California Resources Annual Report 2018

FY2018 Annual Report · California Resources

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CALIFORNIA RESOURCES CORPORATION
2018 ANNUAL REPORT

FINANCIAL AND OPERATIONAL
HIGHLIGHTS

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

Financial Highlights

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

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

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

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

8
1
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)(c)

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

Weighted-Average Shares Outstanding(b)
Year-End Shares

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

Operational Highlights

Closing Share Price

2018

$
$
$
$
$

$
$

$
$
$
$

3,064
429
101
328
61

6.77
1.27

461
690
26
692

7,158
5,251
216
(247)

47.4
48.7

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

2016

$ 1,547
$
201
$
$
$

279
(317)

$
$

$
$
$
$

6.76
(7.85)

130
75
73
(69)

$ 6,354
$ 5,168
397
$
(557)
$

40.4
42.5

2018

2017

2016

82
16
202
132

$
$
$
$

62.60
70.11
43.67
3.00

530
60
734
712

127%
9.4

701
1,539
2,240

83
16
182
129

$ 51.24
$ 51.47
$ 35.76
2.67
$

442
58
706
618

91
16
197
140

$ 42.01
$ 39.72
$ 22.39
2.28
$

409
55
626
568

71%
2.8

119%
4.5

703
1,550
2,253

717
1,614
2,331

17.04

$ 19.44

$ 21.29

(a) See www.crc.com, Investor Relations for a discussion of these non-GAAP measures, including a reconciliation to the most closely related GAAP measure or information on the related calculations. (b) Share amounts presented on post-split basis.
(c) 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.
All statements, other than statements of historical fact, included in this report that address activities, events or developments that we believe will or may occur in the future are forward-looking statements. The words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “goal,” “intend,” “likely,”
“may,” “might,” “plan,” “potential,” “project,” “seek,” “should,” “target,” “will” or “would” or other similar expressions identify forward-looking statements. Such statements speciﬁcally include our expectations as to our: future ﬁnancial position • liquidity • cash ﬂows • results of operations • business
prospects • budgets • transactions • projects • operating costs • operations and operational results • maintenance capital requirements • reserves. Factors (but not necessarily all factors) that could cause our results to differ include: commodity price changes • debt limitations on our ﬁnancial ﬂexibility
• insufﬁcient cash ﬂow to fund planned investment • inability to enter desirable transactions including asset sales and joint ventures • legislative or regulatory changes • insufﬁcient capital • unexpected geologic conditions • changes in business strategy • inability to replace reserves • inability to enter
efﬁcient hedges • equipment, service or labor price inﬂation or unavailability • limitations on necessary permits and approvals • worse-than-expected results of development or acquisitions • disruptions from accidents, mechanical failures, transportation or storage constraints, natural disasters, labor
difﬁculties, cyber-attacks, and other catastrophic events • other risk factors as discussed in our Annual Report on Form 10-K. Forward-looking statements speak only as of the date on which made and we undertake no obligation to correct or update such statements, except as required by applicable law.

A MESSAGE TO OUR SHAREHOLDERS

Dear Shareholder,

California continued its strong demand for energy and petroleum products in 2018. As the world’s
fifth largest economy, California consumes every drop of oil and natural gas produced in the state and
imports approximately 90% of the natural gas, 74% of the oil and 30% of the electricity it consumes.
California Resources Corporation (CRC) remains well-positioned to develop California’s vast oil and
natural gas resources in a safe and responsible manner to make our state’s energy future more
sustainable, self-sufficient and secure. Produced under the most stringent safety, labor, human rights
and environmental standards, the native oil and natural gas production that CRC provides helps
California reduce its reliance on imported petroleum from around the world. Native production also
increases access to reliable and affordable energy and provides thousands of good local careers for a
diverse workforce of Californians from all educational backgrounds.

CRC benefits from a world-class asset base and a team that has been pressure-tested. In 2018,

we relied upon our flexible business model, the optionality of our portfolio and our differentiated
integrated infrastructure to successfully respond to a variety of pricing conditions. Throughout the year,
we remained dedicated to our value-driven strategy that centers on 1) capturing the full value of our
portfolio; 2) driving operational excellence; 3) ensuring effective capital allocation; and 4) strengthening
the balance sheet. As a result, CRC delivered a strong performance for 2018, which included profitable
production growth supported by increased activity, managed operating costs, a strategic and accretive
acquisition, as well as reserves growth over 2017 levels.

In 2018, CRC’s dynamic capital program increased to our highest level as a public company to
address production declines and deliver organic oil production growth in the second half of the year.
Utilizing $641 million of internally funded capital, supplemented by $106 million of joint venture (JV)
capital, CRC generated value-driven organic growth, which yielded higher average total production
year-over-year and reflected a healthy Value Creation Index (VCI)1 of 1.5 based on a $60 Brent price
deck for 2018. Prioritizing capital investment toward oil-focused opportunities, we increased reserves
to 712 million barrels of oil equivalent (BOE) and delivered a strong all-in reserve replacement ratio of
296%, reflecting 127% from the capital program alone, while adding to our inventory and actionable
projects. We also reduced operating costs on a per barrel basis each quarter sequentially throughout
the year and enhanced our overall margin performance for 2018. As a result, we ended 2018 in a
strengthened position with production growth in the second half of the year and annual adjusted
EBITDAX1 of $1.1 billion, growing an impressive 43% compared to the prior year.

Complementing our operational focus on safety, quality, innovation and efficiency in 2018, CRC

completed two major transactions early in the year that earned a S&P Global Platts Energy Award for
“Corporate Deal of the Year” from among a global array of transactions across the energy sector. In
February of 2018, we contributed our Elk Hills power and gas processing assets into a midstream JV
with a portfolio company of Ares Management, L.P. in exchange for $750 million. This strategic move
allowed CRC to monetize midstream assets that were not being fully valued by the market, deploy the
proceeds toward debt reduction and acquire the remaining working, surface and mineral interests at
our flagship Elk Hills field. Completed with $460 million in cash and the issuance of 2.85 million shares
of CRC common stock, the Elk Hills acquisition immediately added value to CRC, improving both cash
flow and credit metrics, in addition to delivering approximately $34 million of annualized synergies from
consolidated operations by the end of 2018 — well ahead of initial expectations.

We also continued ongoing debt reduction efforts by opportunistically repurchasing $232 million of

face value of our debt at a discount for $199 million in 2018. As we demonstrated in each of the past
four years, CRC’s balance sheet strengthening activities center on prioritizing the best value
alternatives that further our goals to reduce overall levels of debt, simplify our capital structure and

enhance our credit metrics. With many options available, we will continue to be thoughtful in our
approach and disciplined in our execution for maximum benefit to our shareholders as we move toward
our long-term leverage target.

At CRC, we pursue opportunities and investments that play to our strength as California’s operator

of choice and lead with our deep experience of operating successfully within California’s prolific,
stacked reservoirs, multiple drive mechanisms and comprehensive regulatory system. Our workforce
comes from our state’s diverse communities and their dedication and hard work provide energy that is
essential to a beneficial, affordable quality of life for all Golden State residents. CRC’s workforce
prioritizes safeguarding people and the environment, and we achieved our annual safety,
environmental stewardship and water conservation targets in 2018. Our workforce earned one of its
highest safety ratings in the history of our operations and received 14 National Safety Council awards.
We served as a net water supplier once again, delivering a record 5.3 billion gallons of treated,
reclaimed water to agricultural water districts in 2018. In addition, our team continued to advance
projects to attain our 2030 Sustainability Goals for water, renewables, methane and carbon. A key
example is CRC’s strategic project at Elk Hills to design carbon capture technologies to enhance oil
production, while sequestering carbon dioxide in oil and gas formations, which would contribute
meaningfully to meeting the state’s long-term sustainability goals.

In 2019, CRC will continue to execute our value-driven strategy with dynamic operating and capital

plans that can be quickly adjusted to match prevailing market conditions. We will utilize our technical
knowledge and experience to target high-margin production and reserves that will enhance value and
strengthen the balance sheet. With our disciplined capital allocation approach, diverse asset base and
a workforce dedicated to sustained operational excellence in providing energy for California by
Californians, CRC represents a compelling investment that is set to deliver long-term value creation for
our shareholders for years to come.

Regards,

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

See the Investor Relations page at www.crc.com for explanations of how CRC calculates and uses the non–GAAP measure
of adjusted EBITDAX and a reconciliation to its nearest GAAP measure, and for other important information about possible
and probable reserves and other hydrocarbon resource quantities and recycle ratio calculations. 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.

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, 2018

‘ 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 315
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

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 Í No ‘

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
Yes Í No ‘
required to submit such files).

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and

will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K. Í

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

$2.2 billion, computed by reference to the closing price on the New York Stock Exchange composite tape of $45.44 per share
of Common Stock on June 30, 2018. 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, 2019, there were 48,650,420 shares of Common Stock outstanding.

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

connection with the registrant’s 2019 Annual Meeting of Stockholders, are incorporated by reference into Part III of this
Form 10-K.

DOCUMENTS INCORPORATED BY REFERENCE

TABLE OF CONTENTS

Part I

Items 1 & 2 BUSINESS AND PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Operations and Environment
Our Business Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Strengths . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . .
Spin-Off and Reverse Stock Split . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MINE SAFETY DISCLOSURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXECUTIVE OFFICERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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 . . . . . . . . . .
Business Environment and Industry Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Seasonality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Joint Ventures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production and Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Operations Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 and 2019 Capital Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Off-Balance-Sheet Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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

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5
6
8
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19
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22
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31
31
32
42
42
42
43

44
46

47
47
47
49
49
50
51
53
55
56
63
67
69
70
71
71
72
73

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) . . . . . . . . . . . . . . . . . . . . . .
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS . . . . . . . . . . . . . . .
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . .
CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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

Page

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119
120
125

126
126
127

128
128

128

128
128

Item 8

Item 9

Item 9A
Item 9B

Part III

Item 10
Item 11
Item 12

Item 13

Item 14

Part IV

Item 15

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

129

PART I

ITEMS 1 & 2 BUSINESS AND PROPERTIES

Business Operations and Environment

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 gas producer in
California on a gross operated basis, with average net daily production of 132 thousand of barrels of oil
equivalent per day (MBoe/d) in 2018. 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 gas basins. Our proved reserves totaled an estimated 712 million barrels of oil equivalent
(MMBoe) at December 31, 2018.

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 multiple
stacked-pay reservoirs that are, in many cases, thousands of feet thick. Our returns are enhanced
relative to our peers because we do not make royalty or other lease payments on over 60% of our
acreage, which is held in fee.

Our large portfolio of low-risk and low-decline conventional opportunities spans each of our oil and

gas basins and comprises approximately 72% of our proved reserves. We are in various phases of
developing many of our conventional assets and will continue to develop them by using internally
generated cash flow and, when appropriate, raising capital through joint ventures (JVs).

We also own or control a network of strategically placed infrastructure that is integrated with, and

complementary to, our operations, including gas plants, oil and gas gathering systems, power plants
and other related assets, which we use to maximize the value generated from our production.

Our 3D seismic library covers approximately 4,860 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.

Our 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
providing value. Our long-term value-driven growth strategy is focused on five key priorities:

•

Utilize our technical knowledge and experience to target production growth, delineate
expansion areas and optimize hydrocarbon recovery;
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 investing to grow cash flow, simplifying our capital structure,
pursuing value-accretive acquisitions and reducing absolute levels of our debt and fixed
charges; and

• Maintain a proactive and collaborative approach to safety, environmental protection and
community outreach while helping California address its energy and water needs.

Our Strengths

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

•

Operational control and a diverse asset base provide us with flexibility.

We have ownership or operational control over substantially all of our assets. This allows us
to adapt our investments by selecting drilling locations, timing the development and the drilling
and completion techniques used and allocating capital in a manner designed to optimize 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.

With our significant land holdings in California, we have undertaken new initiatives to unlock
additional value from our real estate. Our real estate development initiatives include exploring
renewable energy opportunities on our land such as solar energy projects, agricultural
activities (such as the production of fruits and nuts) and other commercial uses. We are also
exploring carbon dioxide capture and storage projects and reclaimed water opportunities.

•

Largest 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 sixth largest oil producing state
in the nation. According to the California Department of Conservation, Division of Oil, Gas,
and Geothermal Resources’ (DOGGR) information through 2017, 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, in the San Joaquin basin, is the second 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 significant energy demands that exceed local supply. Our large
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 acreage and allow us to quickly deploy the knowledge we gain in our existing operations,
together with our seismic data, to other areas within our portfolio.

•

Extensive drilling and workover portfolio.

Our drilling inventory at December 31, 2018 consisted of approximately 32,350 gross
(25,090 net) identified well locations, of which approximately 95% are oil. In addition, we

continue to maintain our available workover projects that can deliver high returns. Our
inventory of largely lower-risk conventional development opportunities has increased more
than our unconventional opportunities. In a sustained favorable oil and 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 JV opportunities.

•

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
25 years of experience in the oil and natural gas industry, with an average of over 15 years
focused on our California oil and 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.

Our Operations

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

December 31, 2018 in each of California’s four major oil and gas basins:

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

Number of fields
Average net revenue interest (%)(a)
Average drilling rigs
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

1,446

66%

49
90%
7
128.6

317
57
621

478

30
46%

8
73%
3
48.2

173
—
13

175

247

74%

27
83%
—
3.5

40
3
32

517

38%

53
78%
—
—

—
—
68

2,240

60%

137

86%
10
180.3

530
60
734

712

Oil percentage of proved reserves

66%

99%

83%

—%

74%

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

35
96
55%

13.7

9
25
100%
19.4

2
6
67%

24.0

2
5
—%
5.5

48
132

62%

14.8

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 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 taking into account royalties and similar

burdens and third- party working interests.

(b) Calculated as total proved reserves as of December 31, 2018 divided by total production for the year ended December 31,

2018.

San Joaquin Basin

According to the 2012 U.S. Geological Survey, the San Joaquin basin contained three of the

10 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 2017 was produced in the San Joaquin basin, according to DOGGR.

The Elk Hills field is our largest producing asset and has been one of the largest fields in the
continental U.S. based on proved reserves. Following the acquisition of Chevron’s interest in April
2018, we now hold all of the working, surface and mineral interests in the former Elk Hills unit.

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 880,000 acres in the San Joaquin
basin, or approximately 50% of our gross acreage in this basin, will give us a competitive advantage in
further exploration. We have established 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 and in the northwest
portion of the Lost Hills field.

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 petroleum basin in California extending from northern

Los Angeles County to the coastal city of Ventura and continues offshore encompassing the Santa
Barbara channel. The earliest discoveries were mines dug into hillsides to mine active oil seeps. The
first commercial oil well started in 1866. All of the sedimentary section is productive at various
locations, and most reservoirs are sandstones with favorable porosity and permeability. As of
December 31, 2018, we operated more than 20 oilfields in this historic and prolific basin. The basin
contains multiple stacked formations throughout its depths 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 acreage position in the Sacramento basin gives us the option
for future development and rapid production growth in an attractive natural gas price environment.

Acreage

The following table sets forth certain information regarding the total developed and undeveloped

acreage in which we held an interest as of December 31, 2018. Approximately 60% of our total net
mineral interest position is held in fee, approximately 16% 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

417
378

1,297
1,068

21
16

17
14

63
61

222
186

266
246

355
271

Gross(b)
Net(c)
(a) Acres spaced or assigned to productive wells.
(b) Total number of acres in which interests are owned.
(c) Sum of our fractional interests based on working interests or interests under PSC-type contracts.
(d) Acres on which wells have not been drilled or completed to a point that would permit the production of commercial

1,714
1,446

285
247

621
517

38
30

767
701

1,891
1,539

2,658
2,240

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

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

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

Work programs are designed to ensure that the exploration potential of any leased property is fully

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 14% of our total net undeveloped acreage at December 31, 2018 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

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 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. Given the volatile oil price environment, as well as our leverage,
we have a hedging program to help protect our cash flow and capital investment program.

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 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 recover our share of capital
and production costs, and 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 15% of our production for
the year ended December 31, 2018.

In addition, 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.

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

and production costs per Boe for the years ended December 31, 2018, 2017 and 2016. For additional
information on price calculations, see information set forth in Item 7 – Management’s Discussion and
Analysis of Financial Condition and Results of Operations – Production and Prices.

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

Total production (MMBoe)(a)(b)

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

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

Year Ended December 31,
2016
2017
2018

82
16
202
132

83
16
182
129

91
16
197
140

$
$
$
$

$
$
$

62.60 $
70.11 $
43.67 $
3.00 $

51.24 $
51.47 $
35.76 $
2.67 $

42.01
39.72
22.39
2.28

71.53 $
64.77 $
2.97 $

54.82 $
50.95 $
3.09 $

45.04
43.32
2.42

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

18.64 $
17.48 $

18.88 $
17.47 $

$
$

15.61
14.69

British Thermal Units.

(a) Our PSC-type contracts negatively impacted our oil production in 2018 by over 1 MBoe/d compared to 2017. The impact

on our oil production was immaterial in 2017 compared to 2016.

(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,
2018, 2017 and 2016:

Average net production:

Oil (MBbl/d)
NGLs (MBbl/d)
Natural gas (MMcf/d)
Total net 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
2017

2018

2016

2018

Wilmington
2017

2016

22
12
108
52

19
13
95
48

21
13
106
52

21
—
1
21

23
—
1
23

25
—
—
25

$ 73.98 $ 55.58 $ 44.50 $ 67.81 $ 49.87 $ 37.98
$ 43.58 $ 36.26 $ 23.03 $
—
1.83
2.27 $
$
$ 12.07 $ 11.76 $ 10.48 $ 29.81 $ 27.91 $ 22.27

— $
2.12 $

— $
1.71 $

2.52 $

2.87 $

N/A

$ 21.02 $ 21.59 $ 17.21

(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.

Reserves

The information with respect to our estimated reserves presented below has been prepared in

accordance with the rules and regulations of the 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 Price), 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 2018 reserves estimates, the average benchmark Brent oil price was
$71.75 per barrel and the average NYMEX gas price was $3.10 per MMBtu. The average realized
prices used for our 2018 reserves were $70.92 per barrel for oil, $43.88 per barrel for NGLs and
$2.95 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, 2018. 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

231
45
473

355

86
12
148

123

317
57
621

478

As of December 31, 2018
Ventura
Basin

Los Angeles
Basin

Sacramento
Basin

131
—
9

132

42
—
4

173
—
13

175

27
2
23

13
1
9

40
3
32

—
—
60

—
—
8

—
—
68

Total

389
47
565

530

141
13
169

182

530
60
734

712

(a) As of December 31, 2018, approximately 23% of proved developed oil reserves, 9% of proved developed NGLs

reserves, 13% of proved developed natural gas reserves and, overall, 20% 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.

Proved Reserves Additions

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

2018 were as follows (in MMBoe):

Balance at December 31, 2017

Revisions related to price
Revisions related to performance
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Balance at December 31, 2018

San Joaquin
Basin

Los Angeles
Basin(a)

Ventura
Basin

Sacramento
Basin

Total

419
16
(8)
4
18
64
—
(35)

478

145
23
8
—
8
—
—
(9)

175

40
1
5
—
4
—
—
(2)

14
(2)
1
—
—
—
—
(2)

618
38
6
4
30
64
—
(48)

712

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

(a)

feet 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 131 MMBoe and 108 MMBoe at December 31, 2018 and
2017, respectively.

In 2018, total net additions to proved reserves from all sources were 142 MMBoe. 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 added 6 MMBoe from net positive performance-related revisions of which 27 MMBoe were

from positive technical revisions due to better-than-expected performance and successful drilling
efforts in the San Joaquin and Los Angeles basins. These additions were partially offset by 21 MMBoe
of negative revisions due to management’s discretion to downgrade proved undeveloped reserves
(PUDs) that are not anticipated to be developed within their five-year window of initial booking.
Approximately 11 MMBoe of these downgraded PUDs are expiring in 2019 and are not anticipated to
be developed before then at current oil prices. The remaining 10 MMBoe of downgraded PUDs are
projects that are no longer prioritized in our development plan based on current project economics.

