California Resources Annual Report 2017

FY2017 Annual Report · California Resources

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CALIFORNIA
RESOURCES
CORPORATION
2017 ANNUAL REPORT

FINANCIAL AND OPERATIONAL
HIGHLIGHTS

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

Financial Highlights

Revenues
(Loss) Income Before Income Taxes
Net Income Attributable to Noncontrolling Interest
Net (Loss) Income Attributable to Common Stock
Adjusted Net Loss(a)

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

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

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

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

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

2015

$ 2,403
$ (5,476)
$
-
$ (3,554)
(311)
$

$ (92.79)
(8.12)
$

$
$
$
$

403
401
356
352

$ 7,053
$ 6,043
491
$
(916)
$

38.3
38.8

2017

2016

2015

Operational Highlights

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

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

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

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

104
18
229
160

$ 49.19
$ 47.15
$ 19.62
2.66
$

466
59
715
644

140%
5.1

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

119%
4.5

71%
2.8

Mineral Acreage (in thousands):
Net Developed
Net Undeveloped
Total

Closing Share Price

703
1,550
2,253

717
1,614
2,331

736
1,653
2,389

$ 19.44

$ 21.29

$ 23.30

(a) See www.crc.com, Investor Relations for a discussion of these non-GAAP measures, including a reconcililation 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. (d) For 2015, the average price realization of natural gas as a percentage of NYMEX includes the effect of hedges.
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.

2017

A MESSAGE TO OUR SHAREHOLDERS

Dear Shareholder,

In 2017, California Resources Corporation continued its role as the Golden State’s largest

producer of oil and natural gas on a gross-operated basis, with operating control over nearly half the oil
and gas fields in California. Our workforce is proud to share California’s values and to operate under
the world’s leading safety, labor, human rights and environmental standards. Throughout the year, our
value-driven approach to developing our world-class assets allowed us to grow our reserves and
improve our financial position.

We exited 2017 with proved reserves of 618 million barrels of oil equivalent (MMBOE), organically

replacing 119% of our production despite a limited capital program. In addition, our probable and
possible reserves1 grew by 303 million barrels, a 37% increase from the prior year. We drilled 110
gross wells with internally funded capital and 119 gross wells from joint venture (JV) capital.

Financial discipline continued to be a focus and we lived within our cash flow in 2017 just as we

have done every year since our inception — a rarity in the E&P sector. We generated a net loss of
$266 million, adjusted EBITDAX1 of $761 million and delivered a cash margin of 36%. Including $96
million of JV funded capital, our capital investments amounted to $371 million. Our internally funded
development program of approximately $240 million is expected to deliver returns of 30%, on a fully
burdened basis, over the life of the investment and an expected value creation index1 (“VCI”) of 1.7 at
a flat $55 Brent price. At the same time, we delivered organic finding & development costs of $6.82 per
barrel of oil equivalent, marking the third year in a row that these costs have been in the single digits
with recycle ratios in excess of 2.0x. We also used our hedging program to protect our cash flow and
underpin our capital investment.

Our financial position meaningfully strengthened in 2017 through a successful credit amendment

and refinancing that provides us with significant liquidity and a clear runway to deliver value through
2021. Since our spin through February 2018, we have eliminated approximately $2.3 billion of net debt
on a pro forma basis during one of the most challenging times in our industry’s history.

CRC possesses a deep inventory of actionable projects at $65 Brent pricing that we expect will
create real value for our shareholders in the years to come. To ensure we capture that potential value,
we develop our capital plan by ranking all of our projects by drive mechanism on a fully burdened, full
cycle cost basis. The result is nearly 750 MMBOE of net resources1 with full cycle costs of $35 per
BOE or less.

With a total capital commitment of up to $550 million, the JVs we entered into during 2017 with
Benefit Street and Macquarie go a long way to accelerate the value of and de-risk our inventory of
actionable projects. These JVs provide for development funding by our partners in specific areas and
allow us to participate in all stages of production growth, including a meaningful portion of the initial
growth wedge and a substantial increase in our participation once the JV partners achieve their
targeted rates of return.

More recently, we monetized power and gas processing assets through a midstream JV with a
portfolio company of Ares Management, L.P. The Ares portfolio company invested $750 million for
certain common and preferred equity interests in the venture, and an Ares-led investor group
purchased approximately 2.34 million shares of CRC’s common stock in a private placement for an
aggregate purchase price of $50 million in cash, or $21.33 per share. Approximately $297 million of
proceeds were used to repay the Company’s outstanding bank revolver balance. With our ongoing
focus on value creation, we intend to deploy remaining proceeds to the best value alternative —
whether that is reinvestment, acquisitions or additional debt reduction — to drive long-term shareholder
returns.

Our focus for 2018 can be summed up in one word: EXECUTION. It will be a year dedicated to

extending our track record of operational and financial discipline into a mid-cycle commodity
environment ripe with upside. With our VCI investment criteria as a guiding principle, we will
strategically invest to drive cash flow and margin growth. Including funds provided by our JV partners,
we will begin with a $425 to $450 million program, which could potentially ramp through the year as
confidence in the current commodity price environment grows.

Our 2018 capital plan will be deployed primarily on low decline crude oil development and

delineation projects in our Buena Vista and Kettleman North Dome fields. Some of our largest assets,
including the greater Elk Hills area, Wilmington, Huntington Beach and Kern Front, will also see
investments focused on new conventional opportunities, as well as expanding waterflood and
steamflood projects. Additionally, we intend to fund continued investment in our capital workovers,
which have proven to be highly valuable.

At CRC, we are constantly focused on adapting our business model to best generate shareholder

value given market dynamics. Our business opportunities dictate our structure, not the other way
around. To that end, as we entered 2018, we redeployed our human capital in a new, flatter
organizational structure to enable quicker decision-making and improved accountability. This
organizational shift is designed to maximize the value of our assets from a cash margin and VCI
perspective, while ensuring that teams are working collaboratively and creatively to achieve operational
goals and sustain our exacting standards for health, safety and environmental protection.

In 2018, we expect to build upon our disciplined execution in a mid-cycle commodity environment

to capture the upside that is imbedded in our business and deliver value to our shareholders. We
intend to play to the strength of our low-capital intensity, low-decline rate resources, prudently
allocating capital investments to the best value alternative as we deliver much-needed energy for
California by Californians.

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, finding and development costs, recycle ratio calculations
and drilling locations. 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.
Facility costs and other non-return capital are apportioned to producing wells in the year they are drilled.

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, 2017

‘ 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)

9200 Oakdale Ave. Los Angeles, California
(Address of principal executive offices)

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

91311
(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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Yes Í No ‘

Act.

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 file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes Í No ‘

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if

any, every Interactive Date File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during
the preceding 12 months (or such shorter period as the registrant was required to submit and post files). Yes Í No ‘

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. ‘

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 ‘

‘ Accelerated Filer

Í 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 $363 million, computed by reference to the closing price on the New York Stock Exchange composite
tape of $8.55 per share of Common Stock on June 30, 2017. 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, 2018, there were 42,901,946 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

connection with the registrant’s 2018 Annual Meeting of Stockholders, are incorporated by reference into Part III of
this Form 10-K.

Part I

Item 1

Item 1A
Item 1B
Item 2

Item 3
Item 4

Part II

Item 5

Item 6
Item 7

TABLE OF CONTENTS

BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Operations and Environment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Business Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Key Characteristics of our Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Portfolio Management and Capital Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reserves and Production Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marketing Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulation of the Oil and Natural Gas Industry . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Spin-Off and Reverse Stock Split . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exploration Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production, Price and Cost History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Productive Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Drilling Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Delivery Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MINE SAFETY DISCLOSURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXECUTIVE OFFICERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Private Placement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production and Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Operations Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash Flow Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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2017 and 2018 Capital Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
74
Off-Balance-Sheet Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
76
Lawsuits, Claims, Commitments and Contingencies . . . . . . . . . . . . . . . . . . . . . . .
77
Critical Accounting Policies and Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
77
Significant Accounting and Disclosure Changes . . . . . . . . . . . . . . . . . . . . . . . . . .
77
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . .
78
FORWARD-LOOKING STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
80
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . .
81
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . .
81
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
83
Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
84
Consolidated Statements of Comprehensive Income . . . . . . . . . . . . . . . . . . . . . .
85
Consolidated Statements of Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
87
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
88
Quarterly Financial Data (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125
. . . . . . . . . . . . . . . . . . . . . . . 126
Supplemental Oil and Gas Information (Unaudited)
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS . . . . . . . . . . . . . . . . 131
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132
OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE . . . . 133
EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . 133
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134
PRINCIPAL ACCOUNTANT FEES AND SERVICES . . . . . . . . . . . . . . . . . . . . . . . . 134

Item 7A

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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

PART I

Item 1

BUSINESS

General

We are an independent oil and natural gas exploration and production company operating
properties within California. We are the largest oil and gas producer in California on a gross operated
basis and we believe we have the largest privately held mineral acreage position in the state,
consisting of approximately 2.3 million net mineral acres spanning the state’s four major oil and gas
basins. We produced approximately 129 thousand barrels of oil equivalent per day (MBoe/d) for the
year ended December 31, 2017. As of December 31, 2017, we had net proved reserves of 618 million
barrels of oil equivalent (MMBoe), of which approximately 71% was categorized as proved developed
reserves. Oil represented 72% of our proved reserves. We were formed in April 2014 and listed on the
New York Stock Exchange on December 1, 2014. All references to ‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’
and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

Business Operations and Environment

Our business is focused on the production, development and exploration of conventional and

unconventional oil and gas assets in California.

