Credit Agreement

In August 2016, we entered into a $1 billion credit agreement with The Bank of New York Mellon

Trust Company, N.A., as administrative agent, and certain other lenders (2016 Credit Agreement). The
net proceeds from the 2016 Credit Agreement were used to (i) prepay $250 million of our 2014 Term
Loan and (ii) reduce our 2014 Revolving Credit Facility by $740 million. The proceeds received were
net of a $10 million original issue discount. As of December 31, 2019, we had a $1 billion term loan
outstanding under our 2016 Credit Agreement.

Security – Our 2016 Credit Agreement is secured by a first-priority lien on a substantial majority of

our assets (excluding the Elk Hills power plant and midstream assets that are part of the Ares JV) but
is second in collateral recovery to our 2014 Revolving Credit Facility and 2017 Credit Agreement.

Maturity Date – The loans mature on December 31, 2021. Prepayment is subject to a variable
make-whole amount prior to the fourth anniversary. Following the fourth anniversary, we may redeem
at par.

109

Financial and Other Covenants – We are required to maintain a first–lien asset coverage ratio of

not less than 1.20 to 1.00 as of any June 30 and December 31. Our 2016 Credit Agreement also
includes other covenants that are substantially similar to our 2017 Credit Agreement. We are also
restricted from paying cash dividends on our stock.

Events of Default and Change of Control – Our 2016 Credit Agreement provides for certain events

Second Lien Notes

In December 2015, we issued $2.25 billion in aggregate principal amount of 8% senior secured

second-lien notes due December 15, 2022 (Second Lien Notes). The Second Lien Notes were issued
in exchange for $2.8 billion of our then outstanding Senior Notes. We recorded a deferred gain of
approximately $560 million on the debt exchange, which is being amortized using the effective interest
rate method over the term of our Second Lien Notes. We pay cash interest semiannually in arrears on
June 15 and December 15.

Security – Our Second Lien Notes are secured on a junior-priority basis to the first-priority liens

that secure the loans under our 2014 Revolving Credit Facility, 2017 Credit Agreement and 2016
Credit Agreement.

Repurchases – In 2019, we repurchased $252 million in face value of our Second Lien Notes for

$156 million in cash, resulting in a pre-tax gain of $126 million including the effect of unamortized
deferred gain and issuance costs. In 2018, we repurchased $183 million in face value of our Second
Lien Notes for $159 million in cash, resulting in a pre-tax gain of $48 million including the effect of
unamortized deferred gain and issuance costs.

Financial and Other Covenants – The indenture includes covenants that, among other things, limit
our ability to grant liens securing borrowed money (subject to certain exceptions) and restrict our ability
to merge or consolidate with, or transfer all or substantially all of our assets to, another entity. The
covenants are not, however, directly linked to measures of our financial performance. In addition, if we
experience a “change of control triggering event” (as defined in the indenture), we will be required,
unless we have exercised our right to redeem our Second Lien Notes, to offer to purchase our Second
Lien Notes at a purchase price equal to 101% of their principal amount, plus accrued and unpaid
interest. The indenture also restricts our ability to sell certain assets and to release collateral from liens
securing our Second Lien Notes, unless the collateral is also released in compliance with our senior
credit facilities. We are also subject to a cross-default provision that causes a default under this
indenture if certain defaults occur under any of our other credit agreements or indentures.

Redemption – We may redeem our Second Lien Notes (i) prior to December 15, 2018, in whole or

in part at a redemption price equal to 100% of the principal amount redeemed plus a make-whole
amount and accrued and unpaid interest, (ii) between December 15, 2018 and 2020, in whole or in part
at a fixed redemption price ranging from 104% to 102% of the principal amount redeemed plus accrued
and unpaid interest and (iii) thereafter in whole or in part at a redemption price equal to 100% of the
principal amount redeemed plus accrued and unpaid interest.

110

Senior Notes

In October 2014, we issued $5 billion in aggregate principal amount of our senior unsecured
notes, including $1 billion of 5% notes due January 15, 2020 (2020 Notes), $1.75 billion of 5.5% notes
due September 15, 2021 (2021 Notes) and $2.25 billion of 6% notes due November 15, 2024 (2024
Notes and, collectively, Senior Notes). We used the net proceeds from the issuance of our Senior
Notes to make a $4.95 billion cash distribution to Occidental in October 2014.

Repurchases – In 2019, we did not repurchase any of our Senior Notes. In 2018, we repurchased

$49 million in face value of our 2024 Notes for $40 million in cash, resulting in a pre-tax gain of
$9 million including the effect of unamortized deferred issuance costs.

Financial and Other Covenants – The indenture includes covenants that, among other things, limit
our ability to grant liens securing borrowed money subject to certain exceptions and restrict our ability
to merge or consolidate with, or transfer all or substantially all of our assets to, another entity. The
covenants are not, however, directly linked to measures of our financial performance. In addition, if we
experience a “change of control triggering event” (as defined in the indenture), we will be required,
unless we have exercised our right to redeem our Senior Notes, to offer to purchase our Senior Notes
at a purchase price equal to 101% of their principal amount, plus accrued and unpaid interest. We are
also subject to a cross-default provision that causes a default under this indenture if certain defaults
occur under any of our other credit agreements or indentures.

Redemption – We may redeem our Senior Notes prior to their maturity dates, in whole or in part,

at a redemption price equal to 100% of the principal amount redeemed plus accrued and unpaid
interest and, generally, a make-whole amount.

Deferred Gain and Issuance Costs

At December 31, 2019 and 2018, net deferred gain and issuance costs consisted of the following:

Deferred gain
Deferred issuance costs and original issue discounts

Net deferred gain and issuance costs

Other

2019

2018

(in millions)
211 $
(65)

146 $

313
(97)

216

At December 31, 2019, we were in compliance with all financial and other debt covenants.

All obligations under our 2014 Revolving Credit Facility, 2017 Credit Agreement and 2016 Credit

Agreement (collectively, Credit Facilities) as well as our Second Lien Notes and Senior Notes are
guaranteed both fully and unconditionally and jointly and severally by all 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.

111

Principal maturities of debt outstanding at December 31, 2019 are as follows:

2020
2021
2022
2023
2024
Thereafter

Total

As of
December 31, 2019
(in millions)

100
1,962
2,771
—
144
—

4,977

We estimate the fair value of fixed-rate debt, which is classified as Level 1, based on prices from
known market transactions for our instruments. The estimated fair value of our debt at December 31,
2019 and 2018, including the fair value of the variable-rate portion, was approximately $3.8 billion and
$4.5 billion, respectively, compared to a face value of approximately $5.0 billion and $5.3 billion,
respectively.

NOTE 7 LEASES

On January 1, 2019, we adopted ASC 842 using the modified retrospective approach that required

us to determine our lease balances as of that date. Prior periods continue to be reported under
accounting standards in effect for those periods. We elected to carry forward our accounting treatment
for land easements on existing agreements. Mineral leases, including oil and natural gas leases, are
not included within the scope of ASC 842.

We have long-term operating leases for commercial office space, drilling rigs, fleet vehicles and

certain facilities. 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 lease liability was determined by measuring the present value of the remaining fixed minimum

lease payments as of the date of adoption 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.

We elected to combine lease and non-lease components in determining fixed minimum lease

payments for our drilling rigs and commercial office space. If applicable, fixed minimum lease
payments were reduced by lease incentives for our commercial buildings and increased by
mobilization and demobilization fees related to 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 lease liability does not include
options to extend or terminate our leases. 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.

For all of our asset classes, we elected to keep leases with an initial term of 12 months or less off

the balance sheet and have included costs related to these contracts in our short-term lease cost
disclosure below. Contracts with terms of one month or less are excluded from our disclosure of short-
term lease costs.

112

For our long-term contracts, variable lease costs were not included in the measurement of our
lease balances. Variable lease costs for our drilling rigs included 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 included other-than-routine
maintenance and other various amounts in excess of our fixed minimum rental fee.

Our operating lease costs, including amounts capitalized to PP&E, for the year ended

December 31, 2019 were as follows:

Operating lease cost
Short-term lease cost
Variable lease cost(a)

Total operating lease costs

2019
(in millions)

52
74
21

147

(a)

Includes $19 million related to drilling rigs, which are capitalized to PP&E.

During the second quarter of 2019, we entered into 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. For the year ended December 31, 2019, sublease income was not material to our
consolidated financial statements.

Cash flows related to our operating leases for the year ended December 31, 2019 were as follows:

Operating cash flows
Investing cash flows

2019
(in millions)

$
$

14
40

Our cash flows related to finance leases were not significant for the year ended December 31,

2019.

Other information related to our operating and finance leases as of December 31, 2019 was as

follows:

Operating Leases
ROU asset obtained in exchange for lease obligations (in millions)
Weighted-average remaining lease term (in years)
Weighted-average discount rate

Finance Leases
ROU asset obtained in exchange for lease obligations (in millions)
Weighted-average remaining lease term (in years)
Weighted-average discount rate

2019

122
4.75
12.2%

2
2.33
8.5%

113

The difference in the weighted-average discount rate between operating leases and finance

leases primarily relates to lease term.

Balance sheet information related to our operating and finance leases as of December 31, 2019

was as follows:

Assets
Operating lease, net
Finance lease, net

Total lease assets

Liabilities
Current

Operating lease
Finance lease

Long-term

Operating lease
Finance lease

Total lease liabilities

Balance Sheet Location

2019

(in millions)

Other assets $

PP&E

Accrued liabilities $
Accrued liabilities

Other long-term liabilities
Other long-term liabilities

59
2

27
1

37
1

As part of our company-wide consolidation of office space, we vacated certain office space in

2019, some of which we subleased. When we enter into a sublease agreement, we evaluate the
carrying value of our ROU asset (including the carrying value of related tenant improvements) for
impairment based on future identifiable cash flows. For the year ended December 31, 2019, we
recognized impairment charges of $3 million related to our leases and $6 million related to abandoned
tenant improvements. We may terminate leases for vacated office space before the expiration of the
lease term. In cases where we decided not to sublease vacated commercial office space, we
shortened the useful life of the ROU assets and related tenant improvements to recover our remaining
costs over our expected period of use. Once the leased office space is vacated, lease costs will be
classified as other non-operating expenses on our consolidated statements of operations.