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.

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 the San Joaquin
and Los Angeles basins.

We also added 64 MMBoe in connection with acquisitions during the year, the majority of which

resulted from the Elk Hills transaction.

Excluding PUD downgrades of 21 MMBoe that were made at management’s discretion, we

achieved an organic reserve replacement ratio of 127% from our capital program of $690 million.
Additionally, our JV partner MIRA funded $57 million, which contributed to our reserve adds. Our total
net reserve additions from all sources generated a reserve replacement ratio of 296%. For further
information on our reserve replacement ratio, see the PV-10, Standardized Measure and Reserve
Replacement Ratio section below.

See Item 8 – Financial Statements and Supplementary Data – Supplemental Oil and Gas

Information (Unaudited) for further discussion of changes in our proved reserves.

Proved Undeveloped Reserves

The total changes to our PUDs during the year ended December 31, 2018 were as follows (in

MMBoe):

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total

Balance at December 31, 2017

Revisions related to performance
Revisions related to price changes
Extensions and discoveries
Improved recovery
Purchases
Transfers to proved developed reserves

Balance at December 31, 2018

125
(15)
2
12
3
17
(21)

123

40
1
2
5
—
—
(5)

11
4
(4)
4
—
—
—

2
—
(1)
—
—
—
—

178
(10)
(1)
21
3
17
(26)

182

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.

In 2018, we had net negative performance-related revisions of 10 MMBoe, reflecting a 21 MMBoe
downward adjustment based on management discretion as described above, which was partially offset
by 11 MMBoe of positive revisions.

We added 21 MMBoe of PUDs through extensions and discoveries, primarily resulting from new
geologic interpretations and pressure data in the Ventura basin along with successful drilling in the San
Joaquin and Los Angeles basins.

We added proved reserves of 3 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. Approximately 79% of the PUD
additions from extensions and discoveries and improved recovery were crude oil.

We transferred 26 MMBoe of PUDs to the proved developed category as a result of the 2018

capital program, all of which was in the San Joaquin and Los Angeles basins. As a result, we
converted approximately 15% of our beginning-of-year PUDs to proved developed reserves during the
year, investing approximately $235 million of development 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 2018
PUDs within five years of their original booking date. Management’s capital commitment assumes an
average $65 Brent price for 2019 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 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, 2018, our standardized measure of discounted future net cash flows
(Standardized Measure) was $7.3 billion and PV-10 was approximately $9.4 billion. In addition, we
organically replaced 127% of our proved reserves in 2018, excluding the effect of PUDs downgraded
at management’s discretion.

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-prescribed
pricing assumptions for the period. 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)
All-in reserve replacement ratio(b)

As of December 31, 2018
(in millions)

7,275
2,136

9,411

127%
296%

(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 performance-related revisions (excluding 21 MMBoe of PUDs
downgraded at management’s discretion), 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 gas producers may use different methods to
calculate replacement ratios, which may affect comparability.

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

extensions and discoveries, improved recovery, revisions and purchases, 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 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, 2018 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 take into account 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.

Net 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. Net 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 14 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 2018. The
Reserves Committee reports its findings to the Audit Committee during the year.

Audits of Reserves Estimates

Ryder Scott was engaged to provide an independent audit of our reserves estimates for fields that

comprised at least 80% of our total proved reserves. The primary technical engineer responsible for
our audit has 39 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.

The 2018 reserves audit covered over 80% of our total proved reserves. Over 95% of our total
2018 proved reserves were audited by Ryder Scott at some time during 2015 through 2018. Ryder
Scott 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. Ryder Scott 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, Ryder Scott 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 Ryder Scott. Given the inherent
uncertainties and judgments in estimating proved reserves, differences between our and Ryder Scott’s
estimates are to be expected. The aggregate difference between our estimates and Ryder Scott’s was
less than 10%, which was within SPE’s acceptable tolerance.

In the conduct of the reserves audit, Ryder Scott 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 Ryder Scott’s attention which brought into question the
validity or sufficiency of any such information or data, Ryder Scott would not rely on such information or
data until it had resolved its questions relating thereto or had independently verified such information or
data.

Ryder Scott 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. Ryder Scott issued an unqualified audit
opinion on our proved reserves as of December 31, 2018. Ryder Scott’s report is attached as an
exhibit to this Form 10-K.

Recovery Mechanisms

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

San Joaquin Basin

Primary
Waterfloods
Steamfloods
Unconventional

San Joaquin Basin subtotal(a)

Los Angeles Basin

Waterfloods

Los Angeles Basin subtotal(a)

Ventura Basin

Primary
Waterfloods

Ventura Basin subtotal(a)

Sacramento Basin

Primary

Sacramento Basin subtotal(a)

Total

Total Proved
Reserves

% of Total Basin

Average Net Daily
Production (MBoe/d)
Year ended
December 31, 2018

15%
13%
31%
41%

478

100%

175

34%
66%

100%

712

15
9
24
48

3
3

132

(a) Subtotal basin reserves in MMBoe. 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

Conventional reservoirs are capable of natural flow during primary recovery phase, often followed

by waterflood and steamflood recovery methods to enhance ultimate recovery. We determine which
development method to use based on reservoir characteristics, reserves potential and expected
returns. We seek to optimize the potential of our conventional assets by using primary recovery
methods, followed by secondary techniques such as Improved Oil Recovery (IOR) methods like
waterflooding and Enhanced Oil Recovery (EOR) methods like steamflooding, both of which use
vertical and horizontal drilling. 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 energy 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 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 as long as the oil-to-gas price ratio is in excess of five.
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. 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
established well-stimulation 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 4,620 (gross and
net) unconventional drilling locations on this acreage, excluding unconventional exploration drilling
locations. Approximately 36% of our 2018 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, increased approximately 10% in 2018 from the prior year. As of December 31, 2018, we
had proved reserves of approximately 196 MMBoe associated with our unconventional properties,
approximately 25% 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. In 2018, we continued our development activities in the
upper Monterey formation and started to appraise and delineate the Kreyenhagen formation within our
Kettleman North Dome field. During the year ended December 31, 2018, we had unconventional
production of approximately 47 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, 2018,

excluding our unconventional exploration drilling locations.

Proven Drilling Locations
Oil and
Natural Gas Wells

Injection
Wells

Total Identified Drilling Locations(a)

Oil and
Natural Gas Wells

Injection
Wells

San Joaquin Basin

Primary Conventional
Steamflood
Waterflood
Unconventional

San Joaquin Basin subtotal

Los Angeles Basin

Waterflood

Los Angeles Basin subtotal

Ventura Basin

Primary Conventional
Steamflood
Waterflood
Unconventional

Ventura Basin subtotal

Sacramento Basin

Primary Conventional

Sacramento Basin subtotal

140
570
90
220

1,020

460

30
—
80
—

110

—
150
40
—

190

130

—
—
60
—

—

Total Drilling Locations

1,600

380

8,080
8,350
1,970
4,520

—
450
980
—

22,920

1,430

1,520

1,400
120
1,560
100

3,180

2,280

29,900

500

—
—
520
—

520

—

2,450

(a) Total gross identified drilling locations is comprised of gross proven drilling locations of 1,980 gross (1,970 net), gross
unproven drilling locations of 17,030 gross (16,870 net) and gross conventional exploration drilling locations of 13,340
gross (6,250 net). Total gross identified drilling locations excludes gross unconventional exploration drilling locations of
6,400 gross (5,300 net).

Proven Drilling Locations

Based on our reserves report as of December 31, 2018, we have approximately 1,980 gross
(1,970 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 17,030 gross (16,870 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 13,340 gross (6,250 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 in the above categories of 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 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 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 oil wells
completed during the periods indicated, regardless of when drilling was initiated. We did not drill any
gas wells in 2018. 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

2018
Productive

Exploratory
Development

Dry

Exploratory
Development

2017
Productive

Exploratory
Development

Dry

Exploratory
Development

2016
Productive

Exploratory
Development

0.3
127.0

1.3
—

2.0
91.8

3.0
—

—
37.0

—
48.2

—
—

—
14.5

—
—

—
5.4

—
3.2

0.3
—

—
1.6

—
—

0.3
178.4

1.6
—

2.0
107.9

3.0
—

—
42.4

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, 2018, 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)

14.0
13.9

2.0
1.9

3.3
2.3

—
—

19.3
18.1

(a) The total number of wells in which interests are owned.
(b) Sum of our fractional interests.

On a gross basis, these projects included three primary, five steamflood, ten waterflood and one

unconventional.

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 94%. 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, 2018, excluding wells that have been idle for more than five years:

As of December 31, 2018
Productive Oil Wells Productive Gas Wells
Gross(a)

Gross(a)

Net(b)

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) Sum of our fractional interests.

Exploration Program

8,419
1,533
1,320
—

7,961
1,486
1,312
—

11,272

10,759

382

356

166
1
—
1,012

1,179

161
1
—
930

1,092

We have an active exploration program in both conventional and unconventional plays. We
believe our experienced technical staff, proprietary geological models, acreage position and extensive
3D seismic library give us a strong competitive advantage. California basins have generated billions of
barrels of oil and billions 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 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 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, primarily 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 JV 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

We currently sell all of our crude oil into the California refining markets, which offer favorable
pricing for comparable grades relative to other U.S. regions. 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 74% of oil and 90% of natural gas consumed in 2018 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. Additionally, our differentials improved against Brent during 2017 and 2018 in
response to strong demand for California crude oil to optimize local refinery yields as well as a decline
in overall California crude oil production.

Crude Oil – Substantially all of our crude oil production is connected to third-party pipelines and
California markets via our gathering pipelines, which are used almost entirely for our production. We do
not refine or process the crude oil we produce and do not have any significant long-term transportation
arrangements. We sell all of our crude oil into the California refining markets, which we believe have
offered relatively favorable pricing compared to other U.S. regions for similar grades. Currently, our
index-based crude oil sales contracts have 30-day to nine-month terms with no such contracts
extending past one year.

Natural Gas – We sell all of our natural gas to the California market. We have firm transportation
capacity contracts to access markets and to facilitate deliveries. We sell virtually all of our natural gas
production under individually negotiated contracts using market-based pricing on a monthly or shorter
basis.

NGLs – We extract substantially all of our NGLs through our gas processing plants, which facilitate

access to third-party delivery points near the Elk Hills field. We currently have pipeline capacity
contracts to transport 20,000 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 60% of our NGLs are sold to export markets.

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 an agreement expiring at the end of 2020, which includes a minimum capacity
payment.

Delivery Commitments

We have short-term commitments to certain refineries and other buyers to deliver oil, natural gas
and NGLs. As of December 31, 2018, we had oil and NGL delivery commitments of 41 and 19 MBbl/d
through March 2019, respectively, and natural gas commitments of 35 MMcf/d through the end of
2019. We have significantly more production capacity than the amounts committed for oil and natural
gas. For NGL commitments, we have agreements to cash settle any shortfall between the committed
quantities and our production. Further, we have the ability to secure additional volumes of all products
if necessary. None of the commitments are expected to have a material impact on our financial
statements. 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 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
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 which cannot be accurately predicted.

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, 43% of our revenue. For
the years ended December 31, 2017 and 2016, our principal customers, Phillips 66 Company, Andeavor
(formerly Tesoro Refining & Marketing Company LLC), Valero Marketing & Supply Company and Shell
Trading (US) Company, each accounted for at least 10%, and, collectively, 67% of our revenue.

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 interests, liens incident
to operating agreements and tax obligations or duties under applicable laws, development obligations,
or net profits interests, 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 gas industry, 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. As a result, 74% of the oil the state consumes is imported, virtually all 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 capacity on our firm transportation commitments.

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. Historically, higher
commodity prices intensify competition for drilling and workover rigs, pipe, other oil field equipment and
personnel. As oil prices and activity increased in 2017, the energy industry in certain parts of the
country started experiencing increases in service costs. However, the California energy industry
experienced only limited cost inflation in 2017 and 2018 due to excess capacity in the service and
supply sectors. At current commodity price levels, we expect limited cost inflation to continue in 2019.
Given our relative size compared to other in-state producers, our activity level influences the pricing of
third-party services in the local market.

Infrastructure

We own a network of infrastructure that is integral to and complements our operations. Our
significant footprint in California and wide network of infrastructure help 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 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
>20,000

(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.

Gas Processing

We believe we own 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 the Elk
Hills natural gas processing facility for NGL sales to third parties.

Electricity

The 550-megawatt combined-cycle Elk Hills power plant, located adjacent to the Elk Hills gas
processing facility, generates all the electricity needs for our Elk Hills 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.

Steam Infrastructure

We own, control and operate all of our steam generation infrastructure in the San Joaquin basin,

including steam generators, steam plants, steam distribution systems, steam injection lines and
headers, water softeners and water disposal 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 and shallow- to medium-depth oil fields such as Kern Front and
Lost Hills.

Gathering Systems

We own an extensive network of over 20,000 miles of oil and gas gathering lines. These gathering
lines are dedicated almost entirely to collecting our oil and 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 1,500 employees as of December 31, 2018 compared to approximately
1,450 as of December 31, 2017. The increase is primarily due to the conversion of certain long-term
contractors to employees in 2018. Of the 1,500 employees, approximately 1,080 were employed in
field operations and approximately 75 of those employees are represented by labor unions. We have
not experienced any strikes or work stoppages by our employees since our formation in 2014. We also
utilize the services of independent contractors to perform drilling, well work, operations, construction
and other services, including construction contractors whose workforce is often 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;

• methods of constructing, drilling, completing, stimulating, operating, maintaining and

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•
•

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

DOGGR 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 DOGGR 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. For example, in September 2016, a
federal judge issued an order finding that the BLM’s NEPA review of the Resource Management Plan
for portions of Ventura, Kern and other counties failed to sufficiently analyze the potential
environmental impacts of hydraulic fracturing and directed the BLM to prepare a supplemental
environmental impact statement (SEIS). In August 2018, BLM published a notice of intent to prepare
an amendment to the Resource Management Plan and an associated SEIS regarding oil and gas
exploration and production activities, including well stimulation, which process may impact future oil
and gas leasing of federal lands in central California.

The jurisdiction and enforcement authority of DOGGR and other state agencies have significantly

increased with respect to oil and gas activities in recent years, and these agencies have significantly
revised their regulations, regulatory interpretations and data collection requirements. DOGGR has
undertaken a comprehensive examination of existing regulations and began implementing an
electronic permitting system in 2018. DOGGR issued additional regulations in 2018 that impose more
stringent inspection and integrity management requirements with respect to certain gas pipelines
located in sensitive areas, and the Office of the State Fire Marshal intends to issue regulations in 2019
that would require retrofitting certain oil pipelines in the coastal zone with best available control
technology to mitigate oil spills. DOGGR is also finalizing updated regulations governing management
of idle wells and underground fluid injection, which are expected to be adopted early in 2019 and to
include specific implementation periods. Pursuant to Assembly Bill 2729, which the Legislature enacted
in 2016, DOGGR requires 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 for each such well. The updated underground injection regulations are expected
to 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. Finally, DOGGR announced that it is reviewing and intends to update its well
construction regulations in the next two years.

In 2013 California adopted 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 gas to flow more freely into producing wells. Among other things, SB 4 requires operators
to obtain specific well stimulation permits, make detailed disclosures and implement groundwater
monitoring and water management plans. The U.S. Environmental Protection Agency (EPA) and the
BLM also regulate certain well stimulation activities. In 2017, the BLM rescinded its hydraulic fracturing
regulations, which were being challenged in court, and is preparing a SEIS regarding well stimulation

and other oil and gas activities on federal lands in central California. The implementation of federal and
state well stimulation regulations has delayed, and increased the cost of, certain operations.

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 own mineral
interests but do not have any production. As written, the measure sought to prohibit the drilling of new
oil and 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 December 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 without compensation under the federal and
state constitutions. 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 National
Environmental Policy Act, among others. California imposes additional laws that are analogous to, and
often more stringent than, such federal laws. These laws and regulations:

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

•

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

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

groups or others; and

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

Due to the severe drought in California over the last several years, 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 to support operations like steam injection in certain fields.

In 2014, at the request of the EPA, DOGGR 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
DOGGR’s implementation of its aquifer exemption regulations. In March 2017, the Kern County
Superior Court issued an injunction barring the blanket enforcement of DOGGR’s aquifer exemption
regulations. The court found that DOGGR 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.

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. The EPA has adopted federal regulations to:

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•

require reporting of annual GHG emissions from oil and gas exploration and production,
power plants and 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. These state laws and regulations:

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established a “cap-and-trade” program for GHG emissions that sets a statewide maximum
limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990
levels by 2030, the year that the cap-and-trade program currently expires;
require allowances or qualifying offsets for GHGs emitted from California operations and for
the volume of natural gas, propane and liquid transportation fuels sold for use in California;
established a low carbon fuel standard and associated tradable credits that require a
progressively lower carbon intensity of the state’s fuel supply than baseline gasoline and
diesel fuels;

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

•

resources by 2030;
established a policy to derive all of California’s retail electricity from renewable or
“zero-carbon” resources by 2045, subject to required evaluation of the feasibility by state
agencies; and
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.

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 proposed in 2018 to increase the
flexibility of its 2016 methane requirements, CARB has adopted more stringent regulations to require
monitoring, leak detection, repair and reporting of methane emissions from both existing and new oil
and gas production, pipeline gathering and boosting facilities and natural gas processing plants
beginning in 2018 and additional controls such as tank vapor recovery to capture methane emissions
in subsequent years.

Legislation and regulation to address climate change could also increase the cost of consuming,

and thereby reduce demand for, oil, natural gas and other products produced by us, and potentially
lower the value of our reserves and other assets.

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:

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

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

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

•

The federal and state agencies overseeing these regulations have substantial rate-setting and

enforcement authority, and violation of the foregoing regulations could expose us to litigation with
government authorities, counterparties, special interest groups and others.

Spin-Off and Reverse Stock Split

We were incorporated in Delaware as a wholly owned subsidiary of Occidental Petroleum

Corporation (Occidental) on April 23, 2014, and remained a wholly owned subsidiary of Occidental until
November 30, 2014 when Occidental distributed shares of our common stock on a pro-rata basis to
Occidental stockholders (the Spin-off). On December 1, 2014, we became an independent, publicly
traded company. Occidental initially retained approximately 18.5% of our outstanding shares of
common stock, which were distributed to its stockholders on March 24, 2016. All references to
‘‘Occidental’’ refer to Occidental Petroleum Corporation, our former parent, and its subsidiaries.

On May 31, 2016 we completed a reverse stock split using a ratio of one share of common stock
for every ten shares then outstanding. Share and per share amounts included in this report have been
restated to reflect this reverse stock split.

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, if any. 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 GAAP to non-GAAP reconciliations. Unless otherwise provided herein,
information contained on our website is not part of this report.

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. Historically, the markets for these commodities 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 2018. Factors affecting oil, natural gas and NGL 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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•

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•

reducing our proved oil and gas reserves over time, including as a result of impairments of
existing reserves;
limiting our ability to grow or maintain future production;
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 and potential issues under our JV arrangements;
affecting our ability to attract counterparties and enter into commercial transactions, including
hedging transactions; and
limiting our access to funds through the capital markets and the price we could obtain for
asset sales or other monetization transactions or our equity and debt securities.

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, loss of certain tax benefits, 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.

Our hedging program does not provide downside protection for all of our production in 2019 and
beyond. As a result, our hedges do not fully protect us from commodity price reductions and we may
be unable to enter into acceptable additional hedges in the future.

Our lenders require us to comply with covenants that limit our borrowing capabilities and could
restrict our ability to use or access capital.

Our 2014 Revolving Credit Facility is an important source of our liquidity and we may need to rely

on this facility to fund a portion of our future capital and operating costs. 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 monthly liquidity requirement of
$150 million. As of December 31, 2018, we had approximately $298 million of available borrowing
capacity, before taking into account the minimum monthly liquidity requirement.