Our large acreage position and extensive drilling inventory provide us a diversified portfolio of oil

and natural gas locations that are economically viable in a variety of operating and commodity price
conditions, including many that are high-value projects throughout the price cycle. Our large fee
mineral acreage position also enhances our returns because we do not make royalty and other lease
payments related to these assets. Our acreage position contains numerous development and growth
opportunities due to its varied geologic characteristics and multiple stacked pay reservoirs which are in
many cases thousands of feet thick. We have a large portfolio of low-risk and low-decline conventional
opportunities in each of our major oil and gas basins comprising approximately 71% of our proved
reserves. Conventional reservoirs are capable of natural flow during primary recovery phase, often
followed by waterflood and steamflood recovery methods to enhance ultimate recovery. We also have
a significant portfolio of lower permeability unconventional reservoirs that typically utilize established
well stimulation techniques. Our conventional and unconventional reservoirs currently include
approximately 20,550 and 4,530 net identified drilling locations, respectively, primarily in the San
Joaquin basin.

We are in various phases of developing many of our conventional assets and will continue to
develop them using internally generated cash flow and, when appropriate, capital raised through joint
ventures. Prior to the severe price declines that began in late 2014, we were focused on higher-value
unconventional production from seven discrete stacked pay horizons within the Monterey formation,
primarily within the upper Monterey. As commodity prices and project economics improved in 2017, we
renewed our development activities in the upper Monterey and started to appraise and delineate the
Kreyenhagen formation within our Kettleman North Dome field. We expect to continue pursuing
unconventional opportunities in 2018 and beyond if prices remain at current levels. Over the longer
term, we believe our project economics will improve, which should allow us to duplicate our successful
upper Monterey results to develop opportunities in the unconventional reservoirs of the lower
Monterey, Kreyenhagen and Moreno formations, which have similar geological attributes.

We have also built a 3D seismic library that covers approximately 4,820 square miles,

representing over 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. In recent years we have tested and successfully
implemented various exploration, drilling, completion and enhanced recovery technologies to increase
recoveries, growth and value from our portfolio. We continue working to build depth in our exploration
inventory and identify new prospects based on the competitive advantage provided by this proprietary
data set and our experience.

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 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.

With significant operating control of our properties, we have the ability to adjust our drilling and
workover rig count based on commodity prices and to increase or decrease our program according to
changing market conditions. We began 2017 with two drilling rigs and ended the year with nine; seven
in the San Joaquin basin and one each in the Los Angeles and Ventura basins. We drilled and
completed 109 net development wells with 92 wells in the San Joaquin basin, 15 in the Los Angeles
basin and two in the Ventura basin. These included six primary wells, 52 steamflood wells,
31 waterflood wells, and 20 unconventional wells. We also drilled and completed five net exploration
wells in the San Joaquin basin. In 2017, we increased our workover rig count from 43 at the beginning
of 2017 to 59 at the end of the year to focus on projects that meet our investment criteria. In total, we
performed approximately 460 capital workover projects during 2017.

The following table summarizes certain information concerning our acreage, wells and drilling

locations as of December 31, 2017:

Mineral
Acreage(a)
(in millions)

Gross

Net

Average
Net Mineral
Acreage
Held in Fee
(%)

Producing
Wells,
gross

Average
Net
Revenue
Interest
(%)

San Joaquin Basin
Los Angeles Basin
Ventura Basin
Sacramento Basin

Total

1.7
<0.1
0.3
0.6

2.7

1.5
<0.1
0.2
0.5

2.3

66%
46%
73%
38%

60%

6,192
1,300
467
677

8,636

79%
76%
82%
75%

78%

Identified Drilling
Locations(b)

Gross

Net

25,190
1,950
4,310
2,420

17,530
1,930
3,900
1,720

33,870

25,080

(a) We currently hold approximately 38,500 gross (30,300 net) acres in the Los Angeles basin. Our Los Angeles basin

operations primarily rely on dense multi-well pad drilling.

(b) Our total identified drilling locations exclude approximately 6,400 gross (5,300 net) exploration drilling locations related
to unconventional reservoirs. They include approximately 2,090 gross (1,870 net) locations associated with proved
undeveloped reserves and approximately 2,520 gross (2,350 net) injection well locations. Please see Item 2—
Properties—Drilling Locations for more information regarding the processes and criteria through which we identified our
drilling locations.

Compared to 2016, our 2017 production declined 8%, with only $266 million of drilling and
workover capital invested for the year. This performance reflects the resilience of our asset base and

the further flattening of our base production decline. In 2017, our production profile comprised roughly
64% oil, 24% natural gas and 12% natural gas liquids. Recognizing the relative value of crude oil, we
are devoting the majority of our 2018 capital program to grow our oil production.

We have created a dynamic capital program for 2018 that can be adjusted to align investments

with projected cash flows and joint venture (JV) funding. We believe our expanded 2018 capital
program focusing primarily on low-decline crude oil assets will provide meaningful deleveraging over
time while we continue to pursue additional opportunities to strengthen our balance sheet. Our capital
program will also allow us to continue to delineate our high-potential conventional and unconventional
areas like Buena Vista Nose and Kettleman, respectively.

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,
demand for oil and natural gas in California remains strong. California is heavily reliant on imported
sources of energy, with approximately 72% of oil and 90% of natural gas consumed in 2017 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 Brent prices. We believe that the limited crude transportation infrastructure from other parts of
the U.S. and California refiners’ preference to run on heavy grades of oil found in California will
continue contributing to favorable prices and realizations compared to other U.S. markets. During the
second half of 2017, Brent crude prices began to recover, rising above $65 per barrel and reaching the
highest level since 2015 as the premium of Brent over West Texas Intermediate (WTI) widened with
the Organization of the Petroleum Exporting Countries (OPEC) production cuts. Additionally, our
differentials improved against Brent during 2017 as a result of an increase in the official selling price to
North America from the Middle East and higher-than-expected demand in Asia.

During 2017, as oil prices and activity increased, 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 due to excess capacity in the service and supply sector. At current commodity
price levels, we expect this trend to continue in 2018.

Recent Developments

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 MW natural gas fired power plant, and a 200 million cubic foot per day cryogenic gas processing
plant. For more on the Ares JV, see Item 7—Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Joint Ventures.

Our Business Strategy

We plan to drive long-term stockholder value by applying modern technologies to develop our
resource base and increase production. We have significant conventional opportunities to pursue,
which we develop through their life cycles to increase recovery factors by transitioning them from
primary production to waterfloods, steamfloods and other enhanced recovery mechanisms.

In a sustained higher price environment, we intend to direct additional available capital to projects
that provide high-value returns. A higher sustained price environment also gives us the opportunity to
acquire assets that would be complementary to our existing operations. The principal elements of our
business strategy include the following:

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Focus on high-value projects. In the near term, we anticipate directing the majority of our
capital investments toward oil-weighted opportunities to the extent the oil-to-gas price

relationship remains favorable. As a result, we expect the percentage of our oil production to
continue to increase over time and favorably impact our overall margins. In 2018,
approximately 95% of our identified drilling inventory is associated with oil projects. Currently,
64% of our production is oil compared to 72% of our proved reserves. Over time, we expect
our share of oil production to approach the share of oil reserves.

Over the longer term, we believe we can generate significant production growth from
unconventional reservoirs such as tight sandstones and shales. We hold mineral interests in
approximately 1.3 million net mineral acres with unconventional potential and have identified
approximately 4,930 gross (4,530 net) drilling locations on this acreage. A meaningful portion
of our production already comes from unconventional assets. While we have not yet
developed sufficient information to reliably predict success rates across our entire portfolio,
our continued technical reviews of these projects are allowing us to better understand
performance of these reservoirs in addition to improving our overall cycle time from project
identification to development. As a result, we believe we will be able to direct future available
capital more precisely to higher value projects, allowing us to strategically increase our
investment levels in unconventional drilling over time.

(cid:129) Maintain an appropriate share of conventional projects in our production mix to

manage production declines and base maintenance capital requirements. Our portfolio
of assets includes a large number of steamflood and waterflood projects that have much
lower decline rates than many unconventional projects. We intend to focus a significant
portion of our capital investments on such projects, which we expect will maintain our low
production decline rates. We have approximately 28,940 gross (20,550 net) identified drilling
locations associated with lower-risk conventional opportunities, 56% of which are Improved
Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) projects. The remaining 44% are
associated with primary recovery methods, many of which we expect will develop into IOR
and EOR projects in the future.

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Enhance stockholder value by pursuing upstream and midstream joint venture
opportunities including exploration ventures. We believe both upstream and midstream
joint ventures will enhance value by giving us the ability to significantly accelerate the
development of our high-value portfolio of assets. We have already announced a number of
joint ventures that have given us substantial development resources and will continue to
evaluate similar opportunities in the future. We have entered into a number of exploration joint
ventures, which, if successful, could result in significant long-term production growth.

Increase natural gas production over time to provide clean energy to California. We are
the largest producer of natural gas in California through our operations in the Sacramento
basin. Our portfolio has a large number of mature gas fields that can be targeted for further
development, with growth opportunities in under-developed areas of our asset base, including
significant growth potential in the Sacramento basin. We are focused on developing
technologies and execution approaches that will generate commercial projects at current price
levels while maintaining a targeted exploration program for new resources. In addition, we
expect to pursue strategic joint ventures to unlock the value of our asset portfolio.

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

and community outreach, while helping the state address its energy and water needs.
We are committed to managing our assets in a manner that safeguards people and protects
the environment, and to reducing California’s dependence on imported energy. We
proactively engage with regulatory agencies, communities, organized labor and other
stakeholders to pursue mutually beneficial outcomes that supply affordable and reliable

energy from local sources and that expand opportunities for the communities in which we live
and work. As a California company, helping our state meet its water needs is a key priority.
We are a net water supplier to agriculture due to our dedicated team and investments in water
conservation and the recycling of produced water from oil and gas reservoirs. In 2017, our
operations supplied 4.9 billion gallons of reclaimed water for agricultural use, a new company
record that far exceeds the volume of fresh water we purchased for our operations statewide.