Maturities of our operating and finance lease liabilities at December 31, 2019 are as follows:

2020
2021
2022
2023
2024
Thereafter

Less: Interest

Present value of lease liabilities

Operating
Leases

Finance
Leases

(in millions)
32 $
11
9
9
6
23

(26)

64 $

1
1
—
—
—
—

—

We entered into a contract for a facility that is under construction as of December 31, 2019. This

lease is not included in our lease population at December 31, 2019 because the lease term has not
commenced, and we do not control the asset during construction. We will apply the new lease
standard when the asset is placed in service by us, which is expected to be in June 2020.

114

At December 31, 2018, future minimum lease payments for noncancelable operating leases under

ASC 840 (excluding oil and natural gas and other mineral leases, utilities, taxes, insurance and
common area maintenance expenses) were:

2019
2020
2021
2022
2023
Thereafter

Total

December 31,
2018
(in millions)

12
8
7
7
6
28

Rent expense for operating leases under ASC 840 was $11 million in 2018 and $13 million in

2017. Rental income from subleases for the years ended December 31, 2018 and 2017 was not
significant.

NOTE 8 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, 2019 and 2018 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 accrued
would not be material to our consolidated financial position or results of operations.

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. At December 31, 2019, total purchase obligations on a discounted basis were as follows:

2020
2021
2022
2023
2024
Thereafter

Total
Less: Interest

Present value of purchase obligations

115

December 31,
2019
(in millions)

88
16
8
14
5
22

153
(24)

129

We remain subject to audit by the Internal Revenue Service for calendar years 2016 through 2018

as well as 2015 through 2018 by the state of California.

NOTE 9 DERIVATIVES

We use a variety of derivative instruments to protect our cash flow, operating margin and capital

program from the cyclical nature of commodity prices and interest-rate movements. These derivatives
are intended to help us maintain adequate liquidity and improve our ability to comply with the
covenants of our Credit Facilities in case of commodity-price deterioration.

Commodity-Price Risk

We did not have any commodity derivatives designated as accounting hedges as of and during the

years ended December 31, 2019, 2018 and 2017. As part of our hedging program, we held the
following Brent-based crude oil contracts as of December 31, 2019:

Purchased Puts:
Barrels per day
Weighted-average price per barrel

Sold Puts:

Barrels per day
Weighted-average price per barrel

Swaps:

Barrels per day
Weighted-average price per barrel

Q1
2020

Q2
2020

Q3
2020

Q4
2020

30,000
$ 70.83

20,000
$ 67.50

13,000
$ 65.00

8,000
$ 65.00

30,000
$ 56.67

20,000
$ 53.75

18,000
$ 54.31

13,000
$ 53.81

—
5,000
— $ 70.05

5,000
$ 65.00

The BSP JV entered into crude oil derivatives that are included in our consolidated results but not

in the above table. The hedges entered into by the BSP JV could affect the timing of the reversion of
BSP’s preferred interest. The BSP JV sold call options for approximately 500 barrels per day at a
weighted-average price per barrel of $60.00 per barrel for 2020. The BSP JV purchased put options for
approximately 2,000 barrels per day at a weighted-average price per barrel of approximately $50.00 for
2020. The BSP JV also purchased put options for approximately 1,000 barrels per day at a weighted-
average price per barrel of approximately $45.00 for 2021. The BSP JV also entered into natural gas
swaps for insignificant volumes for periods through May 2021.

The outcomes of the derivative positions are as follows:

(cid:129)

Sold call options – we make settlement payments for prices above the indicated weighted-
average price per barrel.
Purchased put options – we receive settlement payments for prices below the indicated
weighted-average price per barrel.
Sold put options – we make settlement payments for prices below the indicated weighted-
average price per barrel.

From time to time, we may use combinations of these positions to increase the efficacy of our

hedging program.

116

For the years ended December 31, 2019, 2018 and 2017, we recorded a non-cash derivative
(loss) gain of approximately $(170) million, $229 million, and $(83) million, respectively, from marking
these contracts to market, which were included in net derivative (loss) gain from commodity contracts
on our consolidated statements of operations. For the year ended December 31, 2019, we received
settlement payments of $111 million. For the years ended December 31, 2018 and 2017, we made
settlement payments of $228 million and $7 million, respectively.

Interest-Rate Risk

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.

For the years ended December 31, 2019 and 2018, we reported losses on these contracts in other

non-operating expenses on our consolidated statements of operations of $4 million and $6 million,
respectively. No payments were received in either 2019 or 2018.

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.

Commodity Contracts

The following table presents the fair values (at gross and net) of our outstanding derivatives as of

December 31, 2019 and 2018:

December 31, 2019

Balance Sheet Classification

Assets:
Other current assets
Other assets

Liabilities:
Accrued liabilities
Other long-term liabilities

Gross
Amounts
Recognized at
Fair Value

Gross
Amounts
Offset in the
Balance Sheet

Net Fair Value
Presented in
the Balance
Sheet

49
1

(15)
—
35

(in millions)
$

(10)
—

10
—
—

39
1

(5)
—
35

117

December 31, 2018

Gross
Amounts
Recognized at
Fair Value

Gross
Amounts
Offset in the
Balance Sheet

Net Fair Value
Presented in
the Balance
Sheet

(in millions)

252
23

(84)
(9)

(87)
(10)

84
9

178

— $

168
14

(3)
(1)

178

Balance Sheet Classification

Assets:
Other current assets
Other assets

Liabilities:
Accrued liabilities
Other long-term liabilities

Interest-Rate Contracts

As of December 31, 2019, and 2018, we reported the fair value of our interest-rate derivatives of

zero and $4 million, respectively, in other assets on our consolidated balance sheets.

Counterparty Credit Risk

Our credit risk relates primarily to trade receivables, joint interest receivables and derivative
financial instruments. Credit exposure for each customer is monitored for outstanding balances and
current activity. We actively manage this credit risk by selecting counterparties that we believe to be
financially strong and continuing to monitor their financial health. Concentration of credit risk is
regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of December 31, 2019, the substantial majority of the credit exposures related to our derivative
financial instruments was with investment-grade counterparties. We believe exposure to credit-related
losses at December 31, 2019 was not material and losses associated with credit risk have been
insignificant for all years presented.

All of our derivative instruments are covered by International Swap Dealers Association Master

Agreements with counterparties. At December 31, 2019, and 2018, we had insignificant collateral
posted.

NOTE 10 INCOME TAXES

Income Tax Provision (Benefit)

Income (loss) before income taxes, which is all domestic, was $100 million, $429 million and
$(262) million for the years ended December 31, 2019, 2018 and 2017, respectively. We did not record
a significant income tax provision (benefit) in any of the years ended December 31, 2019, 2018 and
2017.

118

Total income tax expense (benefit) differs from the amounts computed by applying the U.S.

federal income tax rate to pre-tax income (loss) as follows:

For the years ended
December 31,
2018

2019

2017

Effective tax rate

21%
7
(35)
—
(9)
3
—
14
—

21%
6
(5)
—
(6)
—
—
(17)
1

—%

(35)%
(6)
—
91
(19)
—
1
(33)
1

—%

Our effective tax rate is primarily affected by state taxes, income included in our consolidated
results which is taxed to noncontrolling interests, and tax credits including the enhanced oil recovery
credit. Our U.S. federal deferred tax assets and liabilities were remeasured due to the reduction of the
top corporate tax rate from 35% to 21% under the Tax Cuts and Jobs Act (TCJA) enacted on
December 22, 2017. The TCJA also included significant changes to the deduction for executive
compensation by public corporations.

Given our income tax position, any item affecting our effective tax rate described above is
generally offset by an equal change in the valuation allowance. Our valuation allowance increased
$21 million during 2019, $16 million of which was recorded to income tax provision and $5 million was
recorded to accumulated other comprehensive income. Our valuation allowance decreased $81 million
in 2018, $76 million of which was recorded to income tax provision and $5 million was recorded to
accumulated other comprehensive income. Our valuation allowance decreased $74 million in 2017,
$78 million of which was recorded as an income tax benefit and $4 million reduced accumulated other
comprehensive income.

Under the TCJA, for taxable years beginning in 2018, our deduction for business interest is limited

to 30% of our adjusted taxable income. For purposes of this limitation, adjustable taxable income is
computed without regard to net business interest expense and in the case of taxable years beginning
before January 1, 2022, any deduction allowable for depreciation, amortization or depletion. Proposed
Treasury Regulations issued in December 2018 provide that depreciation, amortization or depletion
expense that is capitalized to inventory is not treated as depreciation, amortization or depletion for the
purposes of computing adjustable taxable income. It is reasonably possible that the composition of our
deferred tax assets, specifically the amount reported for net operating loss and business interest
expense carryforwards, could significantly change when the Internal Revenue Service finalizes and
issues regulations. Our carryforwards for business interest expense do not expire.

119

Deferred Tax Assets and Liabilities

The tax effects of temporary differences resulting in deferred income tax assets and liabilities at

December 31, 2019 and 2018 were as follows:

2019

2018

Deferred Tax
Assets

Deferred Tax
Liabilities

Deferred Tax
Assets

Deferred Tax
Liabilities

Debt
Property, plant and equipment
Postretirement benefit accruals
Deferred compensation and benefits
Asset retirement obligations
Net operating loss and tax credit

carryforwards

Business interest expense carryforward
Investment in partnerships
Other

Subtotal

Valuation allowance

176
—
40
55
155

457
194
110
36

1,223
(646)

(in millions)
— $

(517)
—
—
—

—
—
—
(60)

(577)
—

253
11
27
56
129

314
82
93
17

982
(625)

Total deferred taxes

577

(577)

357

—
(316)
—
—
—

—
—
—
(41)

(357)
—

(357)

Components of accumulated other comprehensive income (loss) (AOCI) are presented net of tax.
We use the portfolio approach to clear remaining taxes recorded to AOCI when our pension plans are
terminated.

Management assesses the available positive and negative evidence to estimate whether sufficient

Other

As of December 31, 2019, we had U.S. federal net operating loss carryforwards of approximately

$1 billion, which begin to expire in 2037, and tax credit carryforwards of $57 million, which begin to
expire in 2037.

As of December 31, 2019, we had California net operating loss carryforwards of approximately
$2 billion, which begin to expire in 2026, and $20 million of tax credit carryforwards, which begin to
expire in 2037.

120

Unrecognized Tax Benefits

The following is a reconciliation of unrecognized tax benefits:

Unrecognized tax benefits – January 1
Gross increases – tax positions in prior year
Gross increases – tax positions in current year

Unrecognized tax benefits – December 31

2019

2017

For the years ended
December 31,
2018
(in millions)
25
—
—

25
44
32

101

25
—
—

The unrecognized tax benefit is reported against deferred taxes on our consolidated balance
sheets. If recognized, the amount of unrecognized tax benefit that would affect our effective tax rate is
$25 million.