As of December 31, 2018, the lenders’ aggregate commitment under our 2014 Revolving Credit
Facility was $1 billion. The borrowing base under our 2014 Revolving Credit Facility is currently set at
$2.3 billion and is redetermined each May 1 and November 1. The lenders take into account the
$1.3 billion outstanding under our 2017 Credit Agreement in determining the total commitment that
could be made available in the future under the 2014 Revolving Credit Facility. Our lenders determine
our borrowing base by reference to the value of our reserves, which is influenced by commodity prices,
expected future cash flows and other factors. If our lenders were to reduce our borrowing base
significantly, the amount of availability under our 2014 Revolving Credit Facility could be reduced which
could have an adverse effect on our liquidity and financial condition.

The financial covenants that we must satisfy under our 2014 Revolving Credit Facility include a
monthly minimum liquidity test and 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, the lenders
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 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, 2018, the face value of our outstanding long-term consolidated indebtedness

was $5.3 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 fund capital investments, react to competitive pressures and engage in
certain transactions that might otherwise be beneficial to us;
defaulting on commercial agreements with our JV partners; and
failing to redeem the interests held by 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 granting additional liens;
repay junior indebtedness, including our Second Lien Notes and Senior Notes;

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• make investments;
enter into JVs;
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pay dividends and making other restricted payments;
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selling 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.
•

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 it 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. 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.

Our business requires substantial capital investments, which may include acquisitions. We
may be unable to fund these investments which could lead to a decline in our oil and 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 JV arrangements. We seek to
manage our 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 variables, including:

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the amount of oil, 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.

Future capital availability may be reduced by (i) our lenders, (ii) our JV partners, (iii) capital
markets constraints, (iv) activist funds or investors or (v) 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.

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 over 80% of our 2018 proved reserve estimates were audited by our independent petroleum
engineers, Ryder Scott Company, L.P., 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:

•
•
•
•
•
•
•
•

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:

•

•
•
•
•

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 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.

Part of our business strategy involves entering into JVs and divesting non-core assets. Our JVs

and disposition activities carry risks that we may:

•

not be able to realize reasonable prices or rates of return for assets;

•
•
•

be required to retain liabilities that are greater than desired or anticipated;
experience increased operating costs; and
reduce our cash flows if we cannot replace associated revenue.

There can be no assurance that we will be able to 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 make acquisitions, we may not be able to grow our reserves or develop our

properties in a timely manner or at all. 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. Any of the
foregoing could adversely affect our business, financial condition, cash flows and results of operations.

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 in these areas. For example, the jurisdiction and enforcement
authority of various state agencies have significantly increased with respect to oil and 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 requirements and plan to issue
additional regulations of certain oil and gas activities in 2019. 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, 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 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.

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 gas operations, including those related to air, soil and water quality,
ground movement or seismicity and natural resources. Government authorities have also adopted or
proposed new or more stringent requirements for permitting, well construction and public disclosure or
environmental review of, or restrictions on, oil and 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 in elected officials could result in different approaches to the regulation of the oil and gas

industry. In 2018, California elected a new governor who took office in January 2019. Many
representatives in the Legislature have also changed, with the commencement of a new two-year
legislative session. We cannot predict the actions the Governor or Legislature may take with respect to
the regulation of our business, the oil and 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 our expected VCI.

The exploration and development of oil and 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. VCIs
are calculated based on internal estimates of future cash flows and capital investment and are
inherently uncertain. Our decisions and ultimate profitability are also affected by commodity prices, the
availability of capital, regulatory approvals, available transportation and storage capacity, political
resistance and other factors. Our cost of drilling, completing, stimulating, equipping, operating,
maintaining and abandoning wells is also often uncertain.

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.
Overruns in budgeted investments is a common risk associated with oil and gas operations.

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 these exploration drilling locations or any other drilling
locations we have identified 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 14% of our total net undeveloped acreage at December 31,
2018.

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 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 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.
For example, in 2018, we settled hedges that had the effect of reducing our realized oil price by
$7.51 per barrel. 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, establishes 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, some of which are still ongoing. 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 amount 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 are implementing 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.

In California, there have been numerous proposals for additional income, sales, excise and
property taxes, including taxes on oil and gas production. Although the proposals have not become
law, campaigns by various interest groups could lead to additional future taxes. The imposition of
increased taxes could significantly reduce our profit margins and cash flow and could ultimately reduce
our capital investments and growth plans.

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 other nature-related events common to California, such as wildfires, mudslides,
high winds and earthquakes. The concentration of our operations in California and limited local storage
options also increase our exposure to mechanical failures, industrial accidents or labor difficulties,
including those affecting our operations, our supply chain and those who purchase, transport or use
our products. 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 affect our operations or
results.

Concerns about climate change 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 may increase our operating costs and render certain wells or
projects uneconomic, and potentially lower the value of our reserves and other assets. As these

requirements become more stringent, we may be unable to implement them in a cost-effective manner.
To the extent financial markets view climate change and GHG emissions as a financial risk, this could
adversely impact our cost of, and access to, capital. Both the EPA and California have implemented
laws, regulations and policies that seek to reduce GHG emissions as discussed in 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.

In addition, other current and proposed international agreements and federal and state laws,
regulations and policies seek to restrict or reduce the use of petroleum products in transportation fuels,
electricity generation and other applications, prohibit future use of certain vehicles and 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. For example, former Governor Brown
issued executive orders in 2018 setting a target of at least five million “zero-emission” vehicles in
California by 2030 and a goal for the state to be “carbon-neutral” by 2045. A bill has been introduced in
the California Legislature that seeks to prohibit the sale or registration of new automobiles in California
with internal combustion engines by 2040. Various claimants, including certain municipalities, have
also filed litigation alleging that energy producers are liable for conditions the claimants attribute to
climate change.

Governmental 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.

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 gas exploration and production activities and

our assets are subject to risks such as fires, explosions, releases, discharges, 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, high winds, droughts,
cyber-security 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. 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. 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.

We are exposed to certain risks related to our separation from Occidental in 2014.

In connection with our separation from Occidental, we entered into contracts that allocate risks
and liabilities (including tax liabilities) between Occidental and ourselves. These contracts were not
made on an arm’s length basis and include mutual indemnity obligations. Indemnity payments that we
may be required to provide Occidental may be significant and could adversely impact our business.
Similarly, third parties could also seek to hold us responsible for liabilities that Occidental has agreed to
retain and the indemnity from Occidental may not be sufficient or paid timely.

ITEM 1B

UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 3

LEGAL PROCEEDINGS

For information regarding legal proceedings, see Item 7 – Management’s Discussion and Analysis
of Financial Condition and Results of Operations – Lawsuits, Claims, Commitments and Contingencies
and in Item 8 – Financial Statements and Supplementary Data – Note 8 Lawsuits, Claims,
Commitments and Contingencies.

ITEM 4

MINE SAFETY DISCLOSURES

Not applicable.

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 -
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.

Age at
February 27, 2019

Francisco J. Leon Executive Vice President - Corporate Development and

Strategic Planning - 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

Michael L. Preston Executive Vice President, General Counsel and Corporate

Charles F. Weiss

Darren Williams

Secretary since 2014; 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 -
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.

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 on the New York Stock Exchange (NYSE) under the symbol “CRC.”

Holders of Record

Our common stock was held by approximately 20,700 stockholders of record at December 31,

2018.

Dividend Policy

No dividends were paid in 2018, 2017 and 2016, and we do not anticipate paying any dividends on

our common stock in the foreseeable future. Covenants under our credit agreements generally restrict
the payment of cash dividends on our stock, subject to certain exceptions. See Item 7 – Management’s
Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital
Resources – Credit Agreements for a description of limitations on paying dividends under our credit
facilities.

Securities Authorized for Issuance Under Equity Compensation Plans

A description of the stock-based compensation plans can be found in Item 8 – Financial

Statements and Supplementary Data – Note 11 Stock-Based Compensation. The aggregate number of
shares of our common stock authorized for issuance under our stock-based compensation plans for
our executives, employees and non-employee directors is 6.2 million, of which approximately
4.9 million had been issued or reserved through December 31, 2018.

The following is a summary of the securities available for issuance under such plans as of

December 31, 2018:

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

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

c) Number of securities

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

2,354,569

$62.82 (a)

1,253,892 (b)

(a) Exercise price applies only to approximately 1.3 million options included in column (a) and not to any other awards.
(b)

Includes 656,929 shares available under our 2014 Employee Stock Purchase Plan (ESPP) 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.

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 1, 2014, the date our common stock began trading on the NYSE, $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 2018 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.

Our 2017 peer group included Cabot Oil and Gas Corporation; Cimarex Energy Co.; Concho
Resources Inc.; Denbury Resources Inc.; Energen Corporation; EP Energy Corporation; Murphy Oil
Corporation; Newfield Exploration Company; Oasis Petroleum Corporation; Parsley Energy, Inc.; QEP
Resources, Inc.; Range Resources Corporation; SM Energy Company; Whiting Petroleum Corporation
and WPX Energy, Inc. Energen Corporation is excluded from the graph below due to its acquisition by
Diamondback Energy, Inc. in 2018.

PERFORMANCE GRAPH*
Among CRC, the S&P 500 Index,
the Dow Jones US Exploration & Production Index,
2017 Peer Group and 2018 Peer Group

$160

$140

$120

$100

$80

$60

$40

$20

12/1/14

12/14

12/15

12/16

12/17

12/18

CRC

S&P 500

Dow Jones US Exploration & Production

2017 Peer Group

2018 Peer Group

12/1/2014

2014

2015

December 31,
2016

2017

2018

CRC
S&P 500
Dow Jones US Exploration & Production
2018 Peer Group
2017 Peer Group

$
$
$
$
$

100 $
100 $
100 $
100 $
100 $

75 $
100 $
99 $
95 $
96 $

32
101
76
58
62

$
$
$
$
$

29
113
94
85
92

$
$
$
$
$

27
138
95
70
81

$
$
$
$
$

23
132
78
53
53

* 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

Prior to the Spin-off on November 30, 2014, financial data was derived from Occidental’s
California oil and gas exploration and production operations and related assets, liabilities and
obligations (California business), which we assumed with the Spin-off. All financial information
presented after the Spin-off represents our stand-alone consolidated results of operations, financial
position and cash flows. Accordingly, for the year ended December 31, 2014, the statement of
operations and cash flows data includes the consolidated results for the month ended December 31,
2014 and the combined results of the California business prior to the Spin-off.

2018

Year Ended December 31,
2015
2016
2017

2014

(in millions, except for per share data)

Statement of Operations Data
Total revenues and other
Income (loss) before income taxes
Net income (loss) attributable to common stock

$ 3,064
429
$
328
$

$ 2,006
$
$

(262) $
(266) $

$ 1,547
201
279

$ 2,403 $
$ (5,476) $
$ (3,554) $

4,173
(2,421)
(1,434)

Per common share

Basic
Diluted

Statement of Cash Flows Data
Net cash provided by operating activities
Capital investments
Acquisitions and other
Net (repayments) borrowings and related costs
Contributions from noncontrolling interest holders, net
Distributions paid to noncontrolling interest holders
Spin-off related dividends to Occidental
Distributions to Occidental, net
Dividends per common share

$
$

$
$
$
$
$
$
$
$
$

6.77
6.77

$
$

(6.26) $
(6.26) $

6.76
6.76

$ (92.79) $
$ (92.79) $

(37.54)
(37.54)

461
$
(690) $
(553) $
(26) $
796
$
(121) $
— $
— $
— $

248
$
(371) $
(2) $
(18) $
98
$
(8) $
— $
— $
— $

130
$
(75) $
— $
(73) $
— $
— $
— $
— $
— $

403 $
(401) $
(151) $
356 $
— $
— $
— $
— $
0.30 $

2,371
(2,089)
(292)
6,290
—
—
(6,000)
(335)
—

2018

As of December 31,
2016

2017

2015

2014

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

(in millions)

438 $

483
$
$ 5,696
$ 6,207

640
$
$ 6,455
$ 7,158
— $
$
732
$
607
$
$ 5,306
$ 5,251
287
$
216
$
$
602
575
$
756
$
$
(361) $
$

425
$
$ 5,885
$ 6,354
100
— $
726
$
$ 5,168
397
$
620
$
— $
(814) $

701
$
$ 6,312 $ 11,685
$ 7,053 $ 12,429
—
100 $
$
922
605 $
$
6,360
$ 6,043 $
(68)
491 $
$
549
830 $
$
—
— $
— $
2,611
(916) $
(557) $

The selected financial data presented above should be read in conjunction with Item 7 –
Management’s Discussion and Analysis of Financial Condition and Results of Operations and the
consolidated financial statements and accompanying notes included elsewhere in this Form 10-K.

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.

Basis of Presentation and Certain Factors Affecting Comparability

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 all significant intercompany transactions and
accounts. We account for our share of oil and gas exploration and production ventures, 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 the balance sheets and statements of operations and
cash flows.

On May 31, 2016 we completed a reverse stock split using a ratio of one share of common stock
for every ten shares then outstanding. Share and per share amounts included in this report reflect this
stock split for all periods presented.

Business Environment and Industry Outlook

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

commodity prices. Oil and 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.

On average, global oil prices were higher in 2018 compared to 2017. Further, the spread between

Brent and WTI widened reflecting rising domestic shale production in the mid-continent and pipeline
constraints in these areas. Prices for natural gas liquids (NGLs) have improved between comparative
periods due to tighter local supplies and higher contract prices across the NGL spectrum. On average,
natural gas prices in the U.S. were lower in 2018 compared to 2017 due to higher natural gas
production, which has outpaced demand.

The following table presents the average daily Brent, WTI and NYMEX prices for each of the years

ended December 31, 2018, 2017 and 2016:

Brent oil ($/Bbl)
WTI oil ($/Bbl)
NYMEX gas ($/MMBtu)

2018

2017

2016

$
$
$

71.53
64.77
2.97

$
$
$

54.82
50.95
3.09

$
$
$

45.04
43.32
2.42

We currently sell all of our crude oil into the California refining market, which offers relatively
favorable pricing compared to other U.S. regions for similar grades. California is heavily reliant on
imported sources of energy, with approximately 74% of the oil consumed in 2018 imported from
outside the state. A vast majority 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 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. Additionally, our differentials improved against Brent during 2017 and 2018 in
response to strong demand for California crude oil to optimize local refinery yields as well as a decline
in overall California crude oil production.

Prices and differentials for NGLs 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 pricing volatility.

Natural gas prices and differentials are strongly affected by local market fundamentals, such as
storage capacity, as well as availability of transportation capacity from producing areas. Transportation
capacity influences prices because California imports approximately 90% of its natural gas from other
states and Canada. As a result, we typically enjoy favorable pricing relative to out-of-state producers
since we can deliver our gas for lower transportation costs. Due to our much lower natural gas
production compared to our oil production, the changes in natural gas prices have a smaller impact on
our operating results.

In addition to selling natural gas, we also use 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, but
higher prices still have a net positive effect on our operating results. Conversely, lower natural gas
prices generally have a net negative effect on our results, but lower the operating costs of our
steamflood projects and power generation.

Our earnings are also affected by the performance of our processing and power-generation

assets. 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. Additionally, we use part of the electricity from the Elk Hills
power plant to reduce operating costs at our Elk Hills and certain nearby fields and to increase
reliability. The remaining electricity is sold to the wholesale power market and a utility under a power
purchase and sales agreement expiring in December 2020, which includes a capacity payment. The
price obtained for excess power impacts our earnings but generally by an insignificant amount.

We procure tubular goods and equipment from multiple vendors. Tariffs of 25% for steel and 10%
for aluminum on foreign imports became effective in the first quarter of 2018. These tariffs did not have
a material impact on our operating costs in 2018, and we do not expect them to have a material impact
in the foreseeable future.

We opportunistically seek strategic hedging transactions to help protect our cash flow, operating

margin and capital program from both the cyclical nature of commodity prices and interest rate
movements while maintaining adequate liquidity and improving our ability to comply with our debt
covenants in case of price deterioration. We built our 2019 commodity hedge positions to protect our
downside risk without significantly limiting our upside potential. We can give no assurances that our
hedges will be adequate to accomplish our objectives. 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.

We respond to economic conditions by adjusting the amount and allocation of our capital program
and continuing to identify efficiencies and cost savings. The reductions in our capital program in 2015
and 2016 negatively impacted our 2017 production levels. Our oil production stabilized in the first half
of 2018 with our increased 2017 capital program, even excluding the impact of the additional
production from the Elk Hills transaction in the second quarter of 2018. Volatility in oil prices may
materially affect the quantities of oil and gas reserves we can economically produce over the longer
term.

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.

Joint Ventures

Development Joint Ventures

In line with our strategy, we have entered into a number of joint ventures (JVs). JVs 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.

In February 2017, we entered into a development JV with Benefit Street Partners (BSP) where
BSP will contribute up to $250 million, subject to agreement of the parties, in exchange for a preferred
interest in the BSP joint venture (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. BSP funded a total of $150 million in three equal tranches,
before transaction costs, in March 2017, July 2017 and June 2018. The funds contributed by BSP were
used to develop certain of our oil and 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 our BSP JV, with BSP’s share of net
income being reported in net income attributable to noncontrolling interests on our consolidated
statements of operations.

In April 2017, we entered into a development JV with Macquarie Infrastructure and Real Assets
Inc. (MIRA) under which MIRA will invest up to $300 million, subject to agreement of the parties, to
develop certain of our oil and gas properties in exchange for a 90% working interest in the related
properties (MIRA JV). MIRA will fund 100% of the development cost of such properties. Our 10%
working interest increases to 75% if MIRA receives cash distributions equal to a predetermined
threshold return. MIRA initially committed $160 million, which was intended to be invested over two
years. In June 2018, the parties amended the joint development program to $140 million. The
agreement provides for a commitment of up to 110% of the program amount. MIRA invested
$58 million in 2017 and $57 million in 2018. Our consolidated results reflect only our working interest
share in our MIRA JV.

In October 2018, we entered into a development JV for a three-year program to drill 20 wells

where our JV partner committed approximately $23 million and we are investing approximately
$13 million. Our consolidated results reflect only our working interest share in this JV.

Exploration Joint Ventures

We entered into two exploration JVs where our JV partners have an initial total commitment of

approximately $12 million. If certain milestones are met on the initial wells, the parties may move
forward with a mutually agreed drilling program. Our consolidated results reflect only our working
interest share in this JV.

Midstream Joint Venture

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 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 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 make monthly distributions to the Class B holders. 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 also 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.

Acquisitions and Divestitures

Acquisitions

In April 2018, we acquired the remaining working, surface and mineral interests in the 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 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). After the transaction, we hold all of
the working, surface and mineral interests in the Elk Hills unit. The effective date of the transaction was

April 1, 2018. Since the acquisition, we estimate that we have recognized approximately $25 million in
cost savings and revenue enhancements by streamlining operations and consolidating infrastructure.
On an annualized basis, these synergies total approximately $34 million, significantly exceeding our
initial target and over a shorter time frame. Additionally, we realized approximately $20 million of
nonrecurring capital savings through December 31, 2018, and we may have additional capital savings
in the future. Chevron sold all of the shares of CRC common stock it acquired in the Elk Hills
transaction in 2018.

As part of the Elk Hills transaction, Chevron reduced its royalty interest in one of our oil and 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, 2018, the remaining commitment
was approximately $17 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 also acquired an office building and land in Bakersfield, California for
$48.4 million, which we believe is significantly less than the estimated replacement value of the
property and the land. At the time of acquisition, we had approximately 500 employees using eight
different locations in Bakersfield across multiple leases. We expect that the new building will create
significant value by bringing our Bakersfield employees together into a single location, which will
increase the efficiency, effectiveness and collaboration of these employees. This building was the only
available office space in the Bakersfield area large enough to allow us to consolidate our workforce in a
single location. 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 upstream acquisitions totaling approximately $39 million in

2018.