Apply proven modern development and production methods to enhance production
growth and cost efficiency. Over the last several decades, the oil and gas industry has
focused significantly less effort on utilizing modern development and exploration processes
and technologies in California relative to other prolific U.S. basins. We believe this is largely
due to other oil companies’ limited capital investments in California, concentration on shallow-
zone thermal projects and investments in other assets within their global portfolios. As an
independent company focused on California, we use proven modern technologies in drilling
and completing wells, as well as production methods that we expect will substantially increase
both our production and cost efficiency over time. We have developed an extensive 3D
seismic library covering almost 4,820 square miles in all four of our basins, representing over
90% of the 3D seismic data available for California, and have tested and successfully
implemented various exploration, drilling, completion, IOR and EOR technologies in the state.

Utilize advanced technologies to improve our operations. We have a dedicated Big Data
Analytics team focused on analyzing data to help us make better operating and development
decisions that enhance the value of our assets. We are evaluating advanced technologies
such as artificial intelligence, machine learning, algorithms, complex math analysis and other
digital solutions to predictively optimize our business processes, development criteria and our
drilling and production techniques.

(cid:129)

Key Characteristics of our Operations

The following are among the key characteristics of our operations:

(cid:129)

Operational control of our diverse asset base provides flexibility during commodity
price cycles and preserves future value and growth potential. Our near 100% operational
control of 135 fields in California provides us flexibility to adapt our investments to various
market environments through our ability to select drilling locations, the timing of our
development and the drilling and completion techniques we use. Our large and diverse
mineral acreage position allows us to choose to develop conventional or unconventional
reservoirs of either oil or natural gas using multiple recovery mechanisms, such as primary,
steamflood and waterflood. In addition, approximately 60% of our acreage position is held in
fee and 15% is held by production, which gives us flexibility to choose the timing of our
development projects. A majority of our interests are in producing properties located in
reservoirs characterized by what we believe have long-lived production profiles with
repeatable development opportunities. Approximately 95% of our identified drilling inventory is
associated with oil-rich projects, primarily located in the San Joaquin, Los Angeles and
Ventura basins, and the remaining inventory is associated with natural gas properties in the
Sacramento, San Joaquin and Ventura basins. The variety of recovery mechanisms and
product types available to us, together with our operating control, allows us to allocate capital
in a manner designed to optimize cash flow over a wide range of commodity prices. The low
base decline of our conventional assets allows us to limit production declines with minimal
investment, positioning us to achieve oil-production growth in the current price environment
while living within our means.

(cid:129)

Largest acreage position in a world-class oil and natural gas province. We believe we
are the largest private oil and natural gas mineral acreage holder in California, with interests
in approximately 2.3 million net mineral acres. California is one of the most prolific oil and
natural gas producing regions in the world. California is also the nation’s largest state
economy, and the world’s sixth largest, with significant energy demands that exceed local
supply. Our large acreage position with a diverse development portfolio enables us to pursue
the appropriate production strategy for the relevant commodity price environment without the
need to acquire new acreage. For example, in a high natural gas price environment we can
rapidly increase our investments in the Sacramento basin to generate significant production
growth. Our large acreage position also allows us to quickly deploy the knowledge we gain in
our existing operations, together with our seismic data, in other areas within our portfolio.

Opportunity rich drilling and workover portfolio. Our drilling inventory at December 31,
2017 consisted of approximately 33,870 gross (25,080 net) identified well locations, including
approximately 28,940 gross (20,550 net) conventional drilling locations and approximately
4,930 gross (4,530 net) unconventional drilling locations. Our drilling inventory count
increased by about 10% from the prior year as a result of our technical teams’ continued
efforts. We also have approximately 1,200 workover projects that can deliver high returns. At
about $65 Brent, we estimate we have increased the investment opportunities for drilling and
workover capital that meet our 1.3 VCI threshold by 20%. In the process, our inventory of
lower-risk conventional development opportunities with attractive returns has increased even
more than our unconventional opportunities. In a sustained favorable oil and gas price
environment, we believe we can also achieve further long-term production growth through the
development of unconventional reservoirs. In addition, our rich 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. For
example, we have successfully reduced field operating costs by approximately 27% since
2014.

Portfolio Management and Capital Program

We develop our capital program by prioritizing projects that have returns that will 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 the VCI metric for project selection and capital allocation across our asset portfolio.
Typically, we create the highest value by reinvesting our cash flow back into our business, including
attractive acquisitions. 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 such capital investments as
circumstances warrant.

2017 Capital Program

Our 2017 capital program predominantly targeted projects in the San Joaquin and Los Angeles

basins, and virtually all of our capital was directed towards oil-weighted production, consistent with
2016 and 2015. The program was initially set at approximately $300 million but increased to
$371 million when we entered into JVs with Benefit Street Partners (BSP) and Macquarie Infrastructure
and Real Assets Inc. (MIRA). Our $371 million capital program included $96 million of funding from

BSP and excluded $58 million of funding from MIRA, which is not reported in our consolidated results.
Excluding MIRA capital, we invested approximately $177 million for drilling wells, $89 million for capital
workovers, $71 million for facilities and compression expansion, $25 million for maintenance and
occupational health, safety and environmental projects and $9 million for exploration and other items.
We ended 2017 with nine rigs running and anticipate our activity levels to remain at an average
nine-rig pace for the first quarter of 2018.

2018 Capital Program

We are focusing our 2018 capital on oil projects, which provide higher margins and low decline

rates that we believe will generate cash flow to fund increasing capital budgets that will grow
production. Our approach to our 2018 drilling program is consistent with our stated strategy to remain
financially disciplined and fund projects through either internally generated cash flow or JV capital to
maintain our liquidity and further strengthen our balance sheet. We 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. We will continue to focus on our
core fields: Elk Hills, Wilmington, Kern Front and the delineation and appraisal of Kettleman North
Dome and Buena Vista. We will also restart our development activities in the Huntington Beach field.

With stronger expected cash flow, we estimate our 2018 capital program will range from

$425 million to $450 million, which includes approximately $100 to $150 million in JV capital. Our 2018
capital program may grow further through additional tranches from existing JVs as well as potential
new JVs.

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. Our 2018 drilling
program includes development of conventional and unconventional resources. The depth of our
primary conventional wells is expected to range from 2,000 to 15,000 feet. With a significant reduction
in our drilling costs since 2014, many of our deep conventional and unconventional wells have become
more competitive, and we expect to use approximately 60% of our capital on drilling. We expect to
focus our conventional program of approximately 130 wells primarily in Wilmington, Huntington Beach,
Kern Front, Pleito Ranch and Mount Poso, which will largely consist of waterfloods and steamfloods
along with some primary drilling. We intend to drill approximately 20 unconventional wells in the Buena
Vista and Kettleman areas.

We also plan to use over 20% of our 2018 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 2018 capital program is intended for development facilities for our

projects, including pipeline and gathering line interconnections, gas compression and water
management systems, and about 5% is intended to be used for exploration and to maintain the
mechanical integrity, safety and environmental performance of our operations.

Reserves and Production Information

The table below summarizes our proved reserves and average net daily production as of and for

the year ended December 31, 2017 in each of California’s four major oil and gas basins:

Proved Reserves as of December 31, 2017

Average Net Daily
Production for the
Year Ended
December 31, 2017

Oil
(MMBbl)

NGLs
(MMBbl)

Natural
Gas
(Bcf)

Total
(MMBoe)

Oil
(%)

Proved
Developed
(%)

(MBoe/d)

Oil
(%)

R/P Ratio
(Years)(a)

San Joaquin Basin
Los Angeles Basin
Ventura Basin
Sacramento Basin

Total operations

265
143
34
—

442

56
—
2
—

585
10
26
85

706

63%
99%
85%

419
145
40
14 —

618

72%

70%
72%
73%
86%

71%

90
58%
27 100%
67%
6
6 —%

129

64%

12.8
14.7
18.3
6.4

13.1

Note: MMBbl refers to millions of barrels; Bcf refers to billion cubic feet of natural gas; MMBoe refers to million 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 between six Mcf of natural gas and one Bbl of oil.
(a) Calculated as total proved reserves as of December 31, 2017 divided by annualized Average Net Daily Production for

the year ended December 31, 2017.

Marketing Arrangements

Crude Oil—Substantially all of our crude oil production is connected to California markets via our

crude oil gathering pipelines, which are used almost entirely for our production. We generally do not
transport, refine or process the crude oil we produce and do not have any significant long-term crude
oil transportation arrangements. We currently 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. In addition, we evaluate opportunities to export our crude oil production. The majority of
the oil imported into California arrives via supertanker, with a minor amount arriving by rail. As a result,
California refiners have typically purchased crude oil at international waterborne-based prices.
Currently, our index-based crude oil sales contracts have 30- to 90-day terms with no such contracts
extending past one year.

Natural Gas—California imports approximately 90% of the natural gas consumed in the state. 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 36% 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 the Elk Hills field, which reduces operating costs and increases reliability. We
sell the excess to the grid and to utilities.

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 necessarily 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 years ended December 31, 2017 and 2016, our principal customers included 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. For the year ended December 31, 2015, our principal customers included
Phillips 66 Company, Tesoro Refining & Marketing Company LLC and Valero Marketing & Supply
Company, each accounted for more than 10%, and collectively, 64% 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 for current taxes, obligations or duties under applicable laws,
development obligations, or net profits interests, among others. Prior to the commencement of drilling
operations on those properties, we conduct a more thorough title examination and 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 pipeline and rail lines that only run north to south. As a result,
72% of the oil the state consumes is imported, virtually all from waterborne sources. Our proximity to
the California refineries gives us a competitive edge through lower transportation costs. 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. However, the California energy industry experienced only limited cost inflation in 2017 due
to excess capacity in the service and supply sector. Given our relative size compared to other in-state
producers, our activity influences the pricing of third-party services in the local market.