It is reasonably possible that the amount of unrecognized tax benefit with respect to some of our

uncertain tax positions could significantly decrease in the next 12 months.

NOTE 11 STOCK-BASED COMPENSATION

In 2019, our stockholders approved the California Resources Corporation Long-Term Incentive
Plan (the Plan), which provides 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. The maximum
number of authorized shares of our common stock that may be issued pursuant to our long-term
incentive plan is 7.3 million shares. As of December 31, 2019, 4.7 million shares were issued or
reserved under the Plan and 2.6 million shares were available for future issuance of awards under the
Plan. Our incentive compensation program is administered by the Compensation Committee of our
Board of Directors.

Shares of our common stock may 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 may be withheld by us in payment of the exercise price of employee stock options,
which also count against the authorized shares specified above.

We recognized the following compensation expense for stock-based awards for the years ended

December 31, 2019, 2018 and 2017 in our consolidated statements of operations:

General and administrative expenses
Production costs

Total stock-based compensation expense

2019

25
7

2018
(in millions)
36
$
9

2017

23
6

For the years ended December 31, 2019, 2018 and 2017, we did not recognize any income tax

benefit related to our stock-based compensation. For the years ended December 31, 2019, 2018 and
2017, we made cash payments of $25 million, $24 million and $6 million for the cash-settled portion of
our awards, respectively.

121

As of December 31, 2019, the unrecognized compensation expense for all our unvested stock-

based incentive awards was $26 million, based on the year-end value of our common stock. This
expense is expected to be recognized over a weighted-average period of two years.

Restricted Stock

Executives and other employees are granted restricted stock units (RSUs), which are in the form

of, or equivalent in value to, actual shares of our common stock. RSUs are service based and,
depending on the terms of the awards, are settled in cash or stock at the time of vesting. The awards
either vest ratably over three years, with one third of the granted units becoming vested on the day
before each anniversary date following the date of grant, or vest entirely at the end of three years. Our
RSUs have nonforfeitable dividend rights, and any dividends or dividend equivalents declared during
the vesting period are paid as declared.

For cash- and stock-settled RSUs, compensation value is initially measured on the grant date
using the quoted market price of our common stock. Compensation expense for cash-settled RSUs is
adjusted on a monthly basis for the cumulative change in the value of the underlying stock.
Compensation expense for the stock-settled RSUs is recognized on a straight-line basis over the
requisite service periods, adjusted for actual forfeitures.

The following summarizes our restricted stock activity for the year ended December 31, 2019:

Stock-Settled

Cash-Settled

Number of Units
(in thousands)

Weighted-
Average Grant-
Date Fair Value

Number of Units
(in thousands)

$
819
171
$
(409) $
(27) $

554

17.36
21.71
19.20
13.48

17.54

2,636
1,511
(1,391)
(471)

2,285

Unvested at January 1
Granted(a)
Vested
Forfeited

Unvested at December 31

Performance Stock

Our performance stock units (PSUs) granted in 2019 and 2018 are restricted stock awards with

performance targets. The PSUs granted in 2019 are based 50% on achievement of specified
cumulative VCI results and 50% on total stockholder return relative to a selected peer group of
companies over a three-year period, with payouts ranging from 0% to 200% of the target award. The
awards are paid 50% in stock and 50% in cash up to target. Amounts over target are paid in cash.
These awards accrue dividend equivalents as dividends are declared during the vesting period, which
are paid upon certification for the number of vested units.

The PSUs granted in 2018 are based 50% on achievement of specified cumulative VCI results
and 50% on the change in CRC combined production costs compared to the change in production
costs of a selected peer group of companies over a three-year period, with payouts ranging from 0% to
200% of the target award. The awards are paid 60% in stock and 40% in cash up to target. Amounts
over target are paid in cash. These awards accrue dividend equivalents as dividends are declared
during the vesting period, which are paid upon certification for the number of vested units.

Compensation expense is 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.

122

The following summarizes our PSU activity for the year ended December 31, 2019:

Stock-Settled

Cash-Settled

Number of
Awards
(in thousands)

Weighted-
Average Grant-
Date Fair Value

Number of Units
(in thousands)

294 $
214 $
— $
(11) $

497 $

18.34
21.71
—
20.19

19.75

196
214
—
(9)

401

Unvested at January 1
Granted
Vested
Forfeited

Unvested at December 31

Stock Options

We grant stock options to certain executives under our long-term incentive plan. The options
permit the purchase of our 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 have terms of seven years and vest ratably over three years, with one
third of the granted options becoming exercisable on the day before each anniversary date following
the date of grant, subject to certain restrictions including continued employment. No stock options were
granted during 2017 and 2016.

Fair value is measured on the grant date using the Black-Scholes option valuation model and
expensed on a straight-line basis over the vesting period. The model uses various assumptions, based
on management’s estimates at the time of grant, which impact the calculation of fair value and
ultimately the amount of expense recognized over the vesting period of the award. Expected life is
calculated based on the simplified method and represents the period of time that options granted are
expected to be held prior to exercise. For options granted in 2019 and 2018, volatility was based on the
average historical volatility of our stock. For options granted in 2015 and 2014, volatility was based on
the average volatility of the stocks of a select group of peer companies in the absence of adequate
stock price history of our common stock at the time of grant. The risk-free interest rate is the implied
yield available on zero-coupon U.S. Treasury notes at the grant date with a remaining term
approximating the expected life. The dividend yield is the expected annual dividend yield over the
expected life, expressed as a percentage of the stock price on the grant date. Of the required
assumptions, the expected life of the stock option award and the expected volatility have the most
significant impact on the fair value calculation.

The grant date assumptions used in the Black-Scholes valuation for options granted during 2019,

2018, 2015 and 2014 were as follows:

Exercise price per share
Expected life (in years)
Expected volatility
Risk-free interest rate
Dividend yield
Grant-date fair value of stock option

2019

2018

2015

2014

23.88
4.5
78.26%
2.47%
—%

20.17
4.5
69.85%
2.63%
—%

42.00
4.5
44.7%
1.56%
0.95%

81.10
4.5
35.4%
1.40%
0.50%

awards

12.95

10.02

15.00

19.80

123

The following table summarizes our option activity during the year ended December 31, 2019:

Options
(in thousands)

Weighted-
Average
Exercise
Price

Weighted-
Average
Grant-Date
Fair Value

Aggregate
Intrinsic
Value

Beginning balance, January 1
Granted
Exercised
Expired or Canceled

Ending balance, December 31

1,287 $
144 $
(1) $
(3) $

1,427 $

62.82 $
23.88 $
20.17 $
22.28 $

59.00 $

Exercisable at December 31

1,174 $

66.91 $

17.22
12.95
10.02
11.69

16.81

17.92

$
$
$
$

—
—
—
—

—

Stock Awards

In 2019, we granted approximately 79,000 shares of stock to our non-employee directors as the

equity-portion of their 2019 compensation.

Employee Stock Purchase Plan

Effective January 1, 2015, we adopted the stockholder-approved California Resources

Corporation 2014 Employee Stock Purchase Plan (ESPP), which was subsequently amended in May
2016 and May 2018. The ESPP provides our employees the ability to purchase shares of our common
stock at a price equal to 85% of the closing price of a share of our common stock as of the first or last
day of each offering period (a fiscal quarter), whichever amount is less.

The maximum number of authorized shares of our common stock that may be issued pursuant to

the ESPP is 1.5 million shares, subject to adjustment pursuant to the terms of the ESPP. In addition,
participants in the ESPP are subject to certain limits on the number of shares that can be purchased in
any given year and during any given offering period. As of December 31, 2019, 1.0 million shares were
issued under our ESPP and 0.5 million shares were available for future issuance. For the year ended
December 31, 2019, we issued approximately 0.2 million shares of common stock in connection with
our ESPP.

NOTE 12 EQUITY

In connection with a development joint venture we entered into in July 2019, we issued a warrant

to Colony to purchase up to 1.25 million shares of our common stock at an exercise price of $40 per
share. Colony may exercise the warrant in tranches as funding milestones are achieved. The value of
each tranche is recognized in our consolidated balance sheets when a funding milestone begins and
has a five-year term commencing on the date on which such tranche becomes exercisable. Colony
may elect, in its sole discretion, to pay cash or to exercise on a cashless basis, pursuant to which
Colony will not be required to pay cash for shares of common stock upon exercise of the warrant but
will instead receive fewer shares.

124

We calculated the fair value of the first and second tranche on the grant date using the Black-

Scholes pricing model assumptions below:

Volatility
Risk-free interest rate
Dividend yield
Expected term (in years)
Fair value of underlying common stock
Number of shares
Tranche value (in thousands)

First
Tranche

Second
Tranche

85.00%
1.80%
—%

5.19
7.59
200,000
$ 1,518

5.45
7.84
200,000
$ 1,568

Each tranche was initially measured at fair value and will not be subsequently remeasured. Each

tranche was classified as additional paid-in-capital in equity on the consolidated balance sheet as of
December 31, 2019.

The following is a summary of common stock issuances:

Balance, December 31, 2017

Issued(a)
Canceled

Balance, December 31, 2018

Issued
Canceled

Balance, December 31, 2019

Common Stock
(in thousands)

42,902
6,110
(362)

48,650
694
(168)

49,176

(a)

Includes approximately 2.3 million shares issued in a private placement with an Ares-led investor group. For more on our
Ares JV, see Note 5 Joint Ventures.

At December 31, 2019 and 2018, we had 200 million authorized shares of common stock and

20 million authorized shares of preferred stock, both with a $0.01 par value per share, and no
outstanding shares of preferred stock on either date.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) consisted of pension and post-retirement losses

of $23 million and $6 million at December 31, 2019 and 2018, respectively.