Divestitures

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. In 2016,
we divested non-core assets resulting in $20 million of proceeds and a $30 million gain.

Income Taxes

All of our income is earned from domestic operations and is subject to tax in the U.S. The following

table sets forth our pre- and after-tax income (loss) and income tax amounts:

Pre-tax income (loss)
Income tax benefit

Net income (loss)

2018

For the years ended
December 31,
2017
(in millions)
(262)
$
—

429
—

429

(262)

2016

201
78

279

We did not make United States federal and state income tax payments in 2018, 2017 or 2016 due

to the tax losses we incurred and do not expect to make any income tax payments in the foreseeable
future, although this estimate could change.

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, 2018, 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, 2018 will be released within the next 12 months. The amount of the deferred tax assets
considered realizable could however be adjusted if estimates or amounts of deferred tax liabilities
change.

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,
2017

2016

2018

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

Effective tax rate

21%
6
(5)
—
(6)
—
—
(17)
1

—%

(35)%
(6)
—
91
(19)
—
1
(33)
1

—%

35 %
6
—
—
—
(275)
2
192
1

(39)%

Our income tax provision for 2017 and 2016 was based on a U.S. federal statutory rate of 35%

and a California statutory rate of 8.84%. Our effective rate was lower in each of these years primarily
due to our debt reduction transactions in 2016 and the remeasurement of our net deferred tax assets in
2017 as a result of the reduction in the U.S. federal income tax rate from 35% to 21% as enacted by
the Tax Cuts and Jobs Act signed by the President on December 22, 2017. Additionally, due to the low
commodity price environment, the enhanced oil recovery credit was available in each of the years
ended December 31, 2018 and 2017. These discrete items may not recur in subsequent years.

Our effective tax rate is affected by recurring items such as permanent differences, tax deductions

Given our tax status, any item affecting our effective tax rate described above is offset by an equal

change in the valuation allowance. As of December 31, 2018, 2017 and 2016, we had valuation
allowances of $625 million, $706 million and $780 million, respectively.

For additional information on items affecting our effective tax rate and the impact of 2017 tax
reform, see information set forth in Item 8 – Financial Statements and Supplementary Data – Note 10
Income Taxes.

Production and Prices

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

for the years ended December 31, 2018, 2017 and 2016:

2018

2017

2016

Oil (MBbl/d)(a)

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)

53
25
4

15
1

165
1
7
29

202

132

52
27
4

15
1

140
1
8
33

182

129

57
29
5

15
1

150
3
8
36

197

140

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 PSC-type contracts negatively impacted our oil production in 2018 by over 1 MBoe/d compared to 2017. The

impact on our oil production was immaterial in 2017 compared to 2016.

(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.

The following tables set forth the average realized prices and price realizations as a percentage of

average Brent, WTI and NYMEX for our products for the years ended December 31, 2018, 2017 and
2016:

Oil ($ per Bbl)
Brent

Realized price, without hedge

Settled hedges

2018

2017

2016

Price

Realization

Price

Realization

Price

Realization

$ 71.53

$ 54.82

$ 45.04

$ 70.11
(7.51)

98%

$ 51.47
(0.23)

94%

$ 39.72
2.29

88%

Realized price, with hedge

$ 62.60

88%

$ 51.24

93%

$ 42.01

93%

WTI
Realized price, without hedge
Realized price, with hedge

$ 64.77
$ 70.11
$ 62.60

108%
97%

$ 50.95
$ 51.47
$ 51.24

101%
101%

$ 43.32
$ 39.72
$ 42.01

NGLs ($ per Bbl)
Realized price (% of Brent)
Realized price (% of WTI)

$ 43.67
$ 43.67

61%
67%

$ 35.76
$ 35.76

65%
70%

$ 22.39
$ 22.39

Natural gas
NYMEX ($/MMBTU)

2.97

Realized price, w/out hedge ($/Mcf) $
Settled hedges

3.00
(0.02)

101%

Realized price, with hedge ($/Mcf)

2.98

100%

3.09

2.67
—

2.67

2.42

2.28
—

2.28

86%

92%
97%

50%
52%

94%

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. Under
prior accounting standards, the unhedged realized price and realization for natural gas would have been $2.79 per Mcf
and 94%, respectively, and the hedged realized price and realization would have been $2.77 per Mcf and 93%,
respectively. The new standard did not have a material impact to the realized price and realization for oil and NGLs.

Balance Sheet Analysis

The changes in our balance sheet as of December 31, 2018 and 2017, are discussed below:

Cash
Trade receivables
Inventories
Other current assets, net
Property, plant and equipment, net
Other assets
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

2018

2017

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

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

20
277
56
130
5,696
28
257
475
5,306
287
602
—
(814)
94

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

Cash at December 31, 2018 and 2017 included approximately $2 million and $5 million,

respectively, that is restricted under one of our JV agreements. See Liquidity and Capital Resources
for our cash flow analysis.

The increase in trade receivables was largely the result of higher total production volumes in
December 2018 compared to December 2017. The increase in other current assets, net primarily
reflected an increase in the fair value of the current portion of our derivative assets, partially offset by
the sale of a non-core asset and decreases in amounts due from joint interest partners. The increase in
property, plant and equipment, net primarily reflected capital investments and acquisitions for the
period, partially offset by depreciation, depletion and amortization (DD&A). The increase in other
assets was primarily due to changes in the fair value of our long-term derivative assets and prepaid
power plant major maintenance expenses.

The increase in accounts payable at December 31, 2018 compared to December 31, 2017

reflected the increase in activity between periods. The decrease in accrued liabilities was primarily due
to the change in value of our derivative positions held between the periods and payments made in
2018 for prior years’ greenhouse gas obligations. These decreases were partially offset by higher
accrued employee-related costs due to better performance against our bonus metrics, the timing of
grants between years and executive awards granted in 2018 that have a partial cash payout feature.
The decrease in deferred gain and issuance costs, net was largely the result of repurchases of our
Second Lien Notes.

Mezzanine equity reflected the carrying amount of the Class A common and Class B preferred
interests held by ECR in our Ares JV. The increase in equity attributable to common stock primarily
reflected net income for the period and the issuance of common stock to an Ares-led investor group
and to Chevron in connection with the Elk Hills transaction. Equity attributable to noncontrolling
interests reflected contributions from and distributions to ECR’s Class C common interest and BSP’s
preferred interest as well as their respective share of net income for the period. See Item 8 – Financial
Statements and Supplementary Data – Note 5 Joint Ventures for more information.

Statement of Operations Analysis

Results of Oil and Gas Operations

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

on a per Boe basis for the years ended December 31, 2018, 2017 and 2016:

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

2018

2017

2016

$
$
$
$
$

18.88
17.47
1.01
9.71
2.42

$
$
$
$
$

18.64
17.48
0.70
10.85
2.34

$
$
$
$
$

15.61
14.69
0.68
10.28
2.36

(a) As described in Items 1 and 2 – Business and Properties – Our 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) Excludes corporate amounts.
(c) Field general and administrative expenses increased in 2018, compared to 2017, following the Elk Hills transaction since certain

costs are no longer collected from our former working interest partner through G&A expenses.

(d) For the years ended December 31, 2017 and 2016, certain pension benefit costs of $1 million and $2 million, respectively, 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. See Item 8 – Financial Statement and Supplementary
Data – Note 2 Accounting and Disclosure Changes for more information.

Consolidated Results of Operations

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

December 31, 2018, 2017 and 2016:

Oil and gas sales(a)
Net derivative gain (loss) 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

Net income (loss)
Net income attributable to noncontrolling interests

Net income (loss) attributable to common stock

Adjusted net income (loss)
Adjusted EBITDAX
Effective tax rate

2018

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

429
—

429
(101)

328

$
61
$ 1,117

—%

2017
(in millions)
$ 1,936
(90)
160
(876)
(249)
(544)
(136)
(22)
(106)
(343)
4
21
(17)

2016

$ 1,621
(206)
132
(800)
(235)
(559)
(144)
(23)
(79)
(328)
805
30
(13)

(262)
—

(262)
(4)

(266)

(187)
779

—%

$
$

201
78

279
—

279

(317)
616
(39)%

$
$

(a) 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. Under prior accounting standards, the 2018 total oil and gas sales would have been $2,568 million, other
revenue would have been $392 million and other expenses, net would have been $296 million. See Item 8 – Financial
Statement and Supplementary Data – Note 15 Revenue Recognition for more information.

(b) For the years ended December 31, 2017 and 2016, certain pension benefit costs of $10 million and $13 million,

respectively, have been reclassified from general and administrative expense 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. See Item 8 – Financial Statement and Supplementary Data – Note 2 Accounting and Disclosure
Changes for more information.

Year Ended December 31, 2018 vs. 2017

Oil and gas sales increased 34%, or $654 million, for 2018 compared to 2017 due to increases of
approximately $561 million, $47 million and $21 million primarily from higher oil, NGL and natural gas
realized prices, respectively, and an increase of $25 million primarily from higher natural gas
production. The higher realized oil prices reflected the significant increase in average Brent prices
between years and improved differentials.

Our total daily production volumes averaged 132 MBoe in 2018, compared with 129 MBoe in
2017, representing a year-over-year increase of 2%. Our total daily production volumes included 8
MBoe per day from the Elk Hills transaction, which closed in the second quarter of 2018. Our PSC-type
contracts negatively impacted our 2018 production by approximately 1 MBoe per day compared with
2017, without which the year-over-year production increase would have been 3%.

Net derivative gain was $1 million in 2018, compared to a loss of $90 million in 2017, representing

an overall change of $91 million. In 2018, we entered into derivative contracts to hedge our price risk
for 2019 and the first quarter of 2020, which resulted in a non-cash derivative gain of $229 million.
Offsetting this gain were settlement payments of $228 million. In 2017, we recognized a non-cash
derivative loss of $83 million related to the fair value of our derivative contracts and settlement
payments of $7 million.

The increase in other revenue of $313 million to $473 million in 2018, compared to $160 million in
2017, was largely the result of higher gas trading activity and the adoption of new accounting rules on
revenue recognition that impact the current period but not prior periods. The increase in other revenue
resulting from the accounting change was offset in its entirety by an increase in other expenses, net
with no effect on net income. The prior comparative periods were not adjusted.

Production costs in 2018 increased $36 million to $912 million or $18.88 per Boe, compared to
$876 million or $18.64 per Boe in 2017, resulting in a 1% increase on a per unit basis. The Elk Hills
transaction and cash-settled stock-based compensation added $38 million and $4 million to our 2018
costs, respectively. Without these items, our production costs would have been approximately
$870 million or $19.25 per Boe, which reflects cost savings of $17 million achieved following the Elk
Hills transaction, partially offset by higher 2018 energy costs. Elk Hills production costs are lower than
the average company-wide production costs per barrel. As a result, the Elk Hills transaction had a
favorable effect on production costs per barrel.

Our G&A expenses increased $50 million to $299 million in 2018 compared to 2017. Our cash-

settled stock-based compensation expense increased $14 million primarily due to the increase in our
stock price during the year as noted in the stock-based compensation table below. Additionally, our
G&A expenses increased following the Elk Hills transaction by approximately $8 million since certain
costs are no longer collected from our former working interest partner. The remaining change in G&A
expenses primarily related to an increase in compensation, training, community outreach and
advocacy.

DD&A expense decreased by $42 million in 2018 compared to 2017, primarily resulting from lower
DD&A rates, partially offset by higher production volumes in 2018. For example, our overall DD&A rate
for our oil and gas operations in 2018 was $9.71 compared to $10.85 in 2017. The most significant
financial statement effect from a change in our proved oil and gas reserves or impairment of the
carrying value of our proved properties would be to our DD&A rate. For example, a 5% increase or
decrease in the amount of oil and gas reserves would change our DD&A rate by approximately
$0.60 per Boe, which would increase or decrease pre-tax income (loss) by $28 million annually based
on our total production volume of 48 MMBoe for the year ended December 31, 2018.

Taxes other than on income increased 10% in 2018 compared to 2017, largely resulting from
higher GHG allowance costs. The higher costs were related to annual price increases, as well as the
state’s reduction in the number of allowances granted to us between periods.

Exploration expense increased 55% in 2018 compared to 2017, due to higher exploration activity

and dry hole costs in the fourth quarter of 2018.

The increase in other expenses of $293 million to $399 million in 2018, compared to $106 million

in 2017, was largely the result of higher gas trading activity and reporting selling costs and
unprocessed gas purchased as other expense in 2018 due to the adoption of new accounting rules on
revenue recognition that impact the current period but not the prior period. The increase resulting from
the accounting change was offset by an increase in oil and gas sales and other revenue with no effect
on net income.

Interest and debt expense, net, increased to $379 million in 2018, compared to $343 million in
2017. The increase predominantly relates to higher interest on our variable-rate debt reflecting an
overall increase in LIBOR during 2018.

In 2018 and 2017, the net gain on early extinguishment of debt consisted of the gain on open-

market repurchases, including the effect of unamortized deferred gain and issuance costs.

Other non-operating expense increased by $6 million to $23 million in 2018, compared to 2017,
primarily due to the derivative loss on our interest-rate contracts that were entered into in May 2018.

In 2018, we did not provide any current or deferred tax provision on pre-tax income of $429 million

as a result of the partial release of our valuation allowance. In 2017, we did not provide any current or
deferred tax benefit on pre-tax loss of $262 million as a result of our continued financial losses.

Net income attributable to noncontrolling interests increased by $97 million in 2018 compared to

2017, largely the result of the Ares JV entered into in February 2018.

Year Ended December 31, 2017 vs. 2016

Oil and gas net sales increased 19%, or $315 million, in 2017 compared to 2016, due to increases
of approximately $392 million, $78 million and $29 million from higher oil, NGL and natural gas realized
prices, respectively, partially offset by the effects of lower oil and natural gas production of $168 million
and $16 million, respectively. The higher realized oil prices reflected the significant increase in global
oil prices and improved differentials. Our total daily production volumes averaged 129 MBoe in 2017,
compared with 140 MBoe in 2016, representing a year-over-year decline rate of 8%. Average oil
production decreased by 9%, or 8 MBoe per day, from 91 MBoe per day in 2016 to 83 MBoe per day in
2017. NGL production was 16 MBoe per day in both 2017 and 2016. Natural gas production decreased
by 8% to 182 MMcf per day.

Net derivative losses were $90 million in 2017, compared to $206 million in 2016, representing an

overall change of $116 million. In 2017, we recorded $200 million less in non-cash derivative losses,
partially offset by a cash payment of $7 million in 2017 compared with cash proceeds of $77 million in
2016. The non-cash change reflected changes in the commodity price curves based on our derivative
positions at the end of each of the respective periods.

Other revenue increased 21%, or $28 million, in 2017 compared to 2016, due to increased natural

gas trading activity and increased third-party power sales from the Elk Hills power plant, which was
offline for about half of the first quarter of 2016 for a planned turnaround.

Production costs increased $76 million to $876 million or $18.64 per Boe in 2017, compared to
$800 million or $15.61 per Boe in 2016, resulting in a 10% increase on an absolute dollar basis. The
year-over-year increase was driven by increased activity in line with the stronger commodity prices and
higher gas and electricity costs. Total production costs in 2016 reflected management’s decision to
selectively defer workovers and downhole maintenance activity in light of low commodity prices. The
2017 costs reflected higher downhole maintenance activity in line with the current price environment.

Our G&A expenses increased $14 million to $249 million in 2017 compared to 2016. The 2017

period primarily reflected higher compensation expense related to bonus and the timing of equity-
based compensation grants between years. In 2017 and 2016, the non-cash portion of general and
administrative expenses, which was primarily comprised of equity compensation, was approximately
$16 million and $18 million, respectively.

DD&A expense decreased by $15 million in 2017 compared to 2016. Of this decrease,

approximately $45 million was attributable to lower production volumes, partially offset by an increase
in the DD&A rate of approximately $30 million.

Taxes other than on income decreased 6% in 2017 compared to 2016, largely due to lower

property taxes and GHG allowance costs.

The increase in other expenses, net of $27 million to $106 million in 2017, compared to $79 million

in 2016, was largely the result of the absence of energy and property tax refunds received in 2016 as
well as charges related to fires in the Ventura basin, increased fuel gas costs at our Elk Hills power
plant and higher accretion expense.

Interest and debt expense, net, increased to $343 million in 2017, compared to $328 million in

2016, primarily due to higher blended interest rates, increased average borrowings as a result of our
debt transactions and increased amortization of our deferred financing costs.

Net gains on early extinguishment of debt consisted of the gains on open-market repurchases in

2017 of $12 million, partially offset by a write-off of deferred financing costs related to early repayment
of our 2014 Term Loan of $8 million. Net gains on early extinguishment of debt in 2016 consisted of
open-market purchases, a debt-for-equity exchange and a cash tender for our Senior Notes.

Gains on asset divestitures reflected non-core asset sales during each of the respective periods.

Other non-operating expense in 2017 primarily reflected certain net periodic benefit costs from our

pension and postretirement benefit plans, which were reclassified from G&A expenses upon adoption
of new accounting rules in 2018.

In 2017, we did not provide any current or deferred tax benefit on pre-tax loss of $262 million as a
result of our continued financial losses. For the same period of 2016, we had a deferred tax benefit of
$78 million resulting from an adjustment to our 2015 valuation allowance. For 2016, we did not provide
a tax provision on our pre-tax income of $279 million because the exclusion of gains related to our
debt-reduction actions resulted in a tax loss, which we determined was not more-likely-than-not to be
realized in the future.

Stock-Based Compensation

Our consolidated results of operations include the effects of long-term stock-based compensation

plans under which we annually grant awards 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 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 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 income statement because we pay partially or

fully cash-settled awards based on our stock price as of the vesting date and accounting rules require
that we adjust our obligation for such awards to the amount that would be paid using our stock price as
of the end of each reporting period. Cash-settled awards, including executive awards partially settled in
cash, account for over 50% of our total outstanding awards. The increase in our stock price in 2018
resulted in higher cash-settled stock-based compensation expense in the second and third quarters of
2018 when a portion of these awards vested and our unvested awards were marked-to-market based
on the period-end stock price. In the fourth quarter of 2018, our stock price declined and the year-end
mark-to-market adjustments reduced our compensation expense. Equity-settled awards are not
similarly adjusted for changes in our stock price. Our ending stock price for each of the quarters in
2018, 2017 and 2016 was as follows:

First quarter
Second quarter
Third quarter
Fourth quarter

2018

2017

2016

$
$
$
$

17.15
45.44
48.53
17.04

$
$
$
$

15.04
8.55
10.46
19.44

$
$
$
$

10.30
12.20
12.50
21.29

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

the table below:

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

Non-GAAP Financial Measures

2016
2017
2018
(in millions, except per Boe amounts)

0.75

0.19

0.94

0.49

0.13

0.62

0.45

0.14

0.59

Our results of operations 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 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 U.S. generally accepted accounting principles (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 income (loss) attributable to common stock
Unusual, infrequent and other items:

Non-cash derivative (gain) loss from commodities, excluding
noncontrolling interest
Non-cash derivative loss from interest-rate contracts
Early retirement, severance and other costs
Net gain on early extinguishment of debt
Gain on asset divestitures
Other, net

Total unusual, infrequent and other items
Deferred debt issuance costs write-off
Reversal of valuation allowance for deferred tax assets(a)

2016

2018

2017
(in millions, except share data)
$ (262)
(4)

$ 429
(101)

$ 279
—

328

(266)

279

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

(267)
—
—

78
—
5
(4)
(21)
21

79
—
—

283
—
20
(805)
(30)
(13)

(545)
12
(63)

Adjusted net income (loss)

$ (187)

$ (317)

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

$ 6.77
$ 1.27

$ (6.26)
$ (4.40)

$ 6.76
$ (7.85)

(a) Amount represents the out-of-period portion of the valuation allowance reversal.

The following table presents the components of our net derivative gain (loss) from commodity
contracts and our non-cash derivative loss from interest-rate contracts. Our non-cash derivative loss
from interest-rate contracts is reported in other non-operating expenses.