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:

oil and natural gas production, including well spacing on federal, state and private lands;

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

(cid:129)

(cid:129)
(cid:129)

(cid:129)

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,
waterflooding or steamflooding;
sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and
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.

The Division of Oil, Gas, and Geothermal Resources (DOGGR) of the Department of Conservation

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. The result of this NEPA review has the potential to impact future
leasing of federal lands in those counties for oil and gas exploration and production activities.

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 plans to issue additional
regulations with respect to certain oil and gas activities in 2018, such as management of idle wells,
pipelines and underground fluid injection. Pursuant to Assembly Bill 2729 (AB 2729), DOGGR requires
operators annually starting in 2018 to either submit idle well management plans describing how they
will plug and abandon or reactivate long-term idle wells or pay additional annual fees for each such
well. AB 2729 also requires that DOGGR update its regulations pertaining to idle well testing and
management by June 1, 2018. In September 2017, DOGGR proposed regulations that seek to impose

more stringent inspection and integrity management requirements on pipelines that are four inches or
less in diameter and located in sensitive areas. DOGGR’s plan to update underground injection
regulations in 2018, which may address injection approvals, project data requirements, mechanical
integrity testing of injection wells, monitoring and reporting requirements with respect to injection
parameters, containment or seismic activity, and incident response.

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. Among other things, SB 4 requires operators to obtain specific
well stimulation permits, make 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, though their regulations are currently being challenged in court. 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, 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. The measure
prohibits drilling of new oil and gas wells, hydraulic fracturing, other well stimulation and phases 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 and invalid by 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 hydraulic fracturing is proposed. The decision is
expected to be 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, and require attainment plans to meet those regional standards, which may include
significant 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, to prevent or reduce releases or discharges of
regulated materials to air, land, surface water or ground water;

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restrict the use, types or sources of water, energy, land surface, habitat or other natural
resources, require conservation and reclamation measures, and impose energy efficiency or
renewable energy standards on us or users of our products and services;
restrict the types, quantities and concentrations of regulated materials, including oil, natural
gas, produced water or wastes, that can be released or discharged into the environment, or
any other uses of those materials resulting from drilling, production, processing, power
generation, transportation or storage activities;
limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater
recharge, endangered species habitat and other protected areas, and require the dedication
of surface acreage for habitat conservation;
establish standards for the management of solid and hazardous wastes or the closure,
abandonment, cleanup or restoration of former operations, such as plugging and
abandonment of wells and decommissioning of facilities;
impose substantial liabilities for unauthorized releases or discharges of regulated materials
into the environment with respect to our current or former properties and operations and other
locations where such materials generated by us or our predecessors were released or
discharged;
require comprehensive environmental analyses, recordkeeping and reports with respect to
operations affecting federal, state and private lands or leases;
impose taxes or fees with respect to the foregoing matters;

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groups or others; and

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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. 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. 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.

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 has led to additional permitting and
monitoring requirements in 2017 for surface discharge of produced water. To date, the foregoing
regulatory actions have not affected our oil and natural gas production 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 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. The EPA has adopted federal regulations to:

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require reporting of annual GHG emissions from 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 such 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 propane and liquid transportation fuels sold for use in California;
established a low carbon fuel standard, which requires the use of fuels with lower carbon
intensities than traditional gasoline and diesel fuels;
impose state goals to derive 50% of California’s electricity from renewable sources and to
double the energy efficiency of buildings in the state by 2030; and
impose state goals of reducing 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 greenhouse gas 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 June 2017
to stay its 2016 methane requirements for two years and revisit their implementation, 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 late 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;

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

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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.

Employees

We had approximately 1,450 employees as of December 31, 2017, of whom approximately 1,070

were employed in field operations. Approximately 70 of our 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.

Spin-Off and Reverse Stock Split

We were incorporated in Delaware as a wholly owned subsidiary of 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 the following information available free of charge on our website at www.crc.com:

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Forms 10-K, 10-Q, 8-K and amendments to these forms as soon as reasonably practicable
after they are electronically filed with, or furnished to, the Securities and Exchange
Commission (SEC);
Other SEC filings including Forms 3, 4 and 5;
Corporate governance information, including our corporate governance guidelines, board-
committee charters and code of business conduct (see Item 10—Directors, Executive Officers
and Corporate Governance for further information); and
Other important additional information, including GAAP to non-GAAP reconciliations.

Information contained on our website is not part of this report.

ITEM 1A RISK FACTORS

RISK FACTORS

We are subject to certain risks and hazards due to the nature of our business activities. The risks
discussed below, any of which could materially and adversely affect our business, financial condition,
cash flows and results of operations, are not the only risks we face. We may experience additional
risks and uncertainties not currently known to us or, as a result of developments occurring in the future,
conditions that we currently deem to be immaterial may ultimately materially and adversely affect our
business, financial condition, cash flows and results of operations.

Commodity pricing can fluctuate widely and strongly affects our results of operations, financial
condition, cash flow and ability to invest in our assets.

Our results of operations, financial condition, cash flow and ability to invest in our assets are highly
dependent on commodity prices. Compared to early to mid-2014, global energy commodity prices have
declined significantly. We are particularly dependent on Brent crude prices that have declined from
over $110 per barrel in June 2014 to below $30 per barrel in January 2016. Brent prices have
improved since early 2016 and averaged $54.82 in 2017. However, such improvements may not
continue or may be reversed. Continued low prices for our products or further price decreases could
have several adverse effects including:

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reduced cash flow and decreased funds available for capital investments, interest payments
and operational expenses;
reduced proved oil and gas reserves over time and related cash flows;
impairments of our oil and gas properties;
reduced borrowing base capacity under our 2014 Revolving Credit Facility as proved oil and
gas reserves values fall;
the potential for a reduction of our liquidity, mandatory loan repayments and default and
foreclosure by our banks and bondholders against our secured assets;
forced monetization events and potential issues under our JV arrangements;
inability to attract counterparties to our transactions, including hedging transactions; and
inability to access funds through the capital markets and the price we could obtain for, or the
ability to conduct, asset sales or other monetization transactions.

Commodity pricing can fluctuate widely and is affected by a variety of factors, including changes in
consumption patterns; inventory levels; global and local economic conditions; the actions of OPEC and

other significant producers and governments; actual or threatened production, refining and processing
disruptions; worldwide drilling and exploration activities; the effects of conservation; weather,
geophysical and technical limitations; currency exchange rates; technological advances; transportation
and storage capacity, bottlenecks and costs in producing areas; alternative energy sources; regional
market conditions; other matters affecting the supply and demand dynamics for our products; and the
effect of changes in these variables on market perceptions. These and other factors make it impossible
to predict realized prices reliably. While our hedging activities provide some downside protection for a
significant portion of our 2018 production, they may not adequately protect us from commodity price
reductions and we may be unable to enter into acceptable additional hedges.

Our lenders require us to comply with covenants and can limit our borrowing capabilities,
which may materially limit our ability to use or access capital and our business activities.

Our ability to borrow funds under our 2014 Revolving Credit Facility is limited by our borrowing

base, the size of our lenders’ commitments, our ability to comply with covenants and a minimum
monthly liquidity requirement of $150 million. Currently, the lenders’ aggregate commitment under our
2014 Revolving Credit Facility is $1 billion, and we had approximately $850 million in availability, before
taking into account the minimum liquidity requirement. We may need to draw on our 2014 Revolving
Credit Facility for a portion of our future capital or operating needs.

The financial covenants that we must satisfy under our 2014 Revolving Credit Facility include a
monthly minimum liquidity test and quarterly first-out leverage, interest expense coverage and first-lien
asset coverage ratios. The 2014 Revolving Credit Facility also restricts our ability to monetize assets
and issue or purchase debt. Our borrowing base under our 2014 Revolving Credit Facility is
redetermined each May 1 and November 1. The borrowing base is determined with reference to a
number of factors, including commodity prices and reserves. Restrictions under our 2014 Revolving
Credit Facility are further described in Item 7—Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreements.

If we were to breach any of the covenants under our 2014 Revolving Credit Facility, our lenders
would be permitted to accelerate the principal amount due under the 2014 Revolving Credit Facility
and foreclose against the assets securing them. If payment were accelerated, or we failed to make
certain payments, under our 2014 Revolving Credit Facility, it would result in a default under our 2016
and 2017 Credit Agreements and outstanding notes and permit acceleration and foreclosure against
the assets securing the 2016 and 2017 Credit Agreements and the Second Lien Notes.

Low commodity prices, coupled with substantial interest payments, could constrain our
liquidity. A significant reduction in our liquidity may force us to take actions that could have
significant adverse effects.

The primary source of liquidity and resources to fund our capital program and other obligations is
cash flow from operations and borrowings under our 2014 Revolving Credit Facility. As noted above,
our borrowing capacity is limited.

Further price declines would reduce our cash flows from operations and may limit our access to
borrowing capacity or cause a default under our financing agreements. Under these conditions, if we
were unable to achieve improved 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 or dilution of equity. Past refinancing activities have resulted in
increases in our annual interest expense and future refinancing activities may have the same effect.

We have significant indebtedness that could make us more vulnerable in economic downturns.

As of December 31, 2017, we had long-term consolidated indebtedness of $5.3 billion. Our
financing agreements permit us to incur significant additional indebtedness as well as certain other
obligations. We may seek amendments or waivers to the extent we need to incur indebtedness above
amounts currently permitted by our financing agreements.

Certain of our outstanding indebtedness bears interest at variable rates and a rise in interest rates

will increase our interest expense to the extent we do not purchase interest-rate hedges.