125

NOTE 13 EARNINGS PER SHARE

The following table presents the calculation of basic and diluted EPS for the years ended

December 31:

Basic EPS calculation
Net income (loss)
Less: Net income attributable to noncontrolling interests

Net (loss) income attributable to common stock
Less: Net income allocated to participating securities

Net (loss) income available to common stockholders

Weighted-average common shares outstanding

Basic EPS

Diluted EPS calculation

Net income (loss)
Less: Net income attributable to noncontrolling interests

Net (loss) income attributable to common stock
Less: Net income allocated to participating securities

Net (loss) income available to common stockholders

Weighted-average common shares outstanding
Dilutive effect of potentially dilutive securities

Diluted EPS

Weighted-average antidilutive shares

2019

2017
2018
(in millions, except per share amounts)

99 $

(127)

(28)
—

429 $
(101)

328
(7)

(28) $

321 $

49.0

47.4

(262)
(4)

(266)
—

(266)

42.5

(0.57) $

6.77 $

(6.26)

99 $

(127)

(28)
—

429 $
(101)

328
(7)

(28) $

321 $

49.0

— $

47.4

— $

(262)
(4)

(266)
—

(266)

42.5
—

(0.57) $

6.77 $

(6.26)

3.1

1.6

2.3

NOTE 14 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, 2019 and 2018, we recognized
$37 million and $36 million in other long-term liabilities for these supplemental plans, respectively.

We expensed $36 million in 2019, $35 million in 2018 and $33 million in 2017 under the provisions

of these defined contribution and supplemental plans.

126

Defined Benefit Plans

Participation in defined benefit pension plans sponsored by us is limited. During 2019,

approximately 70 employees accrued benefits under these plans, all of whom were union
employees. Effective December 31, 2015, the plans were amended such that participants other than
union employees no longer earn benefits for service after December 31, 2015.

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.

Obligations and Funded Status of our Defined Benefit Plans

The following tables show the amounts recognized in our balance sheets related to pension and

postretirement benefit plans, as well as plans that we or our subsidiaries sponsor, and their funding
status, obligations and plan asset fair values:

2018
2019
Pension Benefits

As of December 31,
2019

2018

Postretirement Benefits

Amounts recognized in the balance sheet:

Accrued liabilities
Other long-term liabilities

Amounts recognized in accumulated other
comprehensive (loss) income

— $
(18)

(18)

(6)

(in millions)

— $
(14)

(14)

(10)

(3)
(113)

(116)

(17)

(2)
(82)

(84)

127

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 (gain)
Cost of special termination benefits
Curtailment
Benefits paid

Benefit obligation—end of year

Changes in plan assets:
Fair value of plan assets—beginning of year

Actual gain (loss) on plan assets
Employer contributions
Benefits paid

Fair value of plan assets—end of year

Unfunded status

As of December 31,
2019
2018
Pension Benefits

2019

2018

Postretirement Benefits

56 $

65 $

84 $

(in millions)

1
2
11
—
—
(25)

1
2
(2)
—
—
(10)

4
4
19
6
2
(3)

45 $

56 $

116 $

42 $

7
3
(25)

27 $

(18) $

46 $
(2)
8
(10)

42 $

(14) $

— $
—
3
(3)

— $

(116) $

(84)

4
4
(14)
—
—
(3)

—
—
3
(3)

—

The following table sets forth our defined benefit pension plans with accumulated benefit

obligations in excess of plan assets for the years ended December 31:

Projected Benefit Obligation
Accumulated Benefit Obligation
Fair Value of Plan Assets

2019

2018

(in millions)
45 $
41 $
27 $

56
53
42

$
$
$

None of our defined benefit pension plans had plan assets in excess of accumulated benefit

obligations.

128

Components of Net Periodic Benefit Cost

The following tables set forth our pension and postretirement benefit costs and amounts

recognized in other comprehensive income (loss) (before tax):

2019

For the years ended December 31,
2018
Pension Benefits

2019
2018
Postretirement Benefits

2017

(in millions)

Net periodic benefit costs:

Service cost—benefits earned
during the period
Interest cost on projected
benefit obligation
Expected return on plan
assets
Cost of special termination
benefits
Amortization of net actuarial
loss
Settlement costs

1 $

4 $

(2)

—

1
9

(3)

—

2
4

(3)

—

2
5

—

—
—

—

—
—

Net periodic benefit cost

11 $

6 $

7 $

14 $

8 $

—

—
—

2019

2018
Pension Benefits

For the years ended December 31,
2018
Postretirement Benefits

2019

2017

(in millions)

Amounts recognized in other
comprehensive income (loss):
Net actuarial (loss) gain
Settlement costs
Amortization of net actuarial
gain/loss

(6) $
9

(3) $
4

(4) $
5

(19) $
(2)

14 $
—

—

(12)
—

—

Total recognized in other
comprehensive income (loss) $

4 $

3 $

(21) $

14 $

(12)

Settlement costs related to our pension plans were associated with early retirements.

129

The following table sets forth the weighted-average assumptions used to determine our benefit

obligations and net periodic benefit cost:

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

For the years ended December 31,

2019
2018
Pension Benefits

2019

2018

Postretirement Benefits

3.16%
4.00%

4.22%
6.50%
4.00%

4.22%
4.00%

3.53%
6.50%
4.00%

3.48%
—

4.57%
—
—

4.57%
—

3.87%
—
—

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 2019 and 2018. The weighted-
average rate of increase in future compensation levels is consistent with our past and anticipated
future compensation increases for employees participating in retirement 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.

Effective in 2019, we adopted the Society of Actuaries Pri-2012 mortality assumptions reflecting

the MP-2019 Mortality Improvement Scale, which plan sponsors in the U.S. use in the actuarial
valuations that determine a plan sponsor’s pension and postretirement obligations. In 2018, we utilized
the Society of Actuaries Adjusted RP-2014 Mortality Table reflecting the MP-2018 Mortality
Improvement Scale. At December 31, 2019, the changes in the mortality assumptions did not
significantly change the pension benefit obligations or the postretirement benefit obligations.

The postretirement benefit obligation was determined by application of the terms of medical and

dental benefits, including the effect of established maximums on covered costs, together with relevant
actuarial assumptions and healthcare cost trend rates projected at an assumed U.S. Consumer Price
Index (CPI) increase of 1.86% and 1.78% as of December 31, 2019 and 2018, 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, 2019, health care cost trend rates would decrease 0.25% per year from 6.50% in 2020
until they reach 4.50% in 2028 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 Pension 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 2019 and 2018, 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.

130

The fair values of our pension plan assets by asset category are as follows:

Guaranteed deposit account

Total pension plan assets

Asset Class:
Cash equivalents
Commingled funds:
Fixed income
U.S. equity
International equity

Mutual funds:
Bond funds
Blend funds
Value funds
Growth funds

Asset Class:
Cash equivalents
Commingled funds:
Fixed income
U.S. equity
International equity

Mutual funds:
Bond funds
Blend funds
Value funds
Growth funds

Fair Value Measurements at
December 31, 2019

Level 1

Level 2

Level 3

Total

(in millions)

— $

—

—
—
—

5
2
2
2
—

3
4
2

—
—
—
—
—

—
—
—

—
—
—
—
7

3
4
2

5
2
2
2
7

Fair Value Measurements at
December 31, 2018

Level 1

Level 2

Level 3

Total

(in millions)

— $

—
—
—

5
2
2
2
—

9
9
5

—
—
—
—
—

—
—
—

—
—
—
—
7

9
9
5

5
2
2
2
7

Guaranteed deposit account

Total pension plan assets

The activity during the years ended December 31, 2019 and 2018, for the assets using Level 3 fair

value measurements was insignificant.

131

Expected Cash Flows

In 2020, we expect to contribute $4 million to our postretirement benefit plans and at least our

minimum funding requirement of $2 million to our defined benefit pension plans. Estimated future
undiscounted benefit payments, which reflect expected future service, as appropriate, are as follows:

For the years ended December 31,

2020
2021
2022
2023
2024
2025 - 2029

Pension
Benefits

Postretirement
Benefits

(in millions)
$
10
$
4
$
2
$
3
$
2
$
11

4
5
5
5
5
27

$
$
$
$
$
$

NOTE 15 REVENUE RECOGNITION

We account for revenue in accordance with ASC 606, Revenue from Contracts with Customers,
which we adopted on January 1, 2018 using the modified retrospective method, which was applied to
all contracts that were not completed as of that date. Prior period results were not adjusted and
continue to be reported under the accounting standards in effect for the applicable period. The new
standard did not affect the timing of our revenue recognition and did not impact net income;
accordingly, we did not record an adjustment to the opening balance of retained earnings.

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

The following is a description of our principal activities from which we generate revenue.
Revenues are recognized when control of promised goods is transferred to our customers, in an
amount that reflects the consideration we expect to receive in exchange for those goods.

Commodity Sales Contracts

We recognize revenue from the sale of our oil, natural gas and NGL production when delivery has

occurred and control passes to the customer. Our commodity contracts 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. These costs were previously offset against oil and natural gas sales.
Upon adoption of ASC 606, we are recording these costs as a component of other expenses, net 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
invoicing.

132

Electricity

The electrical output of the Elk Hills power plant that is not used in our operations is sold to the

wholesale power market and to a utility under power purchase and sales agreements (PPAs) through
December 2023, which include 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 with our customer are satisfied; generally, this occurs upon delivery of the electricity. We
report electricity sales as other revenue on our consolidated statements of operations. Revenue is
measured as the amount of consideration we expect to receive based on average index or California
Independent System Operator market pricing with payment due the month following delivery.
Payments under our PPAs 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.

Marketing, Trading and Other

Marketing, trading and other revenue primarily includes our activities associated with storing,

transporting and marketing our production as well as third-party volumes.

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 consider our performance
obligations to be satisfied upon transfer of control of the commodity.

We report our trading activities on a gross basis with purchases and costs reported in other

expenses, net and sales recorded in other revenue on our consolidated statements of operations.

Disaggregation of Revenue

The following table provides disaggregated revenue for the years ended December 31, 2019,

2018 and 2017:

Oil and natural gas sales:

Oil
NGLs
Natural gas

Other revenue:
Electricity
Marketing, trading and other
Interest income

Net derivative (loss) gain from commodity contracts

2019

2018

(in millions)

2017

1,884
179
207

2,270

112
311
—

423
(59)

2,110
260
220

2,590

111
361
1

473
1

1,549
210
177

1,936

125
35
—

160
(90)

Total revenues

2,634

3,064

2,006

133

NOTE 16 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our Credit Facilities, Second Lien Notes and Senior Notes are guaranteed both fully and
unconditionally and jointly and severally by our material wholly owned subsidiaries (Guarantor
Subsidiaries). Certain of our subsidiaries do not guarantee our Credit Facilities, Second Lien Notes and
Senior Notes (Non-Guarantor Subsidiaries) either because they hold assets that are less than 1% of
our total consolidated assets or because they are not considered a “subsidiary” under the applicable
financing agreement. The following condensed consolidating balance sheets as of December 31, 2019
and December 31, 2018 and the condensed consolidating statements of operations and statements of
cash flows for the years ended December 31, 2019 and 2018, as applicable, reflect the condensed
consolidating financial information of our parent company, CRC (Parent), our combined Guarantor
Subsidiaries, our combined Non-Guarantor Subsidiaries and the elimination entries necessary to arrive
at the information for the Company on a consolidated basis.