Commodity Contracts:
Non-cash derivative gain (loss), excluding noncontrolling interest
Non-cash derivative gain (loss) included in noncontrolling interest
Net (payments) proceeds on settled commodity derivatives

Net derivative gain (loss) from commodity contracts

Interest-Rate Contracts:

Non-cash derivative loss

2018

2017
(in millions)

2016

$ 224
5
(228)

(78)
(5)
(7)

(90)

$ (283)
—
77

$ (206)

(6)

$ — $ —

We define Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation,
depletion and amortization; exploration expense; other unusual, out-of-period and infrequent 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
Income tax benefit
Depreciation, depletion and amortization
Exploration expense
Unusual, infrequent and other items
Other non-cash items

Adjusted EBITDAX

2018

2017
(in millions)

2016

429 $
379
—
502
34
(267)
40

(262) $
343
—
544
22
79
53

279
328
(78)
559
23
(545)
50

1,117 $

779 $

616

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:

Net cash provided by operating activities

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, net of accruals
Acquisitions, divestitures and other

Net cash provided (used) by financing activities

2018

2017
(in millions)

2016

461 $
441
17
199
(1)

248 $
396
20
94
21

130
384
20
95
(13)

1,117 $

779 $

616

2018

2017
(in millions)

2016

461 $

248 $

130

(621) $
(535) $
692 $

(344) $
31 $
73 $

(81)
20
(69)

$
$
$

Year Ended December 31, 2018 vs. 2017

Our net cash provided by operating activities is sensitive to many variables, including changes in

commodity prices. Commodity price sensitivity also leads to changes in other variables in our business
including adjustments to our capital program. Our operating cash flow increased 86%, or $213 million,
to $461 million in 2018 from $248 million in 2017 primarily due to higher realized prices, including the
effect of hedges, and, to a lesser degree, the Elk Hills transaction. Our operating cash flow included
payments of $124 million related to purchases of GHG allowances over the course of the year, of
which $98 million related to allowances we sold in 2016 to enhance our liquidity at the lowest point of
the commodity price cycle. The magnitude of these GHG payments are not expected in 2019.
Operating cash flow was also affected by payments made to enter into our commodity derivative
contracts as well as higher payments on our floating-interest rate debt.

Our net cash used in investing activities of $1,156 million in 2018 included $621 million of capital

investments (net of $69 million in capital-related accruals), of which $49 million was funded by BSP.
Cash used for acquisitions included $547 million primarily for the Elk Hills transaction and our new
building in Bakersfield. These uses were partially offset by $18 million in proceeds from the sale of
non-core assets. In 2017, our net cash used in investing activities of $313 million included
approximately $344 million of capital investments (net of $27 million in capital-related accruals), of
which $275 million was internally funded and reported as cash provided by financing activities. The
capital investment was partially offset by proceeds from asset divestitures of $33 million.

Our net cash provided by financing activities of $692 million in 2018 primarily comprised

$796 million in net contributions from the Ares JV and BSP JV, net proceeds from our 2014 Revolving
Credit Facility of $177 million and the issuance of common stock of $54 million primarily to an Ares-led
investor group in connection with the Ares JV, partially offset by $203 million of debt repurchases and
transaction costs and $121 million of distributions to our Ares JV and BSP JV. In 2017, our net cash
provided by financing activities of $73 million primarily comprised $1.3 billion of proceeds from our
2017 Credit Agreement and $98 million in net contributions from our BSP JV, partially offset by
$650 million in repayments on our 2014 Term Loan, $484 million of net payments on our 2014
Revolving Credit Facility and $158 million of debt repurchases and transaction costs.

Year Ended December 31, 2017 vs. 2016

Our net cash provided by operating activities is sensitive to many variables including market
changes in commodity prices. Commodity price sensitivity triggers changes in other variables in our
business including our level of workover activity and adjustments to our capital program. Operating
cash flow increased 91% or $118 million to $248 million in 2017 from $130 million in 2016 due to
higher realized prices, after hedges, on lower volumes. Production costs increased in 2017 by
$76 million as we ramped up activity primarily related to downhole maintenance and as fuel gas and
electricity prices increased. Our hedging program reduced our sensitivity to price changes.

Cash interest increased $12 million in 2017 due to higher blended interest rates and increased
borrowings on our overall debt. Taxes other than on income decreased $8 million from 2016 due to
lower property taxes and GHG taxes, partially offset by an increase in the production tax rate. Other
changes in operating cash flow related to higher general and administrative expenses and changes in
working capital.

Our net cash used in investing activities of $313 million in 2017 included approximately

$344 million of capital investments (net of $27 million in capital-related accruals), of which $275 million
was internally funded. Our share of the total capital investment of $248 million was funded with cash
from operations. The capital investment was partially offset by proceeds from asset divestitures of

$33 million. Our net cash used in investing activities of $61 million in 2016 primarily included
$81 million of capital investments (net of changes in capital-related accruals), partially offset by
$20 million from asset divestitures.

Our net cash provided by financing activities of $73 million in 2017 primarily comprised $1.3 billion

of proceeds from our 2017 Credit Agreement and $98 million in net contributions from our BSP JV,
partially offset by $650 million in repayments on our 2014 Term Loan, $484 million of net payments on
our 2014 Revolving Credit Facility, $158 million of debt repurchases and transaction costs and
$8 million of distributions paid to BSP. In 2016, our net cash used by financing activities of $69 million
included approximately $821 million in debt repurchases and transaction costs and $350 million of
payments on our 2014 Term Loan, partially offset by the $990 million in proceeds from the issuance of
our 2016 Credit Agreement and $108 million of net proceeds from our 2014 Revolving Credit Facility.

Liquidity

Our primary sources of liquidity and capital resources are cash flow from operations and available

borrowing capacity under our 2014 Revolving Credit Facility. We also rely on other sources such as
JVs to supplement our capital program, fund acquisitions and for other corporate purposes. Our 2019
capital program will be dynamic and will be adjusted based on realized price trends during the year.
We expect to fund our portion of the 2019 capital program with cash flow from operations.

In February 2018, we entered into the Ares JV where we received $747 million in net proceeds

and raised $50 million in a private placement of our common stock with an Ares-led investor group. A
portion of the net proceeds from the Ares JV were used to pay off the then outstanding balance on our
2014 Revolving Credit Facility and the remaining proceeds were used to fund a strategic acquisition in
April 2018 when we acquired the remaining working, surface and mineral interests in the former Elk
Hills unit for $460 million in cash and 2.85 million shares of our common stock. On an annualized
basis, this transaction, including synergies, added over approximately $130 million to our operating
cash flow, at about $65 Brent. During 2017, we closed two key JV transactions with BSP and MIRA.
Under these arrangements, our JV partners have invested approximately $260 million in our drilling
programs from inception through the end of 2018, some of which is not included in our consolidated
results.

Significant changes in oil and natural gas prices have a material impact on our liquidity. Declining
commodity prices negatively affect our operating cash flow, and the inverse applies during periods of
rising commodity prices. To mitigate some of the risk inherent in the downward movement in oil prices,
we have utilized various derivative instruments to hedge price risk.

Debt

As of December 31, 2018, our long-term debt consisted of the following credit agreements, second

lien notes and senior notes:

Outstanding
Principal
(in millions)

Interest Rate

Maturity

Security

Credit Agreements

2014 Revolving Credit Facility $

540

2017 Credit Agreement

1,300

LIBOR plus
3.25%-4.00%
ABR plus
2.25%-3.00%
LIBOR plus 4.75%
ABR plus 3.75% December 31, 2022(a) 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

2,067

December 15, 2022(b)

Second-Priority Lien

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

100
100
144

5%
5.5%
6%

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

Unsecured
Unsecured
Unsecured

Total

5,251

(a) 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.

(b) The Second Lien Notes require principal repayments of approximately $326 million in June 2021, $65 million in December

2021 and $68 million in June 2022.

As of December 31, 2018, we had approximately $298 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, 2018
and 2017, we had letters of credit of approximately $162 million and $148 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 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 currently have the following Brent-based
crude oil contracts, as of February 27, 2019:

Q1
2019

Q2
2019

Q3
2019

Q4
2019

Q1
2020

Sold Calls:

Barrels per day
Weighted-average price per barrel

15,000
$ 66.15

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

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

2,000
$ 71.00

38,000
$ 65.66

Sold Puts:

Barrels per day
Weighted-average price per barrel

40,000
$ 51.88

Swaps:

Barrels per day
Weighted-average price per barrel

7,000
$ 67.71

5,000
68.45

—
— $

—
—

40,000
69.75

35,000
55.71

40,000
73.13

40,000
57.50

35,000
75.71

35,000
60.00

10,000
75.00

10,000
60.00

—
— $

—
—

The BSP JV entered into crude oil derivatives that are included in our consolidated results but not

included above. The hedges entered into by the BSP JV could affect the timing of the redemption of
the JV interest. The BSP JV sold calls for up to approximately 1,000 barrels per day at a weighted-
average price per barrel of $60.00 per barrel for 2019 through 2020. The BSP JV purchased puts for
up to approximately 2,000 barrels per day at a weighted-average price per barrel of approximately
$50.00 for 2019 through 2021. The BSP JV also entered into natural gas swaps for insignificant
volumes for periods through May 2021.

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. 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.

2018 and 2019 Capital Program

We create value by investing our operating cash flow back into our business. In 2018, we focused

our capital program on oil projects that provide high margins and low decline rates, which we believe
will generate positive cash flow to fund capital program that will grow production. 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 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. 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.

2018 Capital Program

In 2018, we invested approximately $690 million of capital, including $49 million funded by BSP.

Our JV partner MIRA funded an additional $57 million of investment, which is not included in our
consolidated results, bringing our total capital deployed to $747 million as compared to $429 million in
2017. Our capital predominantly targeted projects in the San Joaquin and Los Angeles basins. Our
2018 capital was primarily directed towards oil-weighted production consistent with prior periods. Of
the total 2018 capital program, approximately $396 million was allocated to drilling wells, $98 million to
capital workovers, $129 million to facilities and compression expansion, $36 million to maintenance
and occupational health, safety and environmental projects and $31 million to exploration and other
items.

The table below sets forth our capital investments by basin and recovery mechanism for the year

ended December 31, 2018 (in millions):

Conventional

Primary

Waterflood

Steamflood

Total

Unconventional
Primary

Other

Total Capital
Investments

Basin:

San Joaquin
Los Angeles
Ventura
Sacramento

Basin Total

Exploration and
other

93 $
—
22
7

122

—

Total

122 $

2019 Capital Program

113
155
10
—

278

—

278

59 $
—
1
—

—

265 $
155
33
7

460

199 $
—
—
—

199

—

— $
—
—
—

—

60 $

460 $

199 $

31 $

464
155
33
7

659

690

We entered 2019 with an internally funded capital program of $300 to $385 million, which may be
adjusted during the course of the year depending on commodity prices. We are also in discussions to
obtain additional investments from new and existing JV partners that could increase our capital
program by $100 to $150 million to support a capital program of approximately $500 million.

We are focusing our 2019 capital on oil projects. Our approach to our 2019 drilling 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 BSP and MIRA joint ventures 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 on our core fields: Elk Hills and surrounding areas, Wilmington, Kern

Front and the delineation and appraisal of other long-term prospects.

We plan to use 60% of our capital program on drilling and development of conventional and

unconventional resources. The depth of our conventional wells is expected to range from 2,000 to
15,000 feet. Our conventional program includes approximately 140 wells primarily in Wilmington,
Huntington Beach, Kern Front and Mount Poso, which will largely consist of waterfloods and
steamfloods along with some primary drilling. We also intend to drill approximately 10 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.

We also plan to use approximately 15% of our 2019 capital program for capital workovers on

existing well bores. Capital workovers are some of the highest VCI projects in our portfolio and
generally include well deepenings, recompletions, changes of lift methods and other activities designed
to add incremental productive intervals and reserves.

Further, over 15% of our 2019 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 safety. About 10% is intended to be used for
exploration and other corporate uses.

As a result of higher activity levels, including the Elk Hills transaction, our production grew
sequentially every quarter during 2018. The actions we have taken to streamline our business and
reduce costs, together with higher realized prices, have enabled us to invest in our business and grow
our production. In addition, we will continue to build our inventory of available projects, which we
believe will position us to accelerate value by utilizing third-party capital and take advantage of
potential future commodity price increases.

Off-Balance-Sheet Arrangements

As of December 31, 2018, we had letters of credit of $162 million under our 2014 Revolving Credit

Facility and no other material off-balance-sheet arrangements other than operating leases and
purchase obligations included in our Contractual Obligations table below.

Contractual Obligations

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

2018. This summary indicates on- and off-balance-sheet obligations as of December 31, 2018.

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

Off-Balance Sheet

Operating leases(d)
Purchase obligations(e)

Payments Due by Year

Total

Less than
1 Year

1-3 Years
(in millions)

3-5 Years

More than
5 Years

5,251
1,535
433
147
6

68
172

$ — $
444
31
6
—

12
65

5,107
1,075
—
25
6

22
73

144
16
—
26
—

17
16

—
—
402
90
—

17
18

Total(f)

7,612

558

6,308

219

527

(a)

In performing the calculation, the 2014 Revolving Credit Facility borrowings outstanding at December 31, 2018 of
$540 million were assumed to be outstanding for the entire term of the agreement. See 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,

2018 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 Item 8 – Financial Statements and
Supplementary Data – Note 1 Nature of Business, Summary of Significant Accounting Policies and Other for more
information.

(d) Amounts include obligations for office space and vehicles.
(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, land easements and field equipment. Obligations for
field equipment include contractual agreements with third parties for drilling rigs and other related services. 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.

(f) Amounts exclude unrecognized tax benefit of $25 million due to uncertainty with respect to the timing of future cash

outflows.

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, 2018 and 2017 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 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, asset

retirement obligations and fair value measurements. See 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 financial statements due to the levels of
subjectivity and judgment.

Significant Accounting and Disclosure Changes

See 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:

•

•
•
•
•

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

•

•
•
•

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:

•
•

•

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,
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

•

•
•

•

PSC effects on production and unit
production costs
effect of stock price on costs
associated with incentive compensation
insufficient capital, 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, transportation or
storage constraints, natural disasters,
labor difficulties, cyber attacks or other
catastrophic events
factors discussed in 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 gas prices. In 2019, 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 2019 Price Sensitivities
$1 change in Brent index - Oil(a)
$1 change in Brent index - NGLs
$0.10 change in NYMEX - Gas(b)

(in millions)

24.0
3.5
3.8

$
$
$

(a) Amount reflects the upside sensitivity.
(b) Amount reflects the sensitivity with respect to unhedged volumes and includes the offsetting effect of internal gas use in

the operations.

As a result of our 2019 hedge positions, we protected our downside price risk on approximately

45,000 and 40,000 barrels of oil per day at approximately $66 Brent and $70 Brent per barrel,
respectively, for the first and second quarters of 2019. For the third and fourth quarters of 2019, we
protected our downside price risk on approximately 40,000 and 35,000 barrels of oil per day at
approximately $73 Brent and $76 Brent per barrel, respectively. The underlying instruments in our
2019 hedge program are puts and put spreads. For the full year 2019, we are protected at a weighted-
average Brent price of approximately $71 per barrel, and Brent plus approximately $15 if Brent were to
fall below a weighted-average of $56 per barrel. Except for a small portion primarily in the first quarter
of 2019, the 2019 hedges do not contain caps, thereby providing upside to oil price movements.

Due to our 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, 2018, we recognized a net asset of $178 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. Based on the $178 million net derivative asset as of
December 31, 2018, a 10% increase or decrease in their fair value would affect pre-tax earnings by
approximately $18 million. See additional hedging information in Item 7 – Management’s Discussion
and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

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, 2018, 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, 2018 was not material and losses associated with credit risk have been
insignificant for all years presented.

Interest-Rate Risk

As of December 31, 2018, we had borrowings of $1.3 billion outstanding under our 2017 Credit

Agreement, $1 billion outstanding under our 2016 Credit Agreement and $540 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, 2018, 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. As of December 31, 2018, we
recognized a net asset of $4 million for our interest-rate contracts which are carried at fair value, using
industry-standard models with various inputs, including the LIBOR forward curve.

The following table shows our fixed- and variable-rate debt as of December 31, 2018 (in millions):

Year of Maturity

2019
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

Total

—
100
491
1,676
—
144

2,411

7.65%

1,652

—
—
1,540
1,300
—
—

2,840

9.13%

2,840

—
100
2,031
2,976
—
144

5,251

8.45%

4,492

(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, 2018 and 2017, 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, 2018, 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, 2018, 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, 2018 and 2017, and the results of
its operations and its cash flows for each of the years in the three-year period ended December 31,
2018, 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, 2018, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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.

/s/ KPMG LLP

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

Los Angeles, California
February 27, 2019

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2018 and 2017
(in millions, except share data)

2018

2017

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

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

Preferred stock (20 million shares authorized at $0.01 par value)
no shares outstanding at December 31, 2018 or 2017
Common stock (200 million shares authorized at $0.01 par value)
outstanding shares (2018 — 48,650,420 shares and
2017 — 42,901,946 shares)
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss

Total equity attributable to common stock

Noncontrolling interests

Total equity

17 $

299
69
255

640
22,523
(16,068)

6,455
63

7,158 $

390
217

607
5,251
216
575

756

—

—
4,987
(5,342)
(6)

(361)
114

(247)

20
277
56
130

483
21,260
(15,564)

5,696
28

6,207

257
475

732
5,306
287
602

—

—
4,879
(5,670)
(23)

(814)
94

(720)

TOTAL LIABILITIES AND EQUITY

7,158 $

6,207

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, 2018, 2017 and 2016
(in millions, except per share data)

REVENUES AND OTHER
Oil and gas sales
Net derivative gain (loss) from commodity contracts
Other revenue

Total revenues and other

2018

2017

2016

2,590 $
1
473

1,936 $ 1,621
(206)
132

(90)
160

3,064

2,006

1,547

912
299
502
149
34
399

2,295

769

(379)
57
5
(23)

429
—

429
(101)

876
249
544
136
22
106

800
235
559
144
23
79

1,933

1,840

(293)

(343)
4
21
(17)

(262)
—

(262)
(4)

(328)
805
30
(13)

201
78

279
—

279

328 $

(266) $

6.77 $
6.77 $

(6.26) $
(6.26) $

6.76
6.76

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

Total costs and other

OPERATING INCOME (LOSS)

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 benefit

NET INCOME (LOSS)
Net income attributable to noncontrolling interests

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

Net income (loss) 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, 2018, 2017 and 2016
(in millions)

Net income (loss)
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)

Comprehensive income attributable to noncontrolling interests

2018

2017

2016

429 $ (262) $

279

17
(101)

(14)

(9)
(4)

(9)

1
—

Comprehensive income (loss) attributable to common stock

345 $ (275) $

280

(a) No associated tax for 2018, 2017 and 2016. See 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, 2018, 2017 and 2016
(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, 2015

Net income
Other comprehensive income
Share-based compensation, net

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

4,782
—
—
79

4,861
—

(5,683)
279
—
—

(5,404)
(266)

—

—
—
18

—

—
—
—

4,879
—

(5,670)
328

—

—
101
—
7

—

—
—
—
—

Balance, December 31, 2018

4,987

(5,342)

(15)
—
1
—

(14)
—

—

—
(9)
—

(23)
—

—

—
—
17
—

(6)

(916)
279
1
79

(557)
(266)

—

—
(9)
18

(814)
328

—

—
101
17
7

— $
—
—
—

— $
4

(8)
—
—

94 $

(64)
—
—
—

(916)
279
1
79

(557)
(262)

(8)
(9)
18

(720)
330

(64)
101
17
7

(361)

114 $

(247)

Note: Excludes amounts related to redeemable noncontrolling interests recorded in mezzanine equity. See Note 5 Joint

(a)

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 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 Note 4 Acquisitions and Divestitures and 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, 2018, 2017 and 2016
(in millions)

CASH FLOW FROM OPERATING ACTIVITIES

Net income (loss)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:

Depreciation, depletion and amortization
Deferred income tax benefit
Net derivative (gain) loss from commodity contracts
Net (payments) proceeds 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:

Increase in trade receivables
(Increase) decrease in inventories
(Increase) decrease 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 2016 Credit Agreement
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 provided (used) by financing activities

(Decrease) increase in cash

Cash—beginning of year
Cash—end of year

2018

2017

2016

429 $

(262) $

279

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)

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)
73
8

20
17 $

12
20 $

559
(78)
206

77
(805)
(71)
(30)
101
3

(33)
—
25
(103)
130

(75)
(6)
20
—
—
(61)

2,218
(2,110)
990
—
(350)
(770)
(51)
—
—
4
—
(69)
—

12
12

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 remained a wholly
owned subsidiary of Occidental until November 30, 2014. On November 30, 2014, Occidental
distributed shares of our common stock on a pro-rata basis to Occidental stockholders (the Spin-off).
We became an independent, publicly traded company on December 1, 2014. Occidental initially
retained approximately 18.5% of our outstanding shares of common stock, which it distributed to
Occidental stockholders on March 24, 2016.