Our level of indebtedness may have several important consequences, including:

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jeopardizing our ability to execute our business plans;
increasing our vulnerability to adverse changes in our business and in economic and industry
conditions;
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; and
limiting our flexibility to operate our business, compete for capital, react to competitive
pressures, and engage in certain transactions that might otherwise be beneficial to us.

Subject to certain exceptions, our financing agreements limit:

incurring additional indebtedness;
repaying junior indebtedness, including our Second Lien Notes and Senior Notes;

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entering into JVs;
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paying dividends and other restricted payments;
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creating liens on our assets;
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selling assets;
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using the proceeds of asset sales for certain purposes;
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entering into mergers or acquisitions; and
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releasing collateral.
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These limitations are further described in Item 7—Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Agreement;
Second Lien Notes; Senior Notes and the documents governing our indebtedness that are filed with
the Securities and Exchange Commission (SEC).

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 to service our debt, 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. Further, our
failure to comply with the financial and other restrictive 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 secured
credit facilities and secured notes.

Our business requires substantial capital investments, which may include acquisitions. We
may be unable to fund these investments through operating cash flow or obtain any needed
additional capital on satisfactory terms or at all, 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.

The oil and gas industry is capital intensive. We make and expect to increase capital investments

for the development and exploration of oil and gas reserves. Our ability to deploy capital as planned
depends on a number of variables, including:

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commodity prices;
regulatory and third-party approvals;
our ability to timely drill, complete and stimulate wells;
the availability of, and our ability to compete for, capital, equipment, services and personnel;
and
the availability of external sources of financing, including from JVs.

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 decline and constrain our development or acquisition activities.

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 cash flow from
operations or external sources of capital are insufficient. We may not be successful in developing,
exploring for or acquiring additional reserves. 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, which may ultimately prove to be inaccurate.

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 2017 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:

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historical production from the area compared with production from similar areas;
the quality, quantity and interpretation of available relevant data;
commodity prices;
production and operating costs;
ad valorem, excise and income taxes;
development costs;
the effects of government regulations; and
future workover and asset retirement 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.

Risks related to our acquisition and disposition activities could adversely impact our financial
condition and results of operations.

Our acquisition activities carry risks that we may: (i) not fully realize anticipated benefits due to
less-than-expected reserves or production or changed circumstances; (ii) bear unexpected integration
costs or experience other integration difficulties; (iii) experience share price declines based on the
market’s evaluation of the activity and (iv) assume liabilities that are greater than anticipated.
Furthermore, any acquisitions made in foreign countries would expose us to currency, political,
marketing, labor and other risks 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.

Our disposition activities, including JVs, carry risks that we may (i) not be able to realize
reasonable prices or rates of return for assets we sell or contribute to JVs; (ii) be required to retain
liabilities that are greater than desired or anticipated; (iii) experience increased operating costs and
(iv) burden our cash flows and borrowing base if we cannot replace the revenue lost for less than the
proceeds from the disposition, or at all.

Our business is highly regulated and government authorities can delay or deny permits and
approvals or change legal 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 delay our
implementation of, or cause us to change, our business strategy.

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 agencies have significantly revised their regulations, regulatory interpretations
and data collection and plan to issue additional regulations of certain oil and gas activities in 2018. 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 Item 1—Business—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, 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. 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.

For recent examples relating to well stimulation, water management and fluid injection see

Item 1—Business—Regulation of the Oil and Natural Gas Industry.

Changes in elected officials could result in different approaches to the regulation of the oil and gas
industry. In 2018, California will elect a new governor who will take office next year. Representatives in
the California legislature will change. We cannot predict the actions the future 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, and wells we do drill
may not yield production in economic quantities or generate our expected VCI.

Our decisions to explore, develop, purchase or otherwise exploit prospects or properties depend in

part on the evaluation of geophysical, geologic, engineering, production and other technical data and

processes. The analysis of these factors is often inconclusive or subject to varying interpretations. 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. As we enter into more JVs, our ability to ramp up and deploy internal
capital may be constrained. 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
contracts. Overruns in budgeted investments are a common risk that can make a particular project
uneconomic or less economic than forecast. We bear the risks of equipment failures, accidents,
environmental hazards, adverse weather conditions, permitting or construction delays, title disputes,
surface access disputes, disappointing drilling results or reservoir performance, including production
response to improved recovery or enhanced recovery efforts, and other associated risks. The VCI
metric we use to allocate capital is based on estimates of future cash flows and capital investment, and
therefore our projects may not generate the expected results.

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 16% of our total net undeveloped acreage at December 31,
2017.

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. We may not find commercial amounts of oil or natural gas, in
which case the value of our undeveloped acreage may decline and could be impaired. In 2017, we
drilled two exploration wells both of which were dry. We may increase the proportion of our drilling in
new or emerging plays over time.

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

Adverse tax law changes may affect our operations.

In California, there have been proposals for new taxes on oil and gas production. Although the

proposals have not become law, campaigns by various interest groups could lead to future additional
oil and gas severance or other taxes such as extending the state’s retail sales tax to many services
used in business. In addition to the existing state corporate tax rate of 8.84%, California state
lawmakers recently proposed a 10% surcharge on companies with taxable income of over $1 million.
The imposition of such 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 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. The concentration of our operations
in California and limited local storage options also increase our exposure to events such as natural
disasters, mechanical failures, industrial accidents or labor difficulties. Any one of these events has the
potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash
flows, increase operating and capital costs, prevent development of lease inventory before expiration
and limit access to markets for our products.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto,
could have an adverse effect on our ability to use derivative instruments to reduce the effect of
risks associated with our business.

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, and these rules 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, such changes could materially reduce our hedging opportunities
which could adversely affect our revenues and cash flow during periods of low commodity prices.

In addition, 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. At this time, the impact of such
regulations is not clear.

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 Item 1—Business—
Regulation of the Oil and Natural Gas Industry. In 2017, we incurred costs of approximately $27 million
for mandatory GHG emissions allowances in California, and costs of such allowances per metric ton of
GHG emissions are expected to increase in the future as CARB tightens program requirements or as
the minimum state auction price of such allowances is increased.

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. 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. 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 to permit 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 are

subject to risks such as fires, explosions, releases, discharges, equipment or information technology
failures and industrial accidents. In addition, catastrophic events such as earthquakes, floods,
mudslides, wildfires or droughts, cyber or terrorist attacks and other events may cause operations to
cease or be curtailed and may 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 attacks could affect us significantly.

We rely on electronic systems and networks to communicate, control and manage our operations

and prepare our financial management and reporting information. If we record inaccurate data or
experience infrastructure outages, our ability to communicate and control and manage our business
could be adversely affected. Cyber attacks on businesses have escalated in recent years. If we were to
experience an attack and our security measures failed, the potential consequences to our business
and the communities in which we operate could be significant.

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

We have no unresolved SEC staff comments at December 31, 2017.

ITEM 2 PROPERTIES

Our Operations

Our Areas of Operation

California is one of the most prolific oil and natural gas producing regions in the world and is
currently the fifth largest oil producing state in the nation. According to DOGGR information through
2016, 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 has been one of the top two largest oil producing counties in the lower 48 states for a
number of years. Our operations include 135 fields with 8,636 gross producing wells as of
December 31, 2017. We believe we are the largest private oil and natural gas mineral acreage holder
in California, with interests in approximately 2.3 million net mineral acres. Approximately 60% of our
total net mineral interest position is held in fee and 15% is held by production. A majority of our
interests are in producing properties located in reservoirs characterized by what we believe to be long-
lived production profiles with repeatable development opportunities.

In 2017, we produced 47 million barrels of oil equivalent (MMBoe). We added 56 MMBoe in
proved reserves in 2017, comprising 22 MMBoe from positive performance revisions and 34 MMBoe
from extensions and discoveries, representing a 119% organic reserves replacement ratio. This was
accomplished with a $371 million capital program, of which $362 million was directed to development
activities. In addition, positive price-related revisions added another 49 MMBoe of reserves. For further
information on our reserves replacement ratio, see Our Reserves—PV-10, Standardized Measure and
Reserves Replacement Ratio section below.

San Joaquin Basin

We actively operate and are developing 46 fields in this inland basin in the southern part of
California’s central valley. Our assets consist of conventional primary, IOR, EOR and unconventional
project types with approximately 1.5 million net mineral acres, approximately 66% of which we hold in
fee and another 7% is held by production. Approximately 68% of our estimated proved reserves as of
December 31, 2017 were located in, and 70% of our average daily net production for the year ended
December 31, 2017 came from, the San Joaquin basin.

According to DOGGR, approximately 75% of California’s daily oil production for 2016 was
produced in the San Joaquin basin. Commercial petroleum development began in the basin in the
1800s. Rapid discovery of many of the largest oil accumulations followed during the next several
decades, including the Elk Hills field. We have been redeveloping this field and building our expertise
to use in other fields across the state. According to the U.S. Geological Survey as of 2012, the
San Joaquin basin contained three of the 10 largest oil fields in the United States based on cumulative
production and proved reserves. We have been successfully developing steamfloods in our Kern Front
operations, which are located next to the giant Kern River field, and in the northwest portion of the
Lost Hills field. Beginning in the 1980s, reserves additions occurred in the Monterey formation on the
west side of the basin and in our new conventional field discoveries. The basin contains multiple
stacked formations throughout its areal extent, and we believe that the San Joaquin basin provides an
appealing inventory of existing field re-development opportunities, as well as new play discovery and
unconventional play potential. The complex stratigraphy and structure in the San Joaquin basin has
allowed continuing discoveries of stratigraphic and structural traps. We believe our extensive
3D seismic library, which covers nearly 3,000 square miles in the San Joaquin basin, including 50% of
our acreage, will give us a competitive advantage in further exploring this basin.

We have established a large ownership interest in several of the largest existing oil fields in the

San Joaquin basin, including Elk Hills, our largest producing field, as well as the Buena Vista and
Kettleman North Dome fields.