The financial information may not necessarily be indicative of results of operations, cash flows or

financial position had the Guarantor Subsidiaries operated as independent entities.

134

Total current assets
Investments in consolidated

subsidiaries

Total property, plant and

equipment, net

Other assets

TOTAL ASSETS

Condensed Consolidating Balance Sheets
As of December 31, 2019 and 2018
(in millions)

As of December 31, 2019

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

8 $

436 $

60 $

(13) $

491

5,956

223

35
1

5,846
82

—

471
32

(6,179)

—

6,000 $

6,587 $

563 $

(6,192) $

—
—

Total current liabilities
Long-term debt
Deferred gain and issuance costs,

net

Other long-term liabilities
Amounts due to (from) affiliates
Mezzanine equity
Total equity

248
4,877

146
167
951
—
(389)

469
—

—
549
(953)
—
6,522

5
—

—
4
2
802
(250)

(13)
—

—
—
—
—
(6,179)

TOTAL LIABILITIES AND EQUITY $

6,000 $

6,587 $

563 $

(6,192) $

6,958

As of December 31, 2018

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

7 $

590 $

56 $

(13) $

640

5,440

23
4

5,913
32

—

519
27

(5,536)

—

5,474 $

6,631 $

602 $

(5,549) $

Total current assets
Investments in consolidated

subsidiaries

Total property, plant and

equipment, net

Other assets

TOTAL ASSETS

Total current liabilities
Long-term debt
Deferred gain and issuance costs,

net

Other long-term liabilities
Amounts due to (from) affiliates
Mezzanine equity
Total equity

143
5,251

216
140
85
—
(361)

465
—

—
431
(86)
—
5,821

12
—

—
4
1
756
(171)

(13)
—

—
—
—
—
(5,536)

TOTAL LIABILITIES AND EQUITY $

5,474 $

6,631 $

602 $

(5,549) $

7,158

135

6,352
115

6,958

709
4,877

146
720
—
802
(296)

6,455
63

7,158

607
5,251

216
575
—
756
(247)

Condensed Consolidating Statements of Operations
For the years ended December 31, 2019, 2018 and 2017
(in millions)

Total revenues
Total costs
Non-operating (loss) income
Income tax provision

NET (LOSS) INCOME

Net income attributable to
noncontrolling interest

NET (LOSS) INCOME

ATTRIBUTABLE TO COMMON
STOCK

Total revenues
Total costs
Non-operating (loss) income

NET (LOSS) INCOME

Net income attributable to
noncontrolling interest

NET (LOSS) INCOME

ATTRIBUTABLE TO COMMON
STOCK

Total revenues
Total costs
Non-operating (loss) income

NET (LOSS) INCOME

Net income attributable to
noncontrolling interest

NET (LOSS) INCOME

ATTRIBUTABLE TO COMMON
STOCK

For the year ended December 31, 2019

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

— $

186
(332)
(1)

(519)

2,445 $
2,064
3

384

482
248
—

234

—

(127)

$ (293)
(293)
—

—

2,634
2,205
(329)
(1)

(127)

(519) $

384 $

107

$ — $

(28)

For the year ended December 31, 2018

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

1
207
(348)

(554)

2,897 $
2,128
8

777

427
221
—

206

—

(101)

$ (261)
(261)
—

—

3,064
2,295
(340)

429

(101)

(554) $

777 $

105

$ — $

328

For the year ended December 31, 2017

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

42
226
(353)

(537)

1,947
1,694
18

271

17
13
—

—

(4)

$ — $
—
—

—

2,006
1,933
(335)

(262)

(4)

(537)

271

$ —

$ — $

(266)

136

Condensed Consolidating Statements of Cash Flows
For the years ended December 31, 2019, 2018 and 2017
(in millions)

For the year ended December 31, 2019

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

Net cash (used) provided by

operating activities

Net cash used in investing activities
Net cash provided (used) by

financing activities

Decrease (increase) in cash
Cash—beginning of period

Cash—end of period

— $

6 $

Net cash (used) provided by

operating activities

Net cash used in investing activities
Net cash provided (used) by

financing activities

(Decrease) increase in cash
Cash—beginning of period

Cash—end of period

— $

7 $

(673) $
(15)

1,082 $
(378)

267
(1)

$ — $
—

688

—
—

(705)

(265)

(1)
7

—

—
—

$ — $

1
10

676
(394)

(282)

—
17

For the year ended December 31, 2018

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

(633) $
(8)

1,374 $
(1,138)

(280)
(10)

$ — $
—

461
(1,156)

634

(7)
7

(237)

(1)
8

295

5
5

—

—
—

$ — $

692

(3)
20

For the year ended December 31, 2017

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

(481) $
(4)

718 $
(212)

11
(97)

$ — $
—

248
(313)

492

7
—

(510)

(4)
12

5
—

—

—
—

$ — $

8
12

Net cash (used) provided by

operating activities

Net cash used in investing activities
Net cash provided (used) by

financing activities

Increase (decrease) in cash
Cash—beginning of period

Cash—end of period

7 $

8 $

137

NOTE 17 SUBSEQUENT EVENT

On February 20, 2020, we launched offers to exchange a significant portion of our Second Lien

Notes and senior notes into (1) notes and equity interests issued by a non-consolidated entity that will
hold a term royalty interest in our Elk Hills unit and/or (2) a new first-lien last-out term loan issued by us
and warrants convertible into our common stock. The transaction is expected to close on March 20,
2020.

Quarterly Financial Data (Unaudited)

2019
Second Third

First

Fourth

First

Second

Third Fourth

2018

690 $ 653 $ 681 $

610 $

609 $

549 $ 828 $1,078

(in millions, except per share amounts)

57 $ 122 $ 148 $

102 $

108 $

11 $ 185 $ 465

Revenues(a)

Operating income (loss)(b)

Net (loss) income attributable

to common stock(c)

(67) $

12 $

94 $

(67) $

(2) $

(82) $

66 $ 346

Net (loss) income attributable
to common stock per share:
Basic

$ (1.38) $ 0.25 $ 1.89 $ (1.36) $ (0.05) $ (1.70) $ 1.34 $ 7.00

Diluted

$ (1.38) $ 0.24 $ 1.89 $ (1.36) $ (0.05) $ (1.70) $ 1.32 $ 7.00

(a) We adopted the new revenue recognition standard on January 1, 2018 which required certain sales-related costs to be

reported as expense as opposed to being netted against revenue. The adoption of this standard did not affect net income.
Results for reporting periods beginning January 1, 2018 are presented under the new accounting standard while prior
periods were not adjusted and continue to be reported under accounting standards in effect for the applicable period.
(b) Net (loss) income attributable to common stock included the following unusual, out-of-period, infrequent and other items:

2019

2018

First

Second

Third

Fourth

First

Second

Third

Fourth

(in millions)

Non-cash derivative loss (gain)
from commodities, excluding
noncontrolling interest
Non-cash derivative loss from
interest-rate contracts
Severance and termination
benefits
Net gain on early extinguishment
of debt
Gain on asset divestitures
Other, net

$
$
$

97 $

(4) $

6 $

67 $

7 $

92 $

(28) $

(295)

3 $

1 $

— $

1 $

(1) $

— $

2 $

— $

45 $

2 $

— $

(6) $
— $
4 $

(20) $
— $
(4) $

(82) $
— $
(1) $

(18) $
— $
9 $

— $
— $
1 $

(24) $
(1) $
(2) $

(2) $
(3) $
9 $

—

(31)
(1)
1

138

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 PSC-type
contracts relating to our Wilmington field in Long Beach. All of our proved reserves are located within
the state of California.

PROVED DEVELOPED AND UNDEVELOPED RESERVES

Oil(a)
(MMBbl)

NGLs
(MMBbl)

Natural Gas
(Bcf)

Total(b)
(MMBoe)

Balance at December 31, 2016

Revisions of previous estimates(c)
Improved recovery
Extensions and discoveries
Divestitures
Production

Balance at December 31, 2017

Revisions of previous estimates(c)
Improved recovery
Extensions and discoveries
Acquisitions
Production

Balance at December 31, 2018

Revisions of previous estimates(c)
Improved recovery
Extensions and discoveries
Divestitures
Production

Balance at December 31, 2019

PROVED DEVELOPED RESERVES

December 31, 2016

December 31, 2017

December 31, 2018

December 31, 2019(d)

PROVED UNDEVELOPED RESERVES

December 31, 2016

December 31, 2017

December 31, 2018

December 31, 2019

409
47
—
24
(8)
(30)
442
51
4
25
38
(30)
530
(34)
3
24
(11)
(29)
483

279

304

389

357

130

138

141

126

55
7
—
2
—
(6)
58
(4)
—
1
11
(6)
60
(4)
—
2
—
(6)
52

626
104
—
45
(3)
(66)
706
(15)
—
27
89
(73)
734
(52)
—
41
6
(75)
654

500

543

565

543

126

163

169

111

568
71
—
34
(8)
(47)
618
44
4
30
64
(48)
712
(47)
3
33
(10)
(47)
644

406

440

530

493

162

178

182

151

(a)

Includes proved reserves related to economic arrangements similar to PSCs of 125 MMBbl, 131 MMBbl, 108 MMBbl and
85 MMBbl at December 31, 2019, 2018, 2017 and 2016, respectively.

(b) Natural gas volumes have been converted to Boe based on the equivalence of energy content of six Mcf of natural gas to

one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

economically recoverable reserves in all of our operations, because the extra margin extends their expected lives and
renders more projects economic. Partially offsetting this effect, higher prices decrease our share of proved cost recovery
reserves under arrangements similar to production-sharing contracts at our Wilmington field in Long Beach 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.

139

(d) Approximately 24% of proved developed oil reserves, 11% of proved developed NGLs reserves, 13% of proved

developed natural gas reserves and, overall, 21% of total proved developed reserves are non-producing. A majority of our
non-producing reserves relate to steamfloods and waterfloods where full peak production response has not yet occurred
due to the nature of such projects.

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.