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, and all references to ‘‘Occidental’’ refer to Occidental Petroleum Corporation, our former
parent, and its subsidiaries.

Basis of Presentation

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 all of our significant intercompany
transactions and accounts. We account for our share of oil and gas exploration and production
ventures, 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.

Certain prior year amounts have been reclassified to conform to the 2018 presentation. On the

statements of operations for 2017 and 2016, we reclassified interest cost, expected return on assets,
amortization of prior service costs and settlements/curtailments, all associated with defined benefit
pension plans, from general and administrative expenses to other non-operating expenses in
accordance with new accounting rules. See Note 2 Accounting and Disclosure Changes for more
information.

On May 31, 2016, we completed a reverse stock split using a ratio of one share of common stock
for every ten shares then outstanding. Share and per share amounts included in this report have been
restated to reflect this reverse stock split. The split proportionally decreased the number of authorized
shares of common stock from 2.0 billion shares to 200 million shares and preferred stock from
200 million to 20 million shares.

Risks and Uncertainties

The process of preparing financial statements in conformity with United States (U.S.) generally
accepted accounting principles (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 financial statements.

Concentration of Customers

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, 43% of our oil and
gas sales and other revenue. For the years ended December 31, 2017 and 2016, our principal
customers, Phillips 66 Company, Andeavor (formerly Tesoro Refining & Marketing Company LLC),
Valero Marketing & Supply Company and Shell Trading (US) Company, each accounted for at least
10%, and, collectively, 67% of our oil and gas sales and other revenue.

Critical Accounting Policies

Property, Plant and Equipment

We use the successful efforts method to account for our oil and 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 some cases, we cannot determine whether we have found proved
reserves at the completion of exploration drilling, and must conduct additional testing and evaluation of
the wells. We generally expense the costs of such exploratory wells if we do not determine we have
found proved reserves within a 12-month period after drilling is complete.

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 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 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 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.

A portion of the carrying value of our oil and gas properties is attributable to unproved properties.

At December 31, 2018, the net capitalized costs attributable to unproved properties were
approximately $284 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. The unproved amounts are not subject to depreciation, depletion and amortization
(DD&A) until they are classified as proved properties.

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.

We determine depreciation and depletion of oil and gas producing properties by the

unit-of-production method. 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 gas
reserves are capitalized.

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 $402 million and $403 million is

included in other long-term liabilities, with the remaining current portion in accrued liabilities at
December 31, 2018 and 2017, respectively.

Beginning balance
Liabilities incurred, capitalized to PP&E
Liabilities settled and paid
Accretion expense
Acquisitions, capitalized to PP&E(a)
Dispositions and other, reduction to PP&E
Revisions in estimated cash flows, changes in PP&E

Ending balance

For the years ended
December 31,

2018

2017

(in millions)
422 $
4
(15)
27
8
(2)
(11)

433 $

411
2
(9)
25
—
—
(7)

422

(a)

Includes $7 million related to the Elk Hills transaction and $1 million related to other acquisitions in 2018.

Fair Value Measurements

We have categorized our assets and liabilities that are measured at fair value 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 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 at which transactions are
executed in the marketplace. We classify these measurements as Level 2. The most significant items
on our balance sheet that would be affected by recurring fair value measurements are derivatives.

Our 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, 2018 and 2017 consisted of the
following:

Materials and supplies
Finished goods

Total

Derivative Instruments

2018

2017

(in millions)
65 $
4

69 $

53
3

We apply hedge accounting when transactions meet specified criteria for cash-flow hedge

treatment and management elects and documents such treatment. 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.

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.

Stock-Based Incentive Plans

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

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 recover our share of capital and production costs, and 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, 2018.

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 sponsored by us. 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, 2018 and 2017 included approximately $2 million and $5 million,

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

Other Current Assets

Other current assets, net as of December 31, 2018 and 2017 consisted of the following:

Derivative assets
Amounts due from joint interest partners
Prepaid expenses
Assets held for sale
Other

Other current assets, net

2018

2017

(in millions)

168
68
16
—
3

255

23
76
19
12
—

130

Accrued Liabilities

Accrued liabilities as of December 31, 2018 and 2017 consisted of the following:

Accrued employee-related costs
Accrued taxes other than on income
Current portion of asset retirement obligation
Accrued interest
Derivative liabilities
Other

Accrued liabilities

Supplemental Cash Flow Information

2018

2017

(in millions)
109
38
31
15
3
21

217

86
130
19
23
154
63

475

We did not make any U.S. federal and state income tax payments in 2018, 2017 or 2016. Interest
paid, net of capitalized amounts, totaled approximately $433 million, $393 million and $382 million for
the years ended December 31, 2018, 2017 and 2016, respectively. 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 Issued Accounting and Disclosure Changes

In February 2016, the Financial Accounting Standards Board (FASB) issued rules requiring
lessees to recognize assets and liabilities on the balance sheet for the rights and obligations created
by all leases with terms of more than 12 months and to include qualitative and quantitative disclosures
with respect to the amount, timing, and uncertainty of cash flows arising from leases. In January 2018,
the FASB issued an update to the lease standard providing an optional transition approach for land
easements allowing entities to evaluate only new or modified land easements. In July 2018, the FASB
provided optional transition relief allowing a prospective approach in applying the new rules by not
adjusting comparative period financial information for the effects of the new rules and not requiring
disclosures for periods before the effective date. In December 2018, the FASB issued an update to the
lease standard for lessors regarding certain tax and other costs and the reporting of these costs
against rental income. These rules will be effective for us on January 1, 2019, which we expect to
apply prospectively. We are currently evaluating the impact of this accounting standard on our financial
statements. We expect the adoption of these rules to increase both our assets and liabilities by an
equal amount, which we do not expect to be material to our consolidated balance sheets.

Recently Adopted Accounting and Disclosure Changes

In May 2014, the FASB issued rules on the recognition of revenue that created Topic 606 (ASC
606), which superseded existing revenue recognition requirements reported in accordance with GAAP,
and required an entity to recognize revenue when it transfers promised goods or services to customers
in an amount that reflects the consideration the entity expects to receive in exchange for those goods
or services. The new rules required certain sales-related costs to be reported as other expense as
opposed to being netted against oil and gas sales or other revenue. We adopted ASC 606 on
January 1, 2018 using the modified retrospective method with no adjustment to opening retained
earnings. Results for reporting periods beginning after January 1, 2018 are presented under ASC 606,
while prior period amounts are not adjusted and continue to be reported under the accounting
standards in effect prior to adoption. See Note 15 Revenue Recognition for more information.

In March 2017, the FASB issued rules requiring employers that sponsor defined benefit plans for

pensions and postretirement benefits to present the service cost component of net periodic benefit cost
in the same income statement line item as other employee compensation costs arising from services
rendered during the period. Only the service cost component will be eligible for capitalization to assets.
Under the new rules, employers are required to present the other components of the net periodic
benefit cost separately from the line item that includes the service cost and outside of any subtotal of
operating income. We adopted these rules in the first quarter of 2018 with no significant impact on our
financial statements. The interest cost, expected return on assets, amortization of prior service costs
and settlements/curtailments have been reclassified from general and administrative expense to other
non-operating expenses. We elected to use the amounts disclosed for the various components of net
periodic benefit cost in the pension and postretirement benefit plans footnote as the basis of the
retrospective application.

In August 2018, the FASB issued rules to amend the guidance on defined benefit pension and
postretirement plans. The rules add, remove and clarify specific requirements of disclosures in the
notes to financial statements. We early adopted these rules retrospectively in 2018 with changes
reflected in Note 14 Pension and Postretirement Benefit Plans.

In May 2017, the FASB issued rules to simplify the guidance on the modification of share-based
payment awards. The amendments provide clarity on which changes to the terms or conditions of a
share-based payment award require an entity to apply modification accounting prospectively. We
adopted these rules in the first quarter of 2018 with no impact on our financial statements.

Components of accumulated other comprehensive income (AOCI) are recorded net of related
taxes determined using prevailing rates when the components are initially recorded. When the U.S.
federal corporate tax rates changed in December 2017, a difference arose between tax amounts
reported in AOCI as compared to the expected tax amount using the newly enacted corporate tax
rates. Our accounting policy is to remove such residual tax differences from AOCI when the related
components are ultimately settled. In February 2018, the FASB issued rules that give entities the
option to reclassify this residual difference from AOCI to retained earnings. We early adopted this
accounting standard in the first quarter of 2018 without reclassifying this residual tax difference to
retained earnings.

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
2018, 2017 or 2016.

Property, plant and equipment, net as of December 31, 2018 and 2017 consisted of the following:

Proved oil and gas properties
Unproved oil and gas properties
Facilities and other

Total property, plant and equipment

Accumulated depreciation, depletion and amortization

2018

2017

(in millions)

20,882
1,103
538

22,523
(16,068)

19,664
1,111
485

21,260
(15,564)

Total property, plant and equipment, net

6,455

5,696

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

ended December 31:

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

2018

4
19
(2)
(16)

2017
(in millions)
4
$
4
(2)
(2)

2016

6
1
—
(3)

In April 2018, we acquired the remaining working, surface and mineral interests in the 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. After the transaction, we hold all of the working, surface and
mineral interests in the former Elk Hills unit. The effective date of the transaction was April 1, 2018.

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 (in millions):

Consideration:

Cash
Common stock issued (2.85 million shares)
Liabilities assumed

Identifiable assets acquired:

Proved properties
Other property and equipment
Materials and supplies

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.

Also in April 2018, we acquired an office building and land in Bakersfield, California for
$48.4 million, which we believe is significantly less than the estimated replacement value of the
property and the land. We have approximately 500 employees who have been using eight different
locations in Bakersfield across multiple leases. We expect that the new building will create significant
value by bringing our Bakersfield employees together into a single location, which will increase the
efficiency, effectiveness and collaboration of these employees. This building was the only available

office space in the Bakersfield area large enough to allow us to consolidate our workforce in a single
location. 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 upstream acquisitions totaling approximately $39 million in

2018, excluding assumed ARO liabilities of $1 million.

Divestitures

NOTE 5

JOINT VENTURES

Noncontrolling Interests

The following table presents the changes in noncontrolling interests by JV partners (described in

greater detail below), reported in equity and mezzanine equity on the consolidated balance sheets, for
the years ended December 31, 2018 and 2017:

Equity Attributable
to Noncontrolling Interest
Total
(in millions)

Ares JV BSP 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

— $
(11)
33
(7)

94
13
49
(57)

94
2
82
(64)

Balance, December 31, 2018

114

—
99
714
(57)

756

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.

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.

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. BSP funded a total of $150 million in three equal tranches, before transaction costs, in March
2017, July 2017 and June 2018. The funds contributed by BSP were used to develop certain of our oil
and 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 our 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

In October 2018, we entered into a development JV for a three-year program to drill 20 wells

where our JV partner committed approximately $23 million and we are investing approximately
$13 million. We also entered into two exploration JVs where our JV partners have an initial total
commitment of approximately $12 million. If certain milestones are met on the initial wells, the parties
may move forward with a mutually agreed drilling program. Our consolidated results reflect only our
working interest share in these JVs.

In April 2017, we entered into a development JV with Macquarie Infrastructure and Real Assets

Inc. (MIRA) under which MIRA will invest up to $300 million, subject to agreement of the parties to
develop certain of our oil and gas properties in exchange for a 90% working interest in the related
properties. MIRA will fund 100% of the development cost of such properties. Our 10% working interest
increases to 75% if MIRA receives cash distributions equal to a predetermined threshold return. MIRA
initially committed $160 million, which was intended to be invested over two years. In June 2018, the
parties amended the joint development program to $140 million. The agreement provides for a
commitment of up to 110% of the program amount. MIRA invested $58 million in 2017 and $57 million
in 2018. Our consolidated results reflect only our working interest share in this JV.

NOTE 6 DEBT

As of December 31, 2018 and 2017, our long-term debt consisted of the following credit

agreements, second lien notes and senior notes:

Outstanding Principal
(in millions)

2018

2017

Interest Rate

Maturity

Security

Credit Agreements

2014 Revolving Credit
Facility

540 $

363

2017 Credit Agreement

1,300

2016 Credit Agreement

1,000

Second Lien Notes

2,067

2,250

Senior Notes

5% Senior Notes due

2020

5 1⁄ 2% Senior Notes

due 2021

6% Senior Notes due

2024

Total

100

144

100

193

5,251 $

5,306

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(a)

December 31, 2021

December 15, 2022(b)

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) 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.

(b) The Second Lien Notes require principal repayments of approximately $326 million in June 2021, $65 million in December

2021 and $68 million in June 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, 2018, we had approximately $298 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, 2018
and 2017, we had letters of credit of approximately $162 million and $148 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 a London Interbank Offered Rate (LIBOR) rate 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 October 2018. 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.

Financial Covenants – As of December 31, 2018, 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:

•
•
•

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 2018 and became effective in September 2018. The 2014 Credit Agreement was amended to,
among other things:

•

permit us to draw on our revolver to repurchase up to $300 million of our Second Lien Notes
and Senior Notes at a discount to par;
permit us to draw on our revolver to repurchase our Second Lien Notes and Senior Notes at a
discount to par, without regard to time limit, in an amount not to exceed a specified portion of
proceeds from future dispositions of certain assets;
in connection with any repurchase of certain of our indebtedness, increase the minimum
liquidity required to make such repurchase (calculated on a pro forma basis after giving effect
to the repurchase) from $250 million to $300 million; and
enhance our ability to refinance our outstanding term loans under our 2017 Credit Agreement
and 2016 Credit Agreement, Second Lien Notes and Senior Notes, in each case by allowing
the use of permitted refinancing indebtedness for such refinancing so long as certain
conditions are met.

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 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, 2018, 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.

Recent Amendments – In September 2018, our 2017 Credit Agreement was most recently

amended to, among other things:

•

permit us to repurchase our Second Lien Notes and Senior Notes at a discount to par, without
regard to time limit, in an amount not to exceed a specified portion of proceeds from
dispositions of certain assets; and
enhance our ability to refinance our outstanding Second Lien Notes, Senior Notes and 2016
Credit Agreement, in each case by allowing the use of permitted refinancing indebtedness for
such refinancing so long as certain conditions are met.

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, 2018, 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.

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 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.

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 1⁄ 2% 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 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. In 2017, we repurchased $128 million in face value of our 2020 Notes and 2021 Notes
for $116 million in cash, resulting in a $12 million pre-tax gain.

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, 2018, net deferred gain and issuance costs were $216 million, consisting of

$313 million of deferred gains offset by $97 million of deferred issuance costs and original issue
discounts. The December 31, 2017 net deferred gain and issuance costs were $287 million, consisting
of $415 million of deferred gains offset by $128 million of deferred issuance costs and original issue
discounts.

Other

At December 31, 2018, 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.

Principal maturities of long-term debt outstanding at December 31, 2018 are as follows (in

millions):

2019
2020
2021
2022
2023
Thereafter

Total

—
100
2,031
2,976
—
144

5,251

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,

2018 and 2017, including the fair value of the variable-rate portion, was approximately $4.5 billion and
$4.8 billion, respectively, compared to a carrying value of approximately $5.3 billion in both periods.

NOTE 7 LEASE COMMITMENTS

We have entered into various operating lease agreements, mainly for office space and vehicles.

We lease assets when leasing offers greater operating flexibility. Lease payments are expensed as
part of production costs or general and administrative expenses. At December 31, 2018, future
minimum lease payments for noncancelable operating leases (excluding oil and natural gas and other
mineral leases, utilities, taxes, insurance and common area maintenance expenses) totaled (in
millions):

2019
2020
2021
2022
2023
Thereafter

Total

12
8
7
7
6
28

Rental expense for operating leases was $11 million in 2018 and $13 million in both 2017 and
2016. Rental income from subleases was approximately $4 million in 2018 and was de minimis in 2017
and 2016.

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, 2018 and 2017 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, 2018, total purchase obligations on a discounted basis were as follows (in
millions):

2019
2020
2021
2022
2023
Thereafter

Total

65
63
6
4
10
24

172

100

In October 2018, the Internal Revenue Service (IRS) completed its audit of our U.S. federal

income tax returns for the post-Spin-off period in 2014 and calendar year 2015. There were no
changes to our tax filings as a result of the audit. We remain subject to audit by the IRS for calendar
years 2016 and 2017 as well as for all periods subsequent to the Spin-off 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, 2018, 2017 and 2016. As part of our hedging program, we held the
following Brent-based crude oil contracts as of December 31, 2018:

Sold Calls:

Barrels per day
Weighted-average price per barrel

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

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
2019

Q2
2019

Q3
2019

Q4
2019

Q1
2020

15,000
$ 66.15

5,000
$ 68.45

—
— $

2,000
$ 71.00

—
— $

—
—

38,000
$ 65.66

40,000
$ 69.75

40,000
$ 73.13

35,000
$ 75.71

10,000
$ 75.00

40,000
$ 51.88

35,000
$ 55.71

40,000
$ 57.50

35,000
$ 60.00

10,000
$ 60.00

7,000
$ 67.71

—
— $

—
—

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 redemption of
the JV interest. The BSP JV sold calls for up to approximately 1,000 barrels per day at a weighted-
average price per barrel of $60.00 per barrel for 2019 through 2020. The BSP JV purchased puts for
up to approximately 2,000 barrels per day at a weighted-average price per barrel of approximately
$50.00 for 2019 through 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:

•

Sold calls – we make settlement payments for prices above the indicated weighted-average
price per barrel.
Purchased calls – we receive settlement payments for prices above the indicated weighted-
average price per barrel.

101

•

Purchased puts – we receive settlement payments for prices below the indicated weighted-
average price per barrel.
Sold puts – we make settlement payments for prices below the indicated weighted-average
price per barrel.

From time to time, we may use combinations of these positions to increase the efficacy of our

hedging program.

For the years ended December 31, 2018, 2017 and 2016, we recognized a non-cash derivative
gain (loss) of approximately $229 million, $(83) million and $(283) million, respectively, from marking
these contracts to market, which were included in net derivative gain (loss) from commodity contracts
on our consolidated statements of operations. For the years ended December 31, 2018 and 2017, we
made settlement payments of $228 million and $7 million, respectively. For the year ended
December 31, 2016, we received settlement payments of $77 million.