Elk Hills

Elk Hills is one of the largest fields in the continental United States based on proved reserves and

has produced approximately 2.0 BBoe to date. During the year ended December 31, 2017, we
produced 48 MBoe/d on average from the Elk Hills properties, or approximately 37% of our total
average daily production. Of our total Elk Hills production, 67% is liquids. 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, one of our subsidiaries generates sufficient
electricity to operate the field and sells the excess power to the grid and to utilities. A portion of the
excess power is subject to a five-year contract with a local utility, which includes a minimum capacity
payment, that provides rates that are better than those that could be received from sales to the grid.
Our operations at Elk Hills include a state-of-the-art central control facility and remote automation
control on over 95% of our wells in this field.

Los Angeles Basin

We actively operate and are developing 8 fields in this urban, coastal basin which consists of IOR

project types, approximately half of which we hold in fee and 52% held by production. Approximately
23% of our estimated proved reserves as of December 31, 2017 were located in, and 20% of our
average daily net production for the year ended December 31, 2017 came from, the Los Angeles
basin.

The 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.

Wilmington Field

The Wilmington field located in Long Beach is the fourth largest field in the United States and has

produced approximately 3.0 BBoe to date. During the year ended December 31, 2017, we produced
approximately 30 MBoe/d gross on average, or 98% of the Wilmington field’s daily production from all
producers for the year. We operate in this field on behalf of the state of California and the city of
Long Beach. Our net production in 2017 of approximately 23 MBoe/d equated to approximately 18% of
our total average daily production. Most of our Wilmington production is subject to a set of contracts
similar to production-sharing contracts 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. We use waterflood
recovery methods to develop the field. Our waterflood operations have attractive margins and returns
in the current price environment and extend the productive life of our reservoirs beyond the economic
life expected for primary development.

Ventura Basin

We actively operate and are developing 28 fields in this central California coastal basin which

consists of primary conventional, IOR, EOR and unconventional project types. We currently hold
approximately 0.2 million net mineral acres in the Ventura basin, approximately 73% of which we hold
in fee and 11% held by production. Approximately 6% of our estimated proved reserves as of
December 31, 2017 were located in, and approximately 5% of our average daily net production for the
year ended December 31, 2017 came from, the Ventura basin.

The Ventura basin is the onshore part of a structural feature and its offshore extension is the

modern Santa Barbara basin. All of the sedimentary section is productive at various locations, and
most reservoirs are sandstones with favorable porosity and permeability. The basin contains multiple
stacked formations throughout its depths, and we believe that the Ventura basin provides an appealing
inventory of existing field re-development opportunities, as well as new exploration potential.

Sacramento Basin

We actively operate and are developing 53 fields in this inland basin in the northern part of
California’s central valley, primarily consisting of dry gas production. We currently hold approximately
0.5 million net mineral acres in the Sacramento basin, approximately 38% of which we hold in fee and
44% held by production. We believe 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. As of December 31, 2017, approximately 2% of our estimated proved reserves were
located in the Sacramento basin, which accounted for approximately 5% of our average daily net
production for the year.

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.

Conventional Reservoir Recovery Methods

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
progressively using primary recovery methods, which may include some well stimulation techniques,
IOR methods like waterflooding and EOR methods such as steamflooding, using both vertical and
horizontal drilling. All of these techniques are proven technologies 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 reservoir. Primary recovery is achieved by drilling and
producing wells without supplementing the natural energy of the reservoir. Our successful exploration
program continues to provide us with primary recovery opportunities in new reservoirs or through
extensions of existing fields. Our conventional development 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 in the current price environment. 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. We use waterfloods
extensively in the San Joaquin, Los Angeles and Ventura basins, which has allowed us to reduce
production declines or modestly grow our production from mature fields such as Elk Hills and
Wilmington.

Steamfloods

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

to heat the oil, decreasing its viscosity, or thinning the oil, allowing 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 is generally
characterized by 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. 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 depletion. We use

steamfloods extensively in the San Joaquin basin, where they have allowed us to grow our production
from mature fields such as Kern Front and Lost Hills, among others.

Unconventional Reservoir

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 mineral
acres with unconventional potential and have identified over 4,930 gross (4,530 net) unconventional
drilling locations on this acreage. As a result of our development efforts in previous years,
approximately 34% of our 2017 production was from unconventional reservoirs, an increase of
approximately 91% since the acquisition of the Elk Hills field properties in 1998. As of December 31,
2017, we had proved reserves of approximately 180 MMBoe associated with our unconventional
properties, approximately 26% of which were proved undeveloped reserves.

We hold significant interests in the Monterey formation, which is divided into upper and lower
intervals. We have successfully produced from seven discrete stacked pay horizons within the upper
Monterey. During the year ended December 31, 2017, we produced approximately 53 MBoe/d on
average from upper Monterey. 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. For example, only about 25 wells have tested the lower
Monterey to date. However, we believe we will be able to apply knowledge we gain from the upper
Monterey to the lower Monterey.

Prior to the severe price declines that began in late 2014, we were focused on higher-value
unconventional production from seven discrete stacked pay horizons within the Monterey formation,
primarily within the upper Monterey. As commodity prices and project economics improved in 2017, 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. We expect to continue
pursuing unconventional opportunities in 2018 and beyond if prices remain at current levels. Over the
longer term, as project economics improve, we will seek to duplicate our successful upper Monterey
results to develop opportunities in the unconventional reservoirs of the lower Monterey, Kreyenhagen
and Moreno formations, which have similar geological attributes.

Exploration Program

We have had a successful exploration program in both conventional and unconventional plays,

including during the years prior to Spin-off. Our experienced technical staff, proprietary geological
models, leading acreage position and extensive 3D seismic library give us a strong competitive
advantage. California is one of the most prolific hydrocarbon producing regions as a result of its world-
class source rocks and stacked conventional and unconventional reservoirs. California basins have
generated billions of barrels of oil 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
basins.

We continue to focus on growing our exploration drilling locations and resource identification. We

have a ranked near-field portfolio of over 150 exploration prospects across the San Joaquin,
Sacramento and Ventura basins. As of December 31, 2017, we had approximately 12,610 gross
(5,670 net) exploration drilling locations in conventional reservoirs and approximately 6,400 gross
(5,300 net) exploration drilling locations in unconventional reservoirs.

During 2017, we drilled five shallow wells targeting heavy oil accumulations in the San Joaquin

basin. All wells encountered hydrocarbons and confirmed potential future development areas. Two of
the exploration wells are currently producing, and three of the wells were considered data wells and
were plugged and abandoned.

In 2017, we also partnered with third parties in some of our exploration activities, some of which

are not included in our consolidated results. These arrangements allow us to defer some of our
exploration costs and mitigate technical risks. With a JV partner, we drilled a successful exploration
well in a conventional reservoir in the southern San Joaquin basin to a depth of approximately
15,000 feet, which targeted a seismic defined stratigraphic trap in the prolific Stevens Sand reservoir.
The initial flow rate of the well was in excess of 300 barrels of oil a day. In connection with this JV, we
also acquired 3D seismic data in developed fields that highlighted a number of additional new leads.

At year end, we were in the process of drilling an exploration well in the Sacramento basin. The

well encountered multiple stacked gas bearing reservoirs totaling approximately 400 feet in gross
thickness. The higher quality reservoirs exhibit porosities ranging from 15% to 20%. An effective well
testing program is being planned and will be executed in 2018.

Our 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 prices), unless prices
were defined by contractual arrangements. Oil, NGLs and natural gas prices used for this purpose
were based on spot prices, adjusted for price differentials to account for gravity, quality and
transportation costs. For the 2017 reserves estimates, the calculated average Brent oil price was
$54.42 per barrel and the average NYMEX gas price was $2.98 per Million British Thermal Units
(MMBtu). The average realized prices used for the 2017 disclosures were $51.74 per barrel for oil,
$35.05 per barrel for NGLs and $2.59 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, 2017. Estimated reserves include our economic interests under
arrangements similar to production-sharing contracts 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

176
43
447

294

89
13
138

125

265
56
585

419

As of December 31, 2017
Ventura
Basin

Los Angeles
Basin

Sacramento
Basin

104
—
6

105

39
—
4

143
—
10

145

24
2
20

10
—
6

34
2
26

—
—
70

—
—
15

—
—
85

Total

304
45
543

440

138
13
163

178

442
58
706

618

(a) As of December 31, 2017, approximately 21% of proved developed oil reserves, 9% of proved developed NGLs

reserves, 15% of proved developed natural gas reserves and, overall, 19% of total proved developed reserves are
non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full 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 between six Mcf of gas

and one Bbl 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 (in MMBoe) during the years ended

December 31, 2017, 2016 and 2015 were as follows:

San Joaquin
Basin

Los Angeles
Basin(a)

Ventura
Basin

Sacramento
Basin

Total

Balance at December 31, 2014

Revisions related to price
Revisions related to

performance
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Balance at December 31, 2015

Revisions related to price
Revisions related to

performance
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Balance at December 31, 2016

Revisions related to price
Revisions related to

performance
Improved recovery
Extensions and discoveries
Purchases
Sales
Production

Balance at December 31, 2017

525
(50)

(8)
3
15
6
—
(40)

451
(17)

12
3
16
—
—
(36)

429
16

(6)
—
19
—
(6)
(33)

419

166
(85)

51
—
12
—
—
(12)

132
(23)

—
—
1
—
(1)
(10)

99
23

24
—
9
—
—
(10)

145

58
(12)

(1)
—
5
—
—
(3)

47
(20)

2
—
3
—
—
(3)

29
9

2
—
4
—
(2)
(2)

19
(6)

3
—
1
—
—
(3)

14
—

(1)
—
—
—
—
(2)

11
1

2
—
2
—
—
(2)

768
(153)

45
3
33
6
—
(58)

644
(60)

13
3
20
—
(1)
(51)

568
49

22
—
34
—
(8)
(47)

618

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

(a)

natural gas and one Bbl of oil.
Includes proved reserves related to economic arrangements similar to PSCs of 108 MMBbl, 85 MMBbl, 103 MMBbl
and 116 MMBbl at December 31, 2017, 2016, 2015 and 2014, respectively.