We removed 43 MMBoe of PUD 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 PUDs 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

We achieved an organic reserve replacement ratio of 111% from our capital program of

2018

Revisions of previous estimates – Our 2018 realized prices for oil and natural gas increased over

the prior year by 39% and 14%, respectively, which resulted in positive price-related revisions of 38
MMBoe. We also added 6 MMBoe from net positive performance-related revisions of which 27 MMBoe
were from positive technical revisions primarily due to better-than-expected performance and
successful drilling efforts in the San Joaquin and Los Angeles basins.

140

Additionally, at management’s discretion, we removed a total of 21 MMBoe of PUDs that were not

yet expired but that were not anticipated to be developed within their five-year window of initial
booking. Approximately 11 MMBoe of these downgraded PUDs expired in 2019 and were not
anticipated to be developed before then at current oil prices. The remaining 10 MMBoe of downgraded
PUDs were projects that are no longer prioritized in our development plan based on current project
economics.

Improved recovery – We also added 4 MMBoe from improved recovery through proven IOR and
EOR methods. The improved recovery additions were associated with the continued development of
steamflood and waterflood properties in the San Joaquin basin.

Extensions and discoveries – We added 30 MMBoe from extensions and discoveries, primarily

resulting from new geologic interpretations and pressure data in the Ventura basin along with
successful drilling in San Joaquin and Los Angeles basins.

Acquisitions – We also added 64 MMBoe in connection with the acquisitions during the year, the

majority of which resulted from the Elk Hills transaction.

2017

Revisions of previous estimates – Our total net positive price revision was 49 MMBoe, which was

primarily the result of higher prices net of modestly higher operating costs due to the current
commodity price environment, partially reinstating reserves that were removed in prior years due to
lower prices.

Our net positive performance-related revision of 22 MMBoe resulted primarily from the successful

renegotiation of our Huntington Beach royalty agreement and improved performance in the San
Joaquin basin, partially offset by negative revisions to remove proved undeveloped reserves due to a
downward adjustment of our committed capital in a project area and technical revisions due to updated
testing results in one of our project areas.

Extensions and discoveries – We added 34 MMBoe of proved reserves primarily from extensions,

which were associated with the continued successful drilling program mostly in the San Joaquin and
Los Angeles basins. Our drilling program in the San Joaquin basin benefited from the deployment of
JV capital at Elk Hills and at waterflood projects in Buena Vista. Our drilling program in the Los
Angeles basin resulted in expanded economic inventory due to improvements in performance
compared to 2016. We also added new projects in the Sacramento basin as a result of analyzing new
data from capital workover projects.

Divestitures – We sold 8 MMBoe of proved reserves based on beginning-of-year reserves
balances. Included in this amount was 7 MMBoe of proved undeveloped reserves in the San Joaquin
basin conveyed to MIRA as part of our JV with MIRA. There were no material reserves added from
improved recovery.

141

CAPITALIZED COSTS

Capitalized costs relating to oil and natural gas producing activities and related accumulated

depreciation, depletion and amortization (DD&A) were as follows:

Proved properties
Unproved properties

Total capitalized costs(a)

Accumulated depreciation, depletion and amortization(b)

Net capitalized costs

As of December 31,
2018
2019

(in millions)
$

21,285
1,055

22,340
(16,300)

20,883
1,103

21,986
(15,839)

6,040

6,147

(a)
(b)

Includes acquisition and development costs.
Includes accumulated valuation allowance for total unproved properties of $823 and $819 million at December 31, 2019
and 2018, respectively.

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:

For the years ended December 31,
2018
(in millions)

2019

2017

Property acquisition costs
Proved properties(a)
Unproved properties

Exploration costs
Development costs(b)

Costs incurred

1
4
30
505

540

553
1
38
652

1,244

—
—
25
357

382

(a) Acquisition costs capitalized to proved properties include $8 million of liabilities assumed related to ARO in 2018.
(b) Development costs include a $80 million increase, $7 million decrease and a $5 million decrease in ARO in 2019, 2018

and 2017, respectively. Development costs in 2019 reflect an allocation related to a warrant issued in connection with the
Alpine JV of $3 million.

142

RESULTS OF OPERATIONS

Our oil and natural gas producing activities, which exclude items such as asset dispositions,

corporate overhead and interest, were as follows:

For the years ended December 31,
2018

2019

2017

Revenues(b)
Production costs(c)
General and administrative

expenses(d)

Other operating expenses(e)
Depreciation, depletion and

amortization

Taxes other than on income
Exploration expenses

Pretax income
Income tax expense(f)

($/Boe)(a)

(millions)
($/Boe)(a)
$ 2,377 $ 50.88 $ 2,359 $ 48.84 $ 1,929 $ 41.04
18.64

($/Boe)(a)

(millions)

19.16

18.88

912

876

895

56
71

439
121
29

1.20
1.52

9.40
2.59
0.62

49
51

469
117
34

1.01
1.07

9.71
2.42
0.70

33
26

510
110
22

766
(205)

16.39
(4.39)

727
(180)

15.05
(3.85)

352
(115)

0.70
0.56

10.85
2.34
0.47

7.48
(2.45)

Results of operations

561 $ 12.00 $

547 $ 11.20 $

237 $

5.03

(a) 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.

(b) Revenues include cash settlements on our commodity derivatives which are reported in net derivative (gain) loss from

commodity contracts on our consolidated statements of operations.

(c) Production 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. Production costs on a per Boe basis, excluding the effects of PSC
contracts, were $17.70, $17.47 and $17.48 for 2019, 2018 and 2017, respectively.

(d) For the year ended December 31, 2017, certain pension benefit costs of $1 million have been reclassified to other

non-operating expenses to conform to the current year presentation in accordance with new accounting rules adopted on
January 1, 2018 related to the presentation of net periodic benefit costs for pension and postretirement benefits in the
Consolidated Statements of Operations.

(e) Other operating expenses include accretion expense in 2019, 2018 and 2017. Other operating expenses include

(f)

transportation costs beginning in 2018 due to the adoption of a new accounting standard related to revenue recognition.
Income taxes are calculated on the basis of a stand-alone tax filing entity. The combined U.S. federal and California
statutory tax rate for 2019 and 2018 was 28% and 41% in 2017. The top corporate tax rate was reduced beginning
January 1, 2018 as a result of tax reform legislation enacted on December 22, 2017. The effective tax rate for 2018 and
2017 reflects the benefit of enhanced oil recovery tax credits.

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, 2019, 2018 and
2017, 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, 2019, 2018 and 2017. 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.

143

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows
Future costs

Production costs(a)
Development costs(b)
Future income tax expense

Future net cash flows
Ten percent discount factor

2019

At December 31,
2018
(in millions)

2017

34,134 $ 42,325 $ 26,685

(16,724)
(3,938)
(3,180)

10,292
(5,061)

(19,452)
(4,432)
(4,231)

14,210
(6,935)

(13,988)
(3,848)
(1,585)

7,264
(3,499)

Standardized measure of discounted future net cash flows

5,231 $

7,275 $

3,765

(a)
(b)

Includes general and administrative expenses 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

For the years ended December 31,
2018
(in millions)

2019

2017

Beginning of year

7,275 $

3,765 $

2,667

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
Changes in production rates and other

Net change

End of year

(a)

Includes revisions related to performance and price changes.

(1,198)
(1,998)
556
(283)
433
(638)
890
518
(151)
(173)

(2,044)

(1,511)
3,648
351
(38)
443
738
427
(1,356)
766
42

3,510

5,231 $

7,275 $

(918)
1,405
159
(98)
177
737
260
(599)
(43)
18

1,098

3,765

144

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, 2019 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, 2019, 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, 2019, 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.

145

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 that have materially affected, or are reasonably
likely to materially affect, our internal control over financial reporting.

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that
any controls and procedures, no matter how well designed and operated, can provide only reasonable
assurance of achieving the desired control objectives.

ITEM 9B

OTHER INFORMATION

None.

146

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 2020 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange
Commission (SEC) within 120 days of the fiscal year ended December 31, 2019 (2020 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

Todd A. Stevens

President, Chief Executive Officer and Director since 2014;
Occidental Petroleum Corporation Vice President -
Corporate Development 2012 to 2014; Oxy Oil & Gas Vice
President - California Operations 2008 to 2012; Occidental
Petroleum Corporation Vice President - Acquisitions and
Corporate Finance 2004 to 2012.
Marshall D. Smith Senior Executive Vice President and Chief Financial

Shawn M. Kerns

Officer since 2014; Ultra Petroleum Corporation Senior
Vice President and Chief Financial Officer 2011 to 2014;
Ultra Petroleum Corporation Chief Financial Officer 2005
to 2014.
Executive Vice President - Operations and Engineering
since 2018; 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.

Francisco J. Leon Executive Vice President - Corporate Development and
Strategic Planning since 2018; Vice President - Portfolio
Management and Strategic Planning 2014 to 2018;
Occidental Director - Portfolio Management 2012 to 2014;
Occidental Director of Corporate Development and M&A
2010 to 2012; Occidental Manager of Business
Development 2008 to 2010.
Executive Vice President - Finance since 2014; Occidental
Vice President and Controller 2008 to 2014; Occidental Oil
and Gas Senior Vice President 2007 to 2008.

Roy M. Pineci

Age at
February 26, 2020

147

Name

Employment History

Michael L. Preston Senior Executive Vice President, Chief Administrative

Charles F. Weiss

Darren Williams

Officer and General Counsel - 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 - Public Affairs since 2014;
Occidental Vice President, Health, Environment and
Safety 2007 to 2014.
Executive Vice President - Operations and Geoscience
since 2018; Executive Vice President - Exploration 2014 to
2018; Marathon Upstream Gabon Limited President and
Africa Exploration Manager 2013 to 2014; Marathon Oil
Oklahoma Subsurface Manager 2010 to 2013; Marathon
Oil Gulf of Mexico Exploration and Appraisal Manager
2008 to 2010.

Age at
February 26, 2020

ITEM 11

EXECUTIVE COMPENSATION

The information required by this item is incorporated by reference from our 2020 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 2020 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 2020 Proxy Statement.

ITEM 14

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated by reference from our 2020 Proxy Statement.

148

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:

(cid:129)

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;

(cid:129) may apply standards of materiality in a way that is different from the way the Company and

investors may view materiality; and

(cid:129)

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

3.1

3.2

4.1

4.2

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 Registrant’s Current Report on Form 8-K filed December 1, 2014 and
incorporated herein by reference).

Amended and Restated Certificate of Incorporation of California Resources Corporation
(filed as Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed June 3, 2016 and
incorporated herein by reference).

Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2
to the Registrant’s Current Report on Form 8-K filed November 10, 2015 and
incorporated herein by reference).

Indenture, dated October 1, 2014, by and among California Resources Corporation, the
Guarantors and Wells Fargo Bank, National Association (filed as Exhibit 4.2 to
Amendment No. 4 to the Registrant’s Information Statement on Form 10 filed October 8,
2014 and incorporated herein by reference).

Indenture, dated December 15, 2015, by and among California Resources Corporation,
the Guarantors and the Bank of New York Mellon Trust Company, N.A. (filed as
Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed December 18, 2015 and
incorporated herein by reference).

149

Exhibit
Number

4.3

4.4

4.5

4.6

4.7

4.8

4.9

4.10

4.11

4.12

4.13

4.14

Exhibit Description

Guarantor Supplemental Indenture dated as of March 5, 2015, among California
Resources Corporation, certain guarantors named therein and Wells Fargo Bank,
National Association (filed as Exhibit 4.2 to Registrant’s Registration Statement on
Form S-4 filed March 12, 2015 and incorporated herein by reference).

Guarantor Supplemental Indenture dated as of March 4, 2016, among California
Resources Corporation, certain guarantors named therein and The Bank of New York
Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to Registrant’s Quarterly
Report on Form 10-Q filed August 4, 2016 and incorporated herein by reference).

Guarantor Supplement Indenture dated as of March 4, 2016, among California
Resources Corporation, certain guarantors named therein and The Bank of New York
Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.2 to Registrant’s Quarterly
Report on Form 10-Q filed August 4, 2016 and incorporated herein by reference).

Guarantor Supplemental Indenture No. 2, dated as of April 29, 2016, among California
Resources Corporation, certain guarantors named therein and Wilmington Trust,
National Association, as trustee (filed as Exhibit 10.4 to Registrant’s Quarterly Report on
Form 10-Q filed August 4, 2016 and incorporated herein by reference).

Assumption Agreement dated as of March 6, 2015, among CRC Construction Services,
LLC and JP Morgan Chase Bank, N.A., as Administrative Agent for lenders (filed as
Exhibit 10.31 to Registrant’s Registration Statement on Form S-4 filed March 12, 2015
and incorporated herein by reference).

Registration Rights Agreement, dated October 1, 2014, by and among California
Resources Corporation, the Guarantors and the Initial Purchasers (filed as Exhibit 4.3 to
Amendment No. 4 to the Registrant’s Information Statement on Form 10 filed October 8,
2014 and incorporated herein by reference).

Form of 5% Senior Note due 2020 (included in Exhibit 4.2 to Amendment No. 4 to the
Registrant’s Information Statement on Form 10 filed October 8, 2014 and incorporated
herein by reference).
Form of 5 1⁄ 2% Senior Note due 2021 (included in Exhibit 4.2 to Amendment No. 4 to the
Registrant’s Information Statement on Form 10 filed October 8, 2014 and incorporated
herein by reference).

Form of 6% Senior Note due 2024 (included in Exhibit 4.2 to Amendment No. 4 to the
Registrant’s Information Statement on Form 10 filed October 8, 2014 and incorporated
herein by reference).

Form of 8% Senior Secured Second Lien Note due 2022 (included in Exhibit 4.1 to
Registrant’s Current Report on Form 8-K filed December 18, 2015 and incorporated
herein by reference).

Registration Rights Agreement, dated as of April 9, 2018, by and between California
Resources Corporation and Chevron U.S.A. Inc. (filed as Exhibit 4.01 to the Registrant’s
Current Report on Form 8-K filed April 9, 2018, and incorporated herein by reference).

Guarantor Supplemental Indenture, dated as of April 16, 2018, among California
Resources Corporation, certain guarantors named therein and The Bank of New York
Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to the Registrant’s Quarterly
Report on Form 10-Q filed August 2, 2018, and incorporated herein by reference).

150

Exhibit
Number

4.15

4.16*

10.1

10.2

10.3

10.4

10.5

10.6

Exhibit Description

Third Guarantor Supplemental Indenture, dated as of June 29, 2018, among California
Resources Corporation, certain guarantors named therein and Wilmington Trust,
National Association, as trustee (filed as Exhibit 4.2 to the Registrant’s Quarterly Report
on Form 10-Q filed August 2, 2018, and incorporated herein by reference).

Description of Registrant’s Securities.

Credit Agreement, dated as of September 24, 2014, among California Resources
Corporation, the Lenders and JPMorgan Chase Bank, N.A. as Administrative Agent, a
Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A. as
Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as
Exhibit 10.25 to Amendment No. 5 to the Company’s Registration Statement on Form
10 filed October 14, 2014, and incorporated herein by reference).

First Amendment to Credit Agreement, dated as of February 25, 2015, among California
Resources Corporation, the Lenders and JPMorgan Chase Bank, N.A. as Administrative
Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A. as
Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as Exhibit
10.35 to the Registrant’s Annual Report on Form 10-K filed February 27, 2015, and
incorporated herein by reference).

Second Amendment to Credit Agreement, dated November 2, 2015, among California
Resources Corporation, the Lenders and JPMorgan Chase Bank, N.A. as Administrative
Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A. as
Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as
Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed November 6, 2015,
and incorporated herein by reference).

Third Amendment to Credit Agreement, dated February 23, 2016, among California
Resources Corporation and JP Morgan Chase Bank, N.A., as Administrative Agent, a
Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A. as
Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as
Exhibit 99.1 to the Registrant’s Current Report on Form 8-K filed February 23, 2016,
and incorporated herein by reference).

Fourth Amendment to Credit Agreement dated as of April 22, 2016, among California
Resources Corporation, as the Borrower and JP Morgan Chase Bank, N.A., as
Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of
America, N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer
(filed as Exhibit 99.1 to the Registrant’s Current Report on Form 8-K filed April 22, 2016,
and incorporated herein by reference).

Fifth Amendment and Waiver to Credit Agreement, dated August 12, 2016, among
California Resources Corporation, as the Borrower and JP Morgan Chase Bank, N.A.,
as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of
America, N.A., as Syndication Agent, a Swingline Lender and a Letter of Credit Issuer
(filed as Exhibit 10.2 to the Registration’s Current Report on Form 8-K filed August 17,
2016 and incorporated herein by reference).

151

Exhibit
Number

10.7

10.8

10.9

10.10

10.11

10.12

10.13

10.14

10.15

10.16

Exhibit Description

Sixth Amendment to Credit Agreement, dated as of February 14, 2017, among
California Resources Corporation, as the Borrower, JP Morgan Chase Bank, N.A., as
Administrative Agent, Swingline Lender and a Letter of Credit Issuer, Bank of America,
N.A., as Syndication Agent, Swingline Lender and a letter of Credit Issuer, and the
Lenders (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed
February 16, 2017, and incorporated herein by reference).

Seventh Amendment to Credit Agreement, dated as of November 9, 2017, among
California Resources Corporation, as the Borrower, JP Morgan Chase Bank, N.A., as
Administrative Agent, Swingline Lender and a Letter of Credit Issuer, Bank of America,
N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed November 13, 2017,
and incorporated herein by reference).

Eighth Amendment to 2014 Credit Agreement, dated August 20, 2018 (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed August 24, 2018 and
incorporated herein by reference).

Credit Agreement, dated August 12, 2016, among California Resources Corporation, as
the Borrower, the several Lenders from time to time parties thereto, Goldman Sachs
Bank USA, as Lead Arranger and Bookrunner, and The Bank of New York Mellon Trust
Company, N.A., as Administrative Agent and Collateral Agent (filed as Exhibit 10.1 to
the Registrant’s Current Report on Form 8-K filed August 17, 2016 and incorporated
herein by reference).

Credit Agreement, dated as of November 17, 2017, by and among the Company, as the
Borrower, Bank of New York Mellon Trust, N.A., as Administrative Agent, and the
various Lenders identified therein (filed as Exhibit 10.1 to the Registrant’s Current
Report on Form 8-K filed November 17, 2017, and incorporated herein by reference).

First Amendment to 2017 Credit Agreement, dated September 18, 2018 (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed September 18, 2018,
and incorporated herein by reference).

Omnibus Amendment, dated September 12 2016, among California Resources
Corporation, the Guarantors party thereto, the Collateral Trustee and the other party lien
representatives party thereto (filed as Exhibit 10.3 to the Registration’s Quarterly Report
on Form 10-Q filed November 3, 2016 and incorporated herein by reference).

Transition Services Agreement, dated November 25, 2014, between Occidental
Petroleum Corporation and California Resources Corporation (filed as Exhibit 10.4 to
Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated
herein by reference).

Tax Sharing Agreement, dated November 25, 2014, between Occidental Petroleum
Corporation and California Resources Corporation (filed as Exhibit 10.2 to Registrant’s
Current Report on Form 8-K filed December 1, 2014 and incorporated herein by
reference).

Employee Matters Agreement, dated November 25, 2014, between Occidental
Petroleum Corporation and California Resources Corporation (filed as Exhibit 10.3 to
Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated
herein by reference).

152

Exhibit
Number

10.17

10.18

10.19

10.20

10.21

10.22

10.23

10.24

10.25

10.26

Exhibit Description

Intellectual Property License Agreement, dated November 25, 2014, between
Occidental Petroleum Corporation and California Resources Corporation (filed as
Exhibit 10.7 to 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
Registrant’s Current Report on Form 8-K filed December 1, 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 Company’s
Registration Statement on Form 10 filed August 20, 2014, and incorporated herein by
reference).

Amendment to the Agreement for Implementation of an Optimized Waterflood Program
for the Long Beach Unit, dated January 16, 2009, by and among the State of California,
by and through the State Lands Commission, the City of Long Beach, and Oxy Long
Beach, Inc. (filed as Exhibit 10.11 to Amendment No. 2 to the Company’s Registration
Statement on Form 10 filed August 20, 2014, 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 Company’s Registration Statement on Form 10 filed
August 20, 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 Company’s Current Report on
Form 8-K filed on December 1, 2014, and incorporated herein by reference).

Second Amended and Restated Limited Liability Company Agreement of Elk Hills
Power, LLC, dated as of February 7, 2018, by and among Elk Hills Power, LLC,
California Resources Elk Hills, LLC and ECR Corporate Holdings L.P. (filed as
Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 7, 2018,
and incorporated herein by reference).

Commercial Agreement, dated as of February 7, 2018, by and between Elk Hills Power,
LLC and California Resources Elk Hills, LLC (filed as Exhibit 10.2 to the Company’s
Current Report on Form 8-K filed on February 7, 2018, and incorporated herein by
reference).