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 year ended December 31, 2018, we reported a $6 million loss on these contracts in other
non-operating expense on our consolidated statements of operations. No payments were received in
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, 2018 and 2017 (in millions):

December 31, 2018

Balance Sheet Classification

Gross
Amounts
Recognized at
Fair Value

Gross
Amounts
Offset in the
Balance Sheet

Net Fair Value
Presented in
the Balance
Sheet

Assets:
Other current assets
Other assets

Liabilities:
Accrued liabilities
Other long-term liabilities

252
23

(84) $
(9)

(87)
(10)

178

84
9

— $

168
14

(3)
(1)

178

102

December 31, 2017

Gross
Amounts
Recognized at
Fair Value

Gross
Amounts
Offset in the
Balance Sheet

Net Fair Value
Presented in
the Balance
Sheet

39 $
1

(16) $
—

(170)
(3)

16
—

(133) $

— $

23
1

(154)
(3)

(133)

Balance Sheet Classification

Assets:
Other current assets
Other assets

Liabilities:
Accrued liabilities
Other long-term liabilities

Interest-Rate Contracts

As of December 31, 2018, we reported the fair value of our interest-rate derivatives of $4 million 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, 2018, 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, 2018 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. We had no collateral posted, and held no collateral, at December 31,
2018 and 2017.

NOTE 10 INCOME TAXES

Prior to the Spin-off date, we were included in the Occidental income tax returns for all applicable
years. Under the tax sharing agreement, Occidental controls tax examinations for the periods in which
we were included in a consolidated or combined income tax return filed by Occidental. There were no
amounts due to Occidental as of December 31, 2018 and 2017 under the tax sharing agreement.

The Tax Cuts and Jobs Act (the Tax Act) was enacted on December 22, 2017. The Tax Act
includes significant changes to U.S. income tax and related laws. In addition to the reduction in the top
corporate tax rate, other provisions of the Tax Act include, but are not limited to, fully expensing the
cost of acquired qualified property, subject to certain phase-out provisions, and limiting the deduction
for interest expense. We evaluated the provisions of the Tax Act, most of which are effective
January 1, 2018, and determined that because of our current tax position and resulting valuation
allowance, there was no net impact on our financial statements.

103

Income Tax Expense (Benefit)

Income (loss) before income taxes, which is all domestic, was $429 million, $(262) million and

$201 million for the years ended December 31, 2018, 2017 and 2016, respectively. We had no
provision (benefit) for federal, state and local income taxes in each of the years ended December 31,
2018 and 2017. For the year ended December 31, 2016, we recognized a $78 million deferred tax
benefit, which consisted of $66 million in the U.S. federal jurisdiction and $12 million deferred tax
benefit for state and local taxes.

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:

Effective tax rate

For the years ended
December 31,
2017

2018

2016

21%
6
(5)
—
(6)
—
—
(17)
1

—%

(35)%
(6)
—
91
(19)
—
1
(33)
1

—%

35 %
6
—
—
—
(275)
2
192
1

(39)%

Our effective tax rate is affected by recurring items such as permanent differences, tax deductions

related to equity compensation which is different from compensation expense recognized in the
financial statements and income included in our consolidated results which is taxed to noncontrolling
interests. Additionally, due to the low commodity price environment, the enhanced oil recovery credit
was available in each of the years ended December 31, 2018 and 2017. During 2017, 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 Act. During 2016, our effective tax rate differed from the U.S. federal
statutory rate primarily due to excluding cancellation of debt income which is described further below.

Given our tax status, any item affecting our effective tax rate described above is offset by an equal

change in the valuation allowance. As of December 31, 2018, 2017 and 2016, we had valuation
allowances of $625 million, $706 million and $780 million, respectively.

In the first quarter of 2016, we reduced our valuation allowance due to our evaluation of our assets

and liabilities at the time of our 2015 debt exchange, which generated $1.4 billion of cancellation of
debt income (CODI) for tax purposes. Our evaluation indicated that our liabilities exceeded the value of
our assets, both calculated in accordance with tax rules, enabling us to move the liability related to
CODI to deferred tax liabilities. The resulting increase of our deferred tax liabilities that could be offset
against deferred tax assets caused an $82 million reduction in the valuation allowance and resulted in
an income tax benefit of $78 million, net of $4 million in state tax. During the rest of 2016, we increased
the valuation allowance by $480 million, which resulted in a net increase of the allowance by
$398 million for the year. The net change in the valuation allowance had the effect of increasing our
provision by $384 million, after $14 million in state taxes, which increased our effective tax rate by
192%. We concluded, on a more-likely-than-not basis, that we could not realize any of the deferred tax
assets generated during 2016.

104

As a result of our 2015 and 2016 debt transactions, we generated CODI of $1.4 billion and
$1.3 billion, respectively ($2.7 billion in the aggregate), for both U.S. federal and California state tax
purposes. These respective amounts were excluded from taxable income because we determined that
our liabilities exceeded the value of our assets for tax purposes immediately prior to each of the
deleveraging transactions. In exchange for this exclusion, tax rules require us to reduce the tax basis
of our assets. Accordingly, we have reduced our net operating losses and the basis of property, plant
and equipment by $1.2 billion for U.S. federal tax purposes and $1.9 billion for California tax purposes.
We were not required to make any further reductions in those assets because, beyond this point, our
liabilities would have exceeded the tax basis of our assets. Accordingly, any tax liability attributable to
the remaining approximately $1.5 billion of U.S. federal and $800 million of California CODI was
relieved without any future tax liability, which reduced our effective rate by 275%.

Deferred Tax Assets and Liabilities

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2018

and 2017 were as follows:

2018

2017

Deferred Tax
Assets

Deferred Tax
Liabilities

Deferred Tax
Assets

Deferred Tax
Liabilities

Debt
Property, plant and equipment differences
Postretirement benefit accruals
Deferred compensation and benefits
Asset retirement obligations
Net operating loss carryforwards and credits
Investment in partnerships
All other

Subtotal

Valuation allowance

Total net deferred taxes

253 $
11
27
56
129
396
93
17

982
(625)

(in millions)
— $

(316)
—
—
—
—
—
(41)

(357)
—

324 $
33
33
53
126
417
—
22

1,008
(706)

357 $

(357)

302 $

—
(261)
—
—
—
—
—
(41)

(302)
—

(302)

Components of accumulated other comprehensive income (loss) (AOCI) are presented net of tax.

We use the “with-and-without” intraperiod allocation approach to allocate taxes and 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

As of December 31, 2018, we had U.S. federal net operating loss carryforwards of $555 million,
generated in 2017, which expire in 2037 and are available to offset up to 100% of taxable income in
the year utilized. As of December 31, 2018, we had a carryforward for disallowed interest expense of
$393 million for U.S. federal purposes, which does not expire.

105

In California, we had $1.6 billion of net operating loss carryforwards which begin to expire in 2026.

As of December 31, 2018, we had U.S. federal tax credit carryforwards of $49 million, which begin

to expire in 2037, and we have $16 million of California tax credit carryforwards which begin to expire
in 2037.

Unrecognized Tax Benefits

Tax benefits are recognized only for tax positions that are more-likely-than-not to be sustained
upon examination by tax authorities. The amount recognized is measured as the largest amount of
benefit that is greater than 50 percent likely to be realized upon settlement. A liability for unrecognized
tax benefits is recorded for any tax benefits claimed in the Company’s tax returns that do not meet
these recognition and measurement standards. As of December 31, 2018 and 2017, we recorded a
$25 million liability for tax positions taken in prior periods that was classified as a deferred tax liability.
This amount of unrecognized tax benefit, if recognized, would affect the effective tax rate positively.
We believe there will not be significant increases or decreases to our unrecognized tax benefits within
the next 12 months.

NOTE 11 STOCK-BASED COMPENSATION

General

In 2016, our stockholders approved the California Resources Corporation Long-Term Incentive
Plan (the Plan), which provides for the issuance of 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 4.7 million shares. As of December 31, 2018, 4.1 million shares were issued or
reserved under the Plan and 0.6 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.

Compensation expense for stock-based awards for the year ended December 31, 2018 was
$45 million, of which $36 million was included in general and administrative expenses and $9 million
was included in production costs in our consolidated statement of operations. Compensation expense
for stock-based awards for the year ended December 31, 2017 was $29 million, of which $23 million
was included in general and administrative expenses and $6 million was included in production costs in
our consolidated statement of operations. Compensation expense for stock-based awards for the year
ended December 31, 2016 was $30 million, of which $23 million was included in general and
administrative expenses and $7 million was included in production costs in our consolidated statement
of operations. For the years ended December 31, 2018, 2017 and 2016, we did not recognize any
income tax benefit related to our stock-based compensation. For the years ended December 31, 2018,
2017 and 2016, we made cash payments of $24 million, $6 million and $5 million for the cash-settled
portion of our awards, respectively. Cash payments on our stock-based compensation were higher in
2018 compared to prior years due to the significant increase in our stock price during the second
quarter of 2018.

106

As of December 31, 2018, the unrecognized compensation expense for all our unvested stock-

based incentive awards was $44 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

Certain executives and non-employee directors 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 vest ratably over three years or at the end of three years for employees and at the end of
one year for non-employee directors. 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, 2018:

Unvested at January 1
Granted(a)
Vested
Forfeited

Unvested at December 31

Stock-Settled

Cash-Settled

Number of Units
(in thousands)

Weighted-
Average Grant-
Date Fair Value

Number of Units
(in thousands)

1,035 $
291 $
(466) $
(41) $

819 $

16.04
20.62
16.57
16.33

17.36

2,066
1,656
(903)
(183)

2,636

(a) During 2018 and 2017, our non-employee directors were granted stock-settled RSUs representing approximately 46,000

and 98,000 shares, respectively.

Performance Stock

Our performance stock units (PSUs) granted prior to 2015 were restricted stock awards with a
performance target based on cumulative earnings before interest, taxes and depreciation. The units
vested at the later of the three years following the grant date or when the performance target is met, if
prior to seven years following the grant date. The performance target was met in 2018. Fair value was
based on Occidental’s stock price on the grant date divided by a conversion factor used at the time of
the Spin-off. The resulting fair value was recognized as compensation expense on a straight-line basis
over the three-year service period, adjusted for actual forfeitures. 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 2015 are RSUs based 50% on achievement of specified Value Creation
Index (VCI) results and 50% on total stockholder return (TSR) relative to a selected peer group of
companies over specified multi-year performance periods, with payouts ranging from 0% to 200% of
the target award. The awards were originally granted as cash-settled awards accounted for as liability
awards until they were modified in May 2016 and became stock-settled awards accounted for as equity
awards from that point forward. Fewer than 50 people were impacted by this modification, which
resulted in no incremental compensation cost.

107

Prior to the modification, the fair value of the VCI-based portions of the PSUs was determined on

the grant date based on an estimated performance achievement at the target level. Additionally, the
fair value of the TSR-based portions of the PSUs was determined on the grant date using a Monte
Carlo simulation model based on applicable assumptions. The volatility was derived from
corresponding peer group companies, which we used in the absence of adequate stock price history
for our common stock at the date of grant. The expected life was based on the vesting period of the
award. The risk-free rate was the implied yield available on zero-coupon U.S. Treasury notes at the
time of grant and subsequent measurement periods with a remaining term equal to the remaining term
of the awards. The dividend yield was the expected annual dividend yield over the term, expressed as
a percentage of the stock price on the valuation date. The fair values were then recognized on a
straight-line basis over the requisite service period, adjusted for actual forfeitures. Compensation
expense was adjusted quarterly, on a cumulative basis, for any changes in the number of share
equivalents expected to be paid based on the relevant performance criteria.

On the modification date, the fair value of the PSUs was redetermined based on target-level VCI

and TSR Monte Carlo results as of that date. The resulting fair value was being recognized as
compensation expense on a straight-line basis over the remaining requisite service period, adjusted for
actual forfeitures. Dividend equivalents, if any, declared during the vesting period were accumulated
and paid upon certification for the number of vested shares.

The modification and grant date assumptions used in the Monte Carlo valuation for the TSR-based

portion of the outstanding PSU awards are as follows:

Risk-free interest rate
Dividend yield
Volatility factor
Expected life (years)
Fair value of underlying common stock

Modification Date

Grant Date

0.77%
—%
69.69%
2.16
18.50

1.06%
0.95%
43.63%
2.9
42.00

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 out 60% in stock and 40% cash up to target. Amounts
over target are paid out 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 following summarizes our PSU activity for the year ended December 31, 2018:

Unvested at January 1
Granted
Vested
Forfeited

Unvested at December 31

Stock-Settled

Cash-Settled

Number of
Awards
(in thousands)

Weighted-
Average Grant-
Date Fair Value

Number of Units
(in thousands)

384
306
(384)
(12)

294

$
$
$
$

39.05
18.34
39.05
18.34

18.34

—
204
—
(8)

196

108

Stock Options

In 2018, 2015 and 2014, we granted 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. 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 issued 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 2018, volatility was based on the average
historical volatility of our stock. For options granted in 2015 and 2014, in the absence of adequate
stock price history of our common stock at the time of grant, volatility was based on the average
volatility of the stocks of a select group of peer companies. 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 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 awards

2018

2015

2014

20.17
4.5
69.85%
2.63%
—%

10.02

42.00
4.5
44.7%
1.56%
0.95%

15.00

81.10
4.5
35.4%
1.40%
0.50%

19.80

The following table summarizes our option activity during the year ended December 31, 2018:

Options
(000’s)

Weighted-
Average
Exercise
Price

Weighted-
Average
Grant-Date
Fair Value

Aggregate
Intrinsic
Value

Beginning balance, January 1
Granted
Exercised
Forfeited
Expired or Canceled

Ending balance, December 31

1,105 $
187 $
— $
— $
(5) $

1,287 $

69.95 $
20.17 $
— $
— $
42.00 $

62.82 $

18.43 $
10.02 $
— $
— $
15.00 $

17.22 $

Exercisable at December 31

1,109 $

69.66 $

18.38 $

—
—
—
—
—

—

109

Employee Stock Purchase Plan

Effective January 1, 2015, we adopted the 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, 2018, 0.8 million shares were
issued under our ESPP and 0.7 million shares were available for future issuance. For the year ended
December 31, 2018, we issued approximately 0.1 million shares of common stock in connection with
our ESPP.

NOTE 12 EQUITY

The following is a summary of common stock issuances:

Balance, December 31, 2016

Issued

Balance, December 31, 2017

Issued
Canceled

Balance, December 31, 2018

Common Stock
(in thousands)

42,543
359

42,902
6,110
(362)

48,650

At December 31, 2018 and 2017, 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 $6 million and $23 million, at December 31, 2018 and 2017, respectively.

110

NOTE 13 EARNINGS PER SHARE

The following table presents the calculation of basic and diluted EPS for the years ended

December 31:

2018
2016
2017
(in millions, except per share amounts)

Basic EPS calculation
Net income (loss)
Less: Net income attributable to noncontrolling interests

Net income (loss) attributable to common stock
Less: Net income allocated to participating securities

Net income (loss) 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 income (loss) attributable to common stock
Less: Net income allocated to participating securities

Net income (loss) available to common stockholders

Weighted-average common shares outstanding
Dilutive effect of potentially dilutive securities

Diluted EPS

429 $
(101)

328
(7)

(262) $
(4)

(266)
—

321 $

(266) $

47.4

42.5

6.77 $

(6.26) $

429 $
(101)

328
(7)

(262) $
(4)

(266)
—

321 $

(266) $

47.4

— $

42.5

— $

6.77 $

(6.26) $

Weighted-average anti-dilutive shares(a)
(a) Anti-dilutive shares represent potential common shares that are excluded from the computation of diluted EPS.

1.6

2.3

279
—

279
(6)

273

40.4

6.76

279
—

279
(6)

273

40.4
—

6.76

1.1

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, 2018 and 2017, we recognized
$36 million and $32 million in other long-term liabilities for these supplemental plans, respectively.

We expensed $35 million in 2018, $33 million in 2017 and $32 million in 2016 under the provisions

of these defined contribution and supplemental plans.

Defined Benefit Plans

Participation in defined benefit pension plans sponsored by us is limited. During 2018,

approximately 70 employees accrued benefits under these plans, all of whom were union

111

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:

Amounts recognized in the balance sheet:

Accrued liabilities
Other long-term liabilities

Amounts recognized in accumulated other
comprehensive (loss) income:

As of December 31,

2018

2017

2018

2017

Pension Benefits

Postretirement Benefits

(in millions)

— $
(19)

(19) $

— $
(14)

(14) $

(2) $

(82)

(84) $

(3)
(90)

(93)

(10) $

(13) $

4 $

(10)

As of December 31,

2018

2017

2018

2017

Pension Benefits

Postretirement Benefits

(in millions)

Changes in the benefit obligation:
Benefit obligation—beginning of year

Service cost—benefits earned during the
period
Interest cost on projected benefit obligation
Actuarial (gain) loss
Benefits paid

Benefit obligation—end of year

Changes in plan assets:
Fair value of plan assets—beginning of year

Actual return on plan assets
Employer contributions
Benefits paid

Fair value of plan assets—end of year

Unfunded status

112

65 $

70 $

93 $

1
2
(2)
(10)

1
2
7
(15)

4
4
(14)
(3)

56 $

65 $

84 $

46 $
(2)
8
(10)

42 $

(14) $

44 $

5
12
(15)

46 $

(19) $

— $
—
3
(3)

— $

(84) $

(93)

3
4
11
(2)

—
—
2
(2)

—

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

2018

2017

(in millions)
56
53
42

$
$
$

65
62
46

$
$
$

None of our defined benefit pension plans had plan assets in excess of accumulated benefit

obligations.

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):

For the years ended December 31,

2018

2017
Pension Benefits

2016

2018

2017
Postretirement Benefits

2016

(in millions)

Net periodic benefit costs:
Service cost—benefits
earned during the period
Interest cost on projected
benefit obligation
Expected return on plan
assets
Amortization of net actuarial
loss
Settlement costs

1 $

4 $

3 $

(3)

2
4

(3)

2
5

(3)

2
8

—

—
—

—

—
—

Net periodic benefit cost

6 $

7 $

11 $

8 $

7 $

For the years ended December 31,

2018

2017
Pension Benefits

2016

2018

2017
Postretirement Benefits

2016

(in millions)

Amounts recognized in other
comprehensive income (loss):
Net actuarial (loss) gain
Settlement costs
Amortization of net actuarial
gain/loss

Total recognized in other
comprehensive income (loss)

(3) $
4

(4) $
5

(9) $
8

14 $
—

(12) $
—

—

3 $

1 $

14 $

(12) $

Settlement costs related to our pension plans were associated with early retirements.

113

—

—
—

—

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,

2018

2017

Pension Benefits

2018
2017
Postretirement Benefits

4.22%
4.00%

3.53%
6.50%
4.00%

3.53%
4.00%

3.88%
6.50%
4.00%

4.57%
—

3.87%
—
—

3.87%
—

4.58%
—
—

For pension plans and postretirement benefit plans that we or our subsidiaries sponsor, we based

the discount rate on the Aon/Hewitt AA Above Median yield curve in both 2018 and 2017. 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 2018, we adopted the Society of Actuaries MP-2018 Mortality Improvement Scale,

which updated the Society of Actuaries Adjusted RP-2014 mortality assumptions that private defined
benefit pension plans in the U.S. use in the actuarial valuations that determine a plan sponsor’s
pension and postretirement obligations. In 2017, we utilized the Society of Actuaries Adjusted RP-2014
Mortality Table reflecting the MP-2017 Mortality Improvement Scale. At December 31, 2018, 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 1.78% and 1.97% as of December 31, 2018 and 2017, 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, 2018, healthcare cost trend rates would decrease 0.25% per year from 7.00% in 2018
until they reach 6.00% in 2022, then decrease 0.50% per year until they reach 4.50% in 2025 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 2018 and 2017, the
target allocation of plan assets was 65% equity securities and 35% debt securities. Investment

114

performance was measured and monitored on an ongoing basis through quarterly investment portfolio
and manager guideline compliance reviews, annual liability measurements and periodic studies.