Our ability to add reserves, other than through purchases, 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.

Revisions of Previous Estimates

Revisions related to price—Product price changes affect the proved reserves we record. For

example, higher prices generally increase the economically recoverable reserves in all of our operations,
because the extra margin extends their expected lives and renders more projects economic. Partially

offsetting this effect, higher prices decrease our share of proved cost recovery reserves under
arrangements similar to production-sharing contracts at our Wilmington field in Long Beach because
fewer reserves are required to recover costs. Conversely, when prices drop, we experience the opposite
effects. In 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. In 2016 and 2015, total
net negative price revisions were 60 MMBoe and 153 MMBoe, respectively. The 2016 and 2015 price
revisions 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.

Revisions related to performance—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. In 2017, 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. In 2016, 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. In 2015, our
positive performance related revisions of 45 MMBoe resulted primarily from better-than-expected
reservoir performance in our San Joaquin and Los Angeles basins, combined with lower development
capital than previously estimated.

Improved Recovery

In 2017, there were no material reserves added from improved recovery. We added proved
reserves of 3 MMBoe from improved recovery through proven IOR and EOR methods in 2016 and in
2015. The improved recovery additions in both of those years were associated with the continued
development of steamflood and waterflood properties in the San Joaquin basin.

Extensions and Discoveries

In 2017, 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. In 2016 and 2015, we added 20 MMBoe and 33 MMBoe, respectively, 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.

Sales

In 2017, 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.

Proved Undeveloped Reserves

The total changes to our proved undeveloped reserves during the year ended December 31, 2017

were as follows (in MMBoe):

Balance at December 31, 2016
Revisions of previous estimates

Revisions related to performance
Revisions related to price changes

Total revisions of previous estimates
Extensions and discoveries
Sales
Transfers to proved developed reserves

Balance at December 31, 2017

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total

142

(21)
5

(16)
15
(7)
(9)

125

9
9

18
7
—
(1)

(2)
5

3
4
—
—

—

—
—

—
2
—
—

162

(14)
19

5
28
(7)
(10)

178

In 2017, we had 19 MMBoe of positive price-related revisions, partially offset by 14 MMBoe
negative performance-related revisions. Our positive price revisions were primarily the result of the
higher commodity price environment, partially offset by the effect of modestly higher operating costs.
We had negative performance-related revisions primarily resulting from 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. These negative performance-related revisions were partially offset by positive revisions
related to the successful renegotiation of our Huntington Beach royalty agreement in the Los Angeles
basin.

We had proved undeveloped reserves additions of 28 MMBoe primarily from extensions, which
were associated with the continued successful drilling program primarily in the San Joaquin and Los
Angeles basins. See more discussion of proved reserves additions from the extensions section above.

We transferred 10 MMBoe of proved undeveloped reserves to the proved developed category as a

result of the 2017 development program, all of which was in the San Joaquin and Los Angeles basins.
As a result, we converted approximately 6% of our beginning-of-year proved undeveloped reserves to
proved developed reserves during the year, investing approximately $98 million of capital. The
conversion rate reflected the lack of capital in 2016 and only a gradual ramp up of capital during 2017.
In addition, 7 MMBoe of our proved undeveloped reserves in the San Joaquin basin were conveyed to
the MIRA JV. We expect that, at about $65 to $75 average Brent prices, we will continue to grow our
program and have sufficient future capital to develop our proved undeveloped reserves existing at
December 31, 2017.

Our year-end development plans and associated proved undeveloped reserves are consistent with
SEC guidelines for development within five years. We believe we will have sufficient capital to develop
all proved undeveloped reserves within five years of their original booking date and management
commitment to do so. Our conclusion is based on $65 average Brent price for 2018, $70 average Brent
price for 2019, and $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 five-year average price remained at $65 Brent, we would need to remove approximately 8% from
our proved undeveloped reserves.

PV-10, Standardized Measure and Reserves Replacement Ratio

As of December 31, 2017, our standardized measure of discounted future net cash flows

(Standardized Measure) was $3.8 billion and PV-10 was over $4.5 billion. In addition, we organically
replaced 119% of our proved reserves in 2017.

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 reserves replacement ratio(a)

As of December 31,
2017
($ in millions)

3,765
780

4,545

119%

(a) The organic reserves replacement ratio is calculated for a specified period using the proved oil-equivalent additions
from extensions and discoveries, improved recovery and performance-related revisions, divided by oil-equivalent
production. There is no guarantee that historical sources of reserves additions will continue as many factors are fully or
partially outside management’s control, including commodity prices, availability of capital and the underlying geology, all
of which affect reserves additions. Management uses this measure to gauge the results of its capital program. Other oil
and 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, 2017 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 2017. The
Reserves Committee reports to the Audit Committee during the year.

Audits of Reserves Estimates

Ryder Scott was engaged to provide an independent audit of our 2017 and 2016 reserves

estimates for fields that in each year comprised at least 80% of our total proved reserves. The primary
technical engineer responsible for our audit has 38 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 2017 reserves audit included a detailed review of 82% of our total proved reserves. For 2017,

2016 and 2015 combined, Ryder Scott audited more than 95% of our total proved reserves. 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 at December 31, 2017. Ryder Scott’s report is attached as an exhibit to this Form 10-K.

Drilling Locations

Proven Drilling Locations

Based on our reserves report as of December 31, 2017, we have approximately 2,090 gross
(1,870 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 inventory 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 19,170 gross (17,540 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 12,610 gross (5,670 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
data from analog plays, 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 play 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 for each resource play.

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 EOR). Due to the significant vertical
thickness and multiple stacked reservoirs usually encountered by our drilling wells, 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 have been scheduled as part of our current multi-year drilling

schedule or are expected to be scheduled in the future. However, we may not drill our identified sites at
the times scheduled or at all. We view the risk profile for our exploration drilling locations as being
higher than for our other drilling locations due to relatively less available geologic and production data
and drilling history, in particular with respect to our prospective resource locations in unconventional
reservoirs, which are in unproven geologic plays. We make assumptions about the consistency and
accuracy of data when we identify these locations that may prove inaccurate.

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. 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. For a discussion of the risks associated with our drilling program, see
Item 1A—Risk Factors—Risks Related to Our Business and Industry.

The table below sets forth our total gross identified drilling locations as of December 31, 2017,

excluding our exploration drilling locations related to unconventional reservoirs.

Proven Drilling Locations

Total Identified Drilling Locations

Oil and
Natural Gas Wells

Injection
Wells

Oil and
Natural Gas Wells

Injection
Wells

San Joaquin Basin

Primary Conventional
Steamflood
Waterflood
Unconventional

San Joaquin Basin subtotal

Los Angeles Basin

Primary Conventional
Steamflood
Waterflood
Unconventional

Los Angeles Basin subtotal

Ventura Basin

Primary Conventional
Steamflood
Waterflood
Unconventional

Ventura Basin subtotal

Sacramento Basin

Primary Conventional

Sacramento Basin subtotal
Total Identified Drilling Locations

Production, Price and Cost History

120
660
140
270
1,190

—
—
410
—
410

30
—
40
—
70

20
20
1,690

—
160
60
—
220

—
—
140
—
140

—
—
40
—
40

—
—
400

8,490
8,420
2,000
4,830
23,740

—
—
1,460
—
1,460

1,850
120
1,660
100
3,730

2,420
2,420
31,350

—
460
990
—
1,450

—
—
490
—
490

—
—
580
—
580

—
—
2,520

Oil, NGLs and natural gas are commodities, and the price that 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 consumption patterns; inventory levels; global and local economic conditions; the
actions of OPEC and other significant producers and governments; actual or threatened production;
refining and processing disruptions; currency exchange rates; worldwide drilling and exploration
activities; the effects of conservation, weather, geophysical and technical limitations; technological
advances; transportation and storage capacity, bottlenecks and costs in producing areas; alternative
energy sources; regional market conditions; other matters affecting the supply and demand dynamics
for our products; and the effect of changes in these variables on market perceptions. 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.

Fixed and Variable Costs

Our total production costs consist of variable costs that tend to vary depending on 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. While 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, 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 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.

The following table sets forth information regarding our production, average realized and
benchmark prices, and costs for oil and gas producing activities for the years ended December 31,
2017, 2016 and 2015. 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.

Production Data:
Oil (MBbl/d)
NGLs (MBbl/d)
Natural gas (MMcf/d)
Average daily combined production (MBoe/d)(a)
Total combined production (MMBoe)(a)

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

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

Average costs per Boe:
Production costs
Production costs, excluding effects of PSC contracts(c)
Field general and administrative expenses(d)
Field general and administrative expenses, adjusted(e)
Field other operating expenses(d)
Field other operating expenses, adjusted(f)
Field depreciation, depletion and amortization(d)
Field taxes other than on income(d)

Year Ended December 31,
2015
2016
2017

83
16
182
129
47

91
16
197
140
51

104
18
229
160
58

$ 51.24 $ 42.01 $ 49.19
$ 51.47 $ 39.72 $ 47.15
$ 35.76 $ 22.39 $ 19.62
2.66
$

2.28 $

2.67 $

$ 54.82 $ 45.04 $ 53.64
$ 50.95 $ 43.32 $ 48.80
2.75
$

2.42 $

3.09 $

$ 18.64 $ 15.61 $ 16.30
$ 17.48 $ 14.69 $ 15.58
1.31
$
1.00
$
1.78
$
0.36
$
$ 10.85 $ 10.28 $ 16.72
2.67
$

0.84 $
0.72 $
1.02 $
0.67 $

0.82 $
0.72 $
0.66 $
0.56 $

2.36 $

2.34 $

(a) Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of

natural gas to one Bbl of oil.