Master Services Agreement, dated as of February 7, 2018, by and between Elk Hills
Power, LLC and California Resources Elk Hills, LLC (filed as Exhibit 10.3 to the
Company’s Current Report on Form 8-K filed on February 7, 2018, and incorporated
herein by reference).

Form of Stock Purchase Agreement, dated as of February 7, 2018 (filed as Exhibit 10.4
to the Company’s Current Report on Form 8-K filed on February 7, 2018, and
incorporated herein by reference).

153

Exhibit
Number

10.27

10.29

10.31

10.32

10.33

10.34

10.35

10.36

10.37*

10.38

10.39

10.40

10.41

Exhibit Description

Registration Rights Agreement, dated as of February 7, 2018, by and between
California Resources Corporation and the purchasers named therein (filed as
Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on February 7, 2018,
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 Long-Term Incentive Plan, 2016 Annual Incentive
Award Summary (filed as Exhibit 10.5 on Registrant’s Quarterly Report on Form 10-Q
filed August 4, 2016 and incorporated herein by reference).

California Resources Corporation Long-Term Incentive Plan Nonstatutory Stock Option
Award Terms and Conditions (filed as Exhibit 10.4 to the Registrant’s Quarterly Report
Form 10-Q filed November 6, 2015, and incorporated herein by reference).

California Resources Corporation Supplemental Savings Plan (filed as Exhibit 10.1 to
the Registrant’s Current Report on Form 8-K filed on December 2, 2014, and
incorporated herein by reference).

First Amendment to California Resources Corporation Supplemental Savings Plan (filed
as Exhibit 10.18 to the Registrant’s Annual Report on Form 10-K filed February 29,
2016, and incorporated herein by reference).

California Resources Corporation Supplemental Retirement Plan II (filed as Exhibit 10.3
to the Registrant’s Current Report on Form 8-K filed on December 2, 2014, and
incorporated herein by reference).

California Resources Corporation Deferred Compensation Plan (filed as Exhibit 10.2 to
the Registrant’s Current Report on Form 8-K filed on December 2, 2014, and
incorporated herein by reference).

California Resources Corporation Long-Term Incentive Plan (filed as Exhibit 4.3 to the
Registrant’s related Registration Statement on Form S-8 filed November 26, 2014 and
incorporated herein by reference).

First Amendment to California Resources Corporation Long-Term Incentive Plan (As
Amended and Restated Effective as of May 4, 2016).

Acknowledgment of Amendment to Long-Term Incentive Award Terms with
William E. Albrecht (filed as Exhibit 10.22 to the Registrant’s Annual Report on
Form 10-K filed February 29, 2016, and incorporated herein by reference).

Form of Nonstatutory Stock Option Award Terms and Conditions (filed as Exhibit 10.6 to
Amendment No. 3 to the Registrant’s Information Statement on Form 10 filed
September 22, 2014 and incorporated herein by reference).

Form of Restricted Stock Unit Award Terms and Conditions (filed as Exhibit 10.6 to the
Registrant’s Quarterly Report on Form 10-Q filed August 4, 2016 and incorporated
herein by reference).

Form of Nonstatutory Stock Option Award Terms and Conditions (filed as Exhibit 10.5 to
the Registrant’s Quarterly Report on Form 10-Q filed November 3, 2016, and
incorporated herein by reference).

154

Exhibit
Number

10.42

10.45

10.50

10.51

10.52

10.53

10.54

10.55

10.56

10.57

10.58

10.59

10.60

Exhibit Description

Form of Performance Incentive Award Terms and Conditions (filed as Exhibit 10.6 to the
Registrant’s Quarterly Report on Form 10-Q filed November 3, 2016, and incorporated
herein by reference).

Form of Restricted Stock Unit Award for Non-Employee Directors Grant Agreement
(filed as Exhibit 10.9 to Amendment No. 3 to the Registrant’s Information Statement on
Form 10 filed September 22, 2014 and incorporated herein by reference).

Form of 2018 Nonstatutory Stock Option Award Terms and Conditions (filed as
Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed May 9, 2018, and
incorporated herein by reference).

Form of 2018 Restricted Stock Unit Award Terms and Conditions (filed as Exhibit 10.2
to the Registrant’s Quarterly Report on Form 10-Q filed May 9, 2018, and incorporated
herein by reference).

Form of 2018 Performance Stock Unit Award Terms and Conditions (filed as
Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed May 9, 2018, and
incorporated herein by reference).

California Resources Corporation 2014 Employee Stock Purchase Plan (filed as
Exhibit 4.3 to the Registrant’s related Registration Statement on Form S-8 filed
November 26, 2014 and incorporated herein by reference).

Form of Indemnification Agreements (filed as Exhibit 10.14 to Amendment No. 3
Registrant’s Information Statement on Form 10 filed September 22, 2014 and
incorporated herein by reference).

First Amendment to the California Resources Corporation 2014 Employee Stock
Purchase Plan effective May 4, 2016 (filed as Annex C-1 to the Registrant’s Definitive
Proxy Statement on Schedule 14A filed March 23, 2016 and incorporated herein by
reference).

Second Amendment to the California Resources Corporation 2014 Employee Stock
Purchase Plan effective May 9, 2018 (incorporated by reference herein to Annex B-1 to
the Registrant’s Definitive Proxy Statement on Schedule 14A (File No. 001-36478) filed
on March 27, 2018).

Form of 2019 Nonstatutory Stock Option Award Terms and Conditions (filed as
Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed May 2, 2019 and
incorporated herein by reference).

Form of 2019 Restricted Stock Unit Award Terms and Conditions (filed as Exhibit 10.2
to the Registrant’s Quarterly Report on Form 10-Q filed May 2, 2019 and incorporated
herein by reference).

Form of 2019 Performance Stock Unit Award Terms and Conditions (filed as
Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q filed May 2, 2018 and
incorporated herein by reference).

California Resources Corporation Long–Term Incentive Plan, as amended and restated
effective as of May 8, 2019 (filed as Exhibit 4.3 to the Registrant’s related Registration
Statement on Form S-8 filed May 9, 2019 and incorporated herein by reference).

155

Exhibit
Number

10.61

10.62

21*

23.1*

23.2*

23.3*

31.1*

31.2*

32.1*

99.1*

99.2*

Exhibit Description

Purchase Warrant for Common Stock, dated July 22, 2019 (filed as Exhibit 4.1 to the
Registrant’s Current Report on Form 8-K filed July 23, 2019 and incorporated herein by
reference).

Ninth Amendment to Credit Agreement, dated as of August 28, 2019, among California
Resources Corporation, as the Borrower, JP Morgan Chase Bank, N.A., as
Administrative Agent, Swingline Lender and a Letter of Credit Issuer, Bank of America,
N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer (filed as
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed September 3, 2019,
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.

Consent of Independent Petroleum Engineers, Netherland, Sewell & Associates.

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 Estimated Future Reserves Attributable to Certain Leasehold and
Royalty Interests as of December 31, 2019.

Netherland, Sewell & Associates Estimated Future Reserves Attributable to Certain
Leasehold and Royalty Interests as of December 31, 2019.

101.INS*

Inline XBRL Instance Document.

101.SCH*

Inline XBRL Taxonomy Extension Schema Document.

101.CAL*

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*

Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF*

Inline XBRL Taxonomy Extension Definition Linkbase Document.

104

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

* - Filed herewith.

156

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 26, 2020

By:

/s/ Todd A. Stevens

Todd A. Stevens
President
and Chief Executive Officer

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.

/s/ Todd A. Stevens

Todd A. Stevens

/s/ Marshall D. Smith

Marshall D. Smith

/s/ Roy Pineci

Roy Pineci

/s/ William E. Albrecht

William E. Albrecht

/s/ Justin A. Gannon

Justin A. Gannon

/s/ Harry T. McMahon

Harry T. McMahon

/s/ Richard W. Moncrief

Richard W. Moncrief

/s/ Avedick B. Poladian
Avedick B. Poladian

/s/ Anita M. Powers

Anita M. Powers

/s/ Laurie A. Siegel

Laurie A. Siegel

/s/ Robert V. Sinnott

Robert V. Sinnott

Title

Date

President,
Chief Executive Officer and Director

February 26, 2020

Senior Executive Vice President and
Chief Financial Officer

February 26, 2020

Executive Vice President -Finance and
Principal Accounting Officer

February 26, 2020

Chairman of the Board

February 26, 2020

Director

157

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Annual Meeting

Investor Relations

California Resources Corporation’s annual meeting
of stockholders will be held at 11:00 a.m. on May 6,
2020 at the Bakersfield Marriott at the Convention
Center located at 801 Truxtun Avenue, Bakersfield,
California 93301.

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.

999
1
0
2

Officers

Board of Directors

Todd A. Stevens
President, Chief Executive Officer and Director

Michael L. Preston
Senior Executive Vice President, Chief Administrative
Officer and General Counsel

Marshall D. Smith
Senior Executive Vice President and Chief Financial Officer

Shawn M. Kerns
Executive Vice President, Operations and Engineering

Francisco J. Leon
Executive Vice President, Corporate Development and
Strategic Planning

Roy M. Pineci
Executive Vice President, Finance

Charles F. Weiss
Executive Vice President, Public Affairs

Darren Williams
Executive Vice President, Operations and Geoscience

William E. Albrecht
Chairman of the Board, Former Vice President,
Occidental Petroleum Corporation

Justin A. Gannon
Former Regional Managing Partner, Grant Thornton LLP

Harold M. Korell
Lead Independent Director, Former Chairman of the Board,
Southwestern Energy Company

Harry T. McMahon
Former Executive Vice Chairman, Bank of America Merrill Lynch

Richard W. Moncrief
Chairman of the Board and Chief Executive Officer,
Moncrief Oil International

Avedick B. Poladian
Former Executive Vice President and Chief Operating Officer,
Lowe Enterprises

Anita M. Powers
Former Executive Vice President of Worldwide Exploration,
Occidental Oil and Gas Corporation and Vice President,
Occidental Petroleum Corporation

Laurie A. Siegel
President, LAS Advisory Services

Robert V. Sinnott
Co-Chairman, Kayne Anderson Capital

This Annual Report is printed on Forest Stewardship
Council®-certiﬁed paper that contains wood and wood fibre
from well-managed forests and other responsible sources.

Todd A. Stevens
President, Chief Executive Officer and Director,
California Resources Corporation

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