The fair values of our pension plan assets by asset category are as follows:

Asset Class:
Cash equivalents
Commingled funds:
Fixed income
U.S. equity
International equity

Mutual funds:
Bond funds
Blend funds
Value funds
Growth funds

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

Guaranteed deposit account

Total pension plan assets

Fair Value Measurements at
December 31, 2018

Level 1

Level 2

Level 3

Total

(in millions)

— $

—
—
—

5
2
2
2
—

9
9
5

—
—
—
—
—

—
—
—

—
—
—
—
7

Fair Value Measurements at
December 31, 2017

Level 1

Level 2

Level 3

Total

(in millions)

— $

—
—
—

6
3
3
3
—

7
9
5

—
—
—
—
—

—
—
—

—
—
—
—
7

9
9
5

5
2
2
2
7

7
9
5

6
3
3
3
7

The activity during the years ended December 31, 2018 and 2017, for the assets using Level 3 fair

value measurements was insignificant.

115

Expected Cash Flows

In 2019, we expect to contribute $3 million to our postretirement benefit plans and at least our

minimum funding requirement of $3 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,

2019
2020
2021
2022
2023
2024 - 2028

Pension
Benefits

Postretirement
Benefits

(in millions)
17 $
5 $
4 $
4 $
4 $
14 $

3
4
4
4
4
23

$
$
$
$
$
$

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 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.

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 a power purchase and sales agreement expiring in

116

December 2020, which includes a capacity payment. 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.
Capacity payments are based on a fixed annual amount per kilowatt hour and monthly rates vary
based on seasonality, which is consistent with how we earn the capacity payment. Capacity payments
are settled monthly. We consider our performance obligations to be satisfied as delivery occurs and in
the amount we have a right to invoice 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 marketing,

storing and transporting third-party volumes.

To transport our natural gas as well as third-party volumes, we have entered into firm pipeline

commitments. Depending on market conditions, we may have excess capacity or acquire additional
capacity, in which case we may enter into natural gas purchase and sale agreements with third parties.
We consider our performance obligations to be satisfied upon transfer of control of the commodity. We
have not incurred any significant fees or penalties related to excess capacity on these commitments.

We report our marketing and 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, 2018,

2017 and 2016:

Oil and gas sales:

Oil
NGLs
Natural gas

Other revenue:
Electricity
Marketing, trading and other
Interest income

Net derivative gain from commodity contracts

2018

2017
(in millions)

2016

2,110 $
260
220

1,549 $
210
177

2,590

1,936

111
361
1

473
1

125
35
—

160
(90)

1,325
132
164

1,621

107
25
—

132
(206)

Total revenues and other

3,064 $

2,006 $

1,547

117

The impact of the adoption of ASC 606 on our consolidated statements of operations for the year

ended December 31, 2018 was as follows:

Oil and gas sales
Other revenue
Other expenses, net

As
Reported
ASC 606

$
$
$

2,590
473
399

2018

Previous
GAAP
(in millions)
$
$
$

2,568
392
296

Change

$
$
$

22
81
103

The adoption of ASC 606 did not have an impact on our consolidated balance sheets as of

December 31, 2018 and 2017.

118

Quarterly Financial Data (Unaudited)

Revenues and other(a)

Operating income (loss)(b)

Net (loss) income attributable

to common stock(c)

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

2018
Second Third

First

Fourth

First Second

Third

Fourth

2017

(in millions, except per share amounts)

609 $

549 $ 828 $ 1,078 $ 590

108 $

11 $ 185 $

465 $ 115

516 $

445 $

455

41 $

(45) $

(38)

(2) $

(82) $

66 $

346 $ 53

(48) $

(133) $

(138)

$ (0.05) $ (1.70) $ 1.34 $

7.00 $ 1.23

$ (1.13) $ (3.11) $ (3.23)

Diluted

$ (0.05) $ (1.70) $ 1.32 $

7.00 $ 1.22

$ (1.13) $ (3.11) $ (3.23)

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

(b) For 2017, certain pension benefit costs of 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. See
Item 8 – Financial Statement and Supplementary Data – Note 2 Accounting and Disclosure Changes for more information.

Non-cash derivative loss (gain) from
commodities, excluding noncontrolling interest
Non-cash derivative loss from interest-rate
contracts
Early retirement, severance and other costs
Net gain on early extinguishment of debt
Gain on asset divestitures
Other, net

2018

First

Second

Third

Fourth

First
(in millions)

2017

Second

Third

Fourth

$ 92

$ (28) $ (295) $ (75)

$ (35) $ 72

$ 116

6
— $
3
(31) $ (4)
(1) $ (21)
1
$
1

$ — $ — $ — $ —
$ — $
1
$ — $ — $ —
$ — $ — $ —
7
$

$ —
$
2
$ —
$ —
1
$

1
$
$
2
$ (24) $
(1) $
$
(2) $
$

(1) $
$
$ — $
(2) $
(3) $
9 $

119

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

Balance at December 31, 2015

Revisions of previous estimates(c)
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Balance at December 31, 2016

Revisions of previous estimates(c)
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Balance at December 31, 2017

Revisions of previous estimates(c)
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Balance at December 31, 2018

PROVED DEVELOPED RESERVES

December 31, 2015

December 31, 2016

December 31, 2017

December 31, 2018(d)

PROVED UNDEVELOPED RESERVES

December 31, 2015

December 31, 2016

December 31, 2017

December 31, 2018

Oil
(MMBbl)(a)

NGLs
(MMBbl)

Natural Gas
(Bcf)

466
(40)
3
14
—
(1)
(33)
409
47
—
24
—
(8)
(30)
442
51
4
25
38
—
(30)
530

338

279

304

389

128

130

138

141

59
—
—
2
—
—
(6)
55
7
—
2
—
—
(6)
58
(4)
—
1
11
—
(6)
60

715
(42)
—
25
—
—
(72)
626
104
—
45
—
(3)
(66)
706
(15)
—
27
89
—
(73)
734

575

500

543

565

140

126

163

169

Total
(MMBoe)(b)
644
(47)
3
20
—
(1)
(51)
568
71
—
34
—
(8)
(47)
618
44
4
30
64
—
(48)
712

481

406

440

530

163

162

178

182

(a)

Includes proved reserves related to economic arrangements similar to PSCs of 131 MMBbl, 108 MMBbl, 85 MMBbl and
103 MMBbl at December 31, 2018, 2017, 2016 and 2015, 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.

(d) Approximately 23% of proved developed oil reserves, 9% of proved developed NGLs reserves, 13% of proved developed

natural gas reserves and, overall, 20% 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.

120

2018

In 2018, total net additions to proved reserves from all sources were 142 MMBoe. 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 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. These additions were partially offset by 21
MMBoe of negative revisions due to management’s discretion to downgrade proved undeveloped
reserves (PUDs) that are not anticipated to be developed within their five-year window of initial
booking. Approximately 11 MMBoe of these downgraded PUDs are expiring in 2019 and are not
anticipated to be developed before then at current oil prices. The remaining 10 MMBoe of downgraded
PUDs are projects that are no longer prioritized in our development plan based on current project
economics.

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.

We also added 64 MMBoe in connection with the acquisitions during the year, the majority of

which resulted from the Elk Hills transaction.

Excluding these downgrades of 21 MMBoe that were made at management’s discretion, our
organic reserve replacement ratio would have been 127% from our capital program of $690 million.
Our total net reserves additions from all sources generated an organic reserve replacement ratio of
296%. For further information on our reserve replacement ratio, see Items 1 and 2 – Business and
Properties – Our Operations – Reserves.

2017

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.

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.

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.

121

2016

Total net negative price revisions of 60 MMBoe incorporated the negative effect of lower prices,
partially offset by the positive effect of lower operating costs also caused by the lower commodity price
environment. Our positive performance related revisions of 13 MMBoe resulted primarily from better-
than-expected reservoir performance and comprehensive field development planning. These positive
revisions primarily came from the San Joaquin and Ventura basins.

We added proved reserves of 3 MMBoe from improved recovery through proven IOR and EOR
methods in 2016 which were associated with the continued development of steamflood and waterflood
properties in the San Joaquin basin. We added 20 MMBoe of proved reserves from extensions and
discoveries, which generally resulted from exploration and development programs primarily in the San
Joaquin, Los Angeles and Ventura basins.

CAPITALIZED COSTS

Capitalized costs relating to oil and 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,
2017
2018

(in millions)

20,883
1,103

21,986
(15,839)

19,664
1,111

20,775
(15,391)

6,147

5,384

(a)
(b)

Includes acquisition and development costs.
Includes accumulated valuation allowance for total unproved properties of $819 million at December 31, 2018, 2017 and
2016.

COSTS INCURRED

Costs incurred relating to oil and 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,
2017
(in millions)

2018

2016

Property acquisition costs
Proved properties(a)
Unproved properties

Exploration costs
Development costs(b)

Costs incurred

553
1
38
652

— $
—
25
357

1,244

382

—
—
21
102

123

(a) Acquisition costs capitalized to proved properties include $8 million of liabilities assumed related to ARO in 2018.
(b) Development costs include a $7 million decrease, a $5 million decrease and a $49 million increase in ARO in 2018, 2017

and 2016, respectively.

122

RESULTS OF OPERATIONS

Our oil and gas producing activities, which exclude items such as asset dispositions, corporate

overhead and interest, were as follows:

For the years ended December 31,
2017

2018

2016

Revenues(b)
Production costs(c)
General and administrative

expenses(d)

Adjusted other operating expenses(e)
Depreciation, depletion and

amortization

Taxes other than on income
Exploration expenses

Pretax income
Income tax expense(f)

($/Boe)(a)

($/Boe)(a)
(millions)
$ 2,378 $ 49.23 $ 1,931 $ 41.09 $ 1,700 $ 33.17
15.61

($/Boe)(a)

(millions)

18.88

18.64

800

876

912

49
66

469
117
34

1.01
1.38

9.71
2.42
0.70

33
26

510
110
22

731
(181)

15.13
(3.75)

354
(116)

0.70
0.56

10.85
2.34
0.47

7.53
(2.47)

35
34

527
121
23

160
(65)

0.68
0.67

10.28
2.36
0.45

3.12
(1.27)

Results of operations

550 $ 11.38 $

238 $

5.06 $

95 $

1.85

(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. Revenues also include sales related to processing
third-party gas which are reported in other revenue on the 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 $17.47, $17.48 and $14.69 for 2018, 2017 and 2016, respectively.

(d) For the years ended December 31, 2017 and 2016, certain pension benefit costs of $1 million and $2 million, respectively,
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. See Item 8 – Financial Statement and
Supplementary Data – Note 2 Accounting and Disclosure Changes for more information.

(e) Other operating expenses include accretion expense in 2018, 2017 and 2016. Other operating expenses in 2018 also

include wet gas purchases from third parties, transportation and other expenses due to the adoption of a new accounting
standard related to revenue recognition on January 1, 2018. Adjusted other operating expenses for 2018 exclude net
unusual and infrequent gains of $10 million ($0.21 per Boe) that include receivables and refunds partially offset by rig
termination expenses. For 2017, the amounts exclude net unusual and infrequent charges of $5 million ($0.10 per Boe)
primarily related to rig termination expenses partially offset by property tax refunds, recovery of amounts due from joint
interest partners and other items. For 2016, the amounts exclude net unusual and infrequent gains of $18 million ($0.35
per Boe) that include refunds partially offset by plant turnaround charges and other items.
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 2018 was 28% as compared to 41% in both 2017 and 2016. 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.

(f)

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 gas reserves the unweighted arithmetic average of the
first-day-of-the-month price for each month within the years ended December 31, 2018, 2017 and
2016, 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

123

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, 2018, 2017 and 2016. Such assumptions, which are prescribed
by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to
substantially different results.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows
Future costs

Production costs(a)
Development costs(b)
Future income tax expense

Future net cash flows
Ten percent discount factor

2018

At December 31,
2017
(in millions)

2016

42,325 $ 26,685 $ 18,831

(19,452)
(4,432)
(4,231)

14,210
(6,935)

(13,988)
(3,848)
(1,585)

7,264
(3,499)

(10,092)
(3,376)
(340)

5,023
(2,356)

Standardized measure of discounted future net cash flows

7,275 $

3,765 $

2,667

(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,
2017
(in millions)

2018

2016

Beginning of year

3,765 $

2,667 $

4,024

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.

(1,511)
3,648
351
(38)
443
738
427
(1,356)
766
42

3,510

(918)
1,405
159
(98)
177
737
260
(599)
(43)
18

(742)
(2,297)
62
89
117
(247)
458
854
(4)
353

1,098

(1,357)

7,275 $

3,765 $

2,667

124

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

(in millions)

2018

Balance at
Beginning of
Period

Charged
(Credited) to
Costs and
Expenses

Charged
to Other
Accounts Deductions

Balance at End
of Period

Deferred tax valuation allowance

Other asset valuation allowance

2017

Deferred tax valuation allowance

Other asset valuation allowance

2016

Deferred tax valuation allowance

Other asset valuation allowance

706

780

382

(76) $

(13) $

(78) $

(12) $

398 $

(12) $

(5) $

— $

625

706

780

125

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.

We have assessed the effectiveness of our internal control system as of December 31, 2018
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, we believe that, as of December 31, 2018, 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, 2018, 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.

126

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.

127

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 2019 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, 2018 (2019 Proxy
Statement). See Part I – Executive Officers of this report for the list of our executive officers and
related information.

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.

ITEM 11

EXECUTIVE COMPENSATION

The information required by this item is incorporated by reference from our 2019 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 2019 Proxy Statement.

See also 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 2019 Proxy Statement.

ITEM 14

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated by reference from our 2019 Proxy Statement.

128

PART IV

ITEM 15

EXHIBITS

The agreements included as exhibits to this report are included to provide information about their
terms and not to provide any other factual or disclosure information about us or the other parties to the
agreements. The agreements contain representations and warranties by each of the parties to the
applicable agreement that were made solely for the benefit of the other agreement parties and:

•

should not be treated as categorical statements of fact, but rather as a way of allocating the
risk among the parties if those statements prove to be inaccurate;

have been qualified by disclosures that were made to the other party in connection with the
negotiation of the applicable agreement, which disclosures are not necessarily reflected in the
agreement;

• may apply standards of materiality in a way that is different from the way the Company and

investors may view materiality; and

•

were made only as of the date of the applicable agreement or such other date or dates as
may be specified in the agreement and are subject to more recent developments.

(a) (1) and (2). Financial Statements

Reference is made to Item 8 of the Table of Contents of this report where these documents are

listed.

(a) (3). Exhibits

Exhibit
Number

2.1

3.1

3.2

4.1

4.2

4.3

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).

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).

129

Exhibit
Number

4.4

4.5

4.6

4.7

4.8

4.9

4.10

4.11

4.12

4.13

4.14

4.15

Exhibit Description

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).

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).

130

Exhibit
Number

10.1

10.2

10.3

10.4

10.5

10.6

10.7

10.8

Exhibit Description

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).

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).

131

Exhibit
Number

10.9

10.10

10.11

10.12

10.13

10.14

10.15

10.16

10.17

10.18

10.19

Exhibit Description

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).

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).

132

Exhibit
Number

10.20

10.21

10.22

10.23

10.24

10.25

10.26

10.27

10.28

10.29

Exhibit Description

Amendment to the Agreement for Implementation of an Optimized Waterflood Program
for the Long Beach Unit, dated January 16, 2009, by and among the State of California,
by and through the State Lands Commission, the City of Long Beach, and Oxy Long
Beach, Inc. (filed as Exhibit 10.11 to Amendment No. 2 to the 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).

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 Restricted Stock Unit
Award Terms and Conditions (filed as Exhibit 10.3 to the Registrant’s Quarterly Report
Form 10-Q filed November 6, 2015, and incorporated herein by reference).

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).

133

Exhibit
Number

10.30

10.31

10.32

10.33

10.34

10.35

10.36

10.37*

10.38

10.39

10.40

10.41

10.42

10.43

10.44

Exhibit Description

California Resources Corporation Long-Term Incentive Plan Performance Stock Unit
Award Terms and Conditions (filed as Exhibit 10.2 to the Registrant’s Quarterly Report
on Form 10-Q filed November 6, 2015, 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).

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 Incentive Award Terms and Conditions (Not Performance-
Based) (filed as Exhibit 10.8 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 Incentive Award Terms and Conditions (Performance-Based)
(filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed February 10,
2015, and incorporated herein by reference).

134

Exhibit
Number

10.45

10.46

10.47

10.48

10.49

10.50

10.51

10.52

10.53

10.54

10.55

21*

23.1*

23.2*

31.1*

Exhibit Description

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 Long-Term Incentive Award Terms and Conditions (Cash-based, Equity, and
Cash-settled Award) (filed as Exhibit 10.10 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 Incentive Award Terms and Conditions (Replacement Award-
Performance-Based) (filed as Exhibit 10.11 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 Incentive Award Terms and Conditions (Replacement
Award-Not Performance-Based) (filed as Exhibit 10.12 to Amendment No. 3 to the
Registrant’s Information Statement on Form 10 filed September 22, 2014 and
incorporated herein by reference).

Form of Phantom Share Unit Award Terms and Conditions (Replacement Award) (filed
as Exhibit 10.13 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).

List of Subsidiaries of California Resources Corporation.

Consent of Independent Registered Public Accounting Firm.

Consent of Independent Petroleum Engineers.

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.

135

Exhibit
Number

31.2*

32.1*

99.1*

Exhibit Description

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, 2018.

101.INS*

XBRL Instance Document.

101.SCH*

XBRL Taxonomy Extension Schema Document.

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document.

* - Filed herewith.

136

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.

February 27, 2019

By:

/s/ Todd A. Stevens

CALIFORNIA RESOURCES CORPORATION

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/ Harold M. Korell

Harold M. Korell

/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 27, 2019

Senior Executive Vice President and
Chief Financial Officer

February 27, 2019

Executive Vice President - Finance and
Principal Accounting Officer

February 27, 2019

Chairman of the Board

February 27, 2019

Director

137

February 27, 2019

EXHIBIT INDEX

EXHIBITS

23.1

23.2

31.1

31.2

32.1

99.1

List of Subsidiaries of California Resources Corporation.

Consent of Independent Registered Public Accounting Firm.

Consent of Independent Petroleum Engineers.

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, 2018.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

138

Annual Meeting

California Resources Corporation’s annual meeting of

stockholders will be held at 11:00 a.m. on May 8, 2019 at

the Bakersﬁeld Marriott at the Convention Center located

at 801 Truxtun Avenue, Bakersﬁeld, California 93301.

Investor Relations

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 ir@crc.com.

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

Stock Exchange Listing

California Resources Corporation’s common stock

is listed on the New York Stock Exchange (NYSE).

The symbol is CRC.

Marshall D. Smith
Senior Executive Vice President
and Chief Financial Ofﬁcer

Ofﬁcers

Todd A. Stevens
President,
Chief Executive Ofﬁcer

and Director

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

Michael L. Preston
Executive Vice President,

General Counsel and

Corporate Secretary

Charles F. Weiss
Executive Vice President,

Public Affairs

Darren Williams
Executive Vice President,

Operations and Geoscience

Merrill Lynch

Petroleum Corporation

Chief Executive Ofﬁcer,

Moncrief Oil International

Chairman, Bank of America

Southwestern Energy Company

Board Of Directors

Harry T. McMahon
Former Executive Vice

Richard W. Moncrief
Chairman of the Board and

Harold M. Korell
Lead Independent Director,

Former Chairman of the Board
and Chief Executive Ofﬁcer,

Justin A. Gannon
Former Regional Managing
Partner, Grant Thornton LLP

William E. Albrecht
Chairman of the Board, Former
Vice President, Occidental

2
0
1
8This Annual Report is printed on Forest Stewardship Council®-

certiﬁed paper that contains wood and/or wood ﬁber from
well-managed forests and other responsible sources.

Todd A. Stevens
President, Chief Executive

Anita M. Powers
Former Executive Vice

Avedick B. Poladian
Former Executive Vice

Robert V. Sinnott
Co-Chairman,

Laurie A. Siegel
President,

Ofﬁcer and Director, California

President and Chief Operating

Exploration, Occidental Oil

Vice President, Occidental

and Gas Corporation and

Ofﬁcer, Lowe Enterprises

Kayne Anderson Capital

President of Worldwide

Petroleum Corporation

Resources Corporation

LAS Advisory Services

888

UFCW®

crc.com