(b) For 2015, the average realized price of gas includes the effect of hedges.
(c) The reporting of our PSC-like 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. The amounts
represent the production costs for the company after adjusting for this difference.

(d) Amounts exclude corporate charges.
(e) Amounts exclude corporate charges. Amounts also exclude unusual and infrequent charges related to severance and
early retirement costs associated with field personnel totaling $0.10 per Boe, $0.12 per Boe and $0.31 per Boe for
2017, 2016 and 2015, respectively.

(f) Amounts exclude corporate charges. For 2017, the amounts also exclude net unusual and infrequent charges of $0.10
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 amount also excludes net unusual and infrequent gains of $0.35 that
include refunds partially offset by plant turnaround charges and other items. For 2015, the amount also excludes
charges related to the write-down of certain assets and rig termination charges of $1.42 per Boe.

The following table sets forth information regarding production, realized prices and production
costs for our largest two fields, Elk Hills and Wilmington, for the years ended December 31, 2017, 2016
and 2015:

Production data:
Oil (MBbl/d)
NGLs (MBbl/d)
Natural gas (MMcf/d)
Average realized prices:(a)

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

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

2017

Elk Hills
2016

2015

2017

Wilmington
2016

2015

19
13
95

21
13
106

24
15
123

23
—
1

25
—
—

28
—
1

$ 55.58 $ 44.50 $ 52.78 $ 49.87 $ 37.98 $ 45.50
—
$ 36.26 $ 23.03 $ 20.12 $
$
2.05
2.67 $
$ 11.76 $ 10.48 $ 11.11 $ 27.91 $ 22.27 $ 21.87

— $
1.83 $

— $
2.12 $

2.27 $

2.52 $

N/A

N/A $ 21.59 $ 17.21 $ 17.74

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

natural gas to one Bbl of oil.

(c) The reporting of our PSC-like 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. The amounts
represent the production costs for the Company after adjusting for this difference.

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

Total Proved Reserves

% of Total Basin

Oil (%)

Average Net Daily
Production(MBoe/d)

Year ended
December 31, 2017

San Joaquin Basin

Primary Conventional
Waterfloods
Steamfloods(a)
Unconventional

San Joaquin Basin subtotal(b)

Los Angeles Basin

Primary Conventional
Waterfloods
Steamfloods
Unconventional

Los Angeles Basin subtotal(b)

Ventura Basin

Primary Conventional
Waterfloods
Steamfloods
Unconventional

Ventura Basin subtotal(b)

Sacramento Basin

Primary Conventional

Sacramento Basin subtotal(b)

Total

13%
14%
30%
43%

419

—
100%
—
—

145

35%
65%
—
—

100%

618

64%
76%
100%
33%

63%

—%
99%
—
—

99%

80%
86%
—
—

85%

—

72%

13
8
25
44

—
27
—
—

3
3
—
—

129

Includes reserves and production from gas injection of 12% and 10%, respectively.

(a)
(b) Subtotal basin reserves in MMBoe.

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. Net wells represent the
sum of fractional interests in wells in which we own an interest. Our average working interest in our
producing wells is approximately 87%. 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, 2017, excluding wells that have been idle for more than five years:

San Joaquin Basin
Los Angeles Basin
Ventura Basin
Sacramento Basin

Total(c)

As of December 31, 2017

Productive Oil Wells
Net(b)
Gross(a)

Productive Gas Wells
Gross(a)

Net(b)

8,058
1,629
819
—

10,506

6,826
1,579
812
—

9,217

162
1
—
965

135
1
—
886

1,128

1,022

Multiple completion wells included above

(a) The total number of wells in which interests are owned.
(b) Sum of our fractional interests.
(c) This total represents both producing and capable of producing wells. As of December 31, 2017, we had 2,690 gross

(2,455 net) oil wells and 308 gross (283 net) gas wells that are capable of production but currently not producing, and a
total of 8,636 gross (7,501 net) producing wells, approximately 91% of which were oil wells.

Acreage

The following table sets forth certain information regarding the total developed and undeveloped
acreage in which we owned an interest as of December 31, 2017, of which approximately 60% is held
in fee, 15% is held by production and 25% are term leases.

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

Undeveloped(d)

Gross(b)
Net(c)

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total

(in thousands)

417
379

1,317
1,087

21
16

17
14

63
61

224
187

267
247

341
261

768
703

1,899
1,549

(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 arrangements similar to production-sharing

contracts.

(d) Acres on which wells have not been drilled or completed to a point that would permit the production of commercial

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

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 acreage, we have generally been successful in obtaining extensions. The
combined net acreage covered by leases expiring in the next three years represents approximately
16% of our total net undeveloped acreage at December 31, 2017 and these expirations 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.

Drilling Activities

The following table sets forth information with respect to our net exploration and development
wells completed during the periods indicated. Net wells represent the sum of fractional interests in

wells in which we own an interest. 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

2017
Oil

Exploratory
Development

Dry

Exploratory
Development

2016
Oil

Exploratory
Development

2015
Oil

Exploratory
Development

2
92

3
—

—
37

3
254

—
15

—
—

—
5

—
29

—
2

—
—

2
109

3
—

—
42

3
283

The following table sets forth information with respect to our exploration and development wells for
which drilling was in progress or pending completion as of December 31, 2017, which are 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)

13
12
(a) The total number of wells in which interests are owned.
(b) Sum of our fractional interests.

—
—

1
1

1
—

15
13

On a gross basis, these projects included four primary, six steamfloods, one waterflood and two
unconventional wells in the San Joaquin basin, as well as one primary project in each of the Ventura
and Sacramento basins.

Delivery Commitments

We have made short-term commitments to certain refineries and other buyers to deliver oil, natural
gas and NGLs. As of December 31, 2017, we had oil, natural gas and NGL delivery commitments of 47
MBbl/d, 56 MMcf/d and 18 MBbl/d, respectively, through May 2018. These are index-based contracts
with prices set at the time of delivery. We have significantly more production capacity than the amounts
committed for oil and natural gas. We have agreements to purchase third-party NGLs for any shortfall
between the committed quantities and our production. Further, we have the ability to secure additional
volumes for all products if necessary. None of the commitments are expected to have a material
impact on our financial statements.

Our Infrastructure

We own a network of infrastructure that is integral to and significantly complements our

operations. Our significant footprint in California and wide network of infrastructure helps us connect to
third-party transportation pipelines, providing us with a competitive advantage by reducing our
operating costs. In February 2018, we entered into a midstream JV in which the Ares JV holds the Elk
Hills natural gas processing plant and power plant described below. For further information regarding
the Ares JV, see Item 7—Management’s Discussion and Analysis of Financial Condition and Results of
Operations—Joint Ventures.

Our infrastructure includes the following:

Description

Quantity

Unit(a)

San Joaquin
Basin

Capacity
Other
Basins Total

Gas Plants
Power Plants/Co-generation
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

50
50
—
20

660
650
220
320
2,100 4,500
265
1,240
>20,000

—
660

(a) MW refers to megawatts of power; MHp refers to thousand horsepower; MBw/d refers to thousand barrels of water per

day; MBbls 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 equity 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, owned by one of our subsidiaries and
located adjacent to the Elk Hills gas processing facility, generates all the electricity needs for our Elk
Hills and 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 utilities. 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 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.

ITEM 3

LEGAL PROCEEDINGS

In the fourth quarter of 2017, one of our subsidiaries settled previously disclosed notices of

violation issued by the South Coast Air Quality Management District to our subsidiary and its
predecessor alleging that emissions at a facility in Huntington Beach, California exceeded permit
conditions over certain periods in the past three years. The subsidiary paid a cash penalty of $500,000
to the District and paid an additional $1 million to fund a supplemental environmental project that is
expected to further reduce the facility’s emissions.

In November 2017, Chevron initiated a contractual dispute resolution process regarding audit
claims alleging that it has been underallocated NGLs by approximately $200 million and overcharged
for power by $50 million at the Elk Hills field. Under the applicable dispute resolution procedures, the
parties are to engage in negotiations, mediation, and, if necessary, binding arbitration. After an
extensive review of these claims, including review by third-party accounting experts with respect to the
NGL claim, we concluded and continue to believe these claims are without merit. Based on our review,
we believe that we have in fact overallocated oil, NGLs and gas to Chevron and intend to take action to
seek an adjustment in our favor.

For additional 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 7 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:

Positions Held with CRC and Predecessor and Employment
History

Age at
February 26, 2018

Name

Todd A. Stevens

Marshall D. Smith

Shawn M. Kerns

Francisco J. Leon

Roy Pineci

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.

Senior Executive Vice President and Chief Financial 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.

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.

Michael L. Preston

Executive Vice President, General Counsel and Corporate
Secretary since 2014; Occidental Oil and Gas Vice President
and General Counsel 2001 to 2014.

Charles F. Weiss

Executive Vice President—Public Affairs since 2014; Occidental
Vice President, Health, Environment and Safety 2007 to 2014.

Darren Williams

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 began trading “regular way” on the New York Stock Exchange (NYSE) under
the symbol “CRC” on December 1, 2014. Prior to that date there was no public trading market for our
common stock. 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. All share-related information is presented on a
split-adjusted basis.

The following schedule sets forth the high and low sales price per share of our common stock as

reported on the NYSE for the periods indicated:

First Quarter
Second Quarter
Third Quarter
Fourth Quarter

Holders of Record

Stock Price

2017

2016

High

Low

High

Low

$
$
$
$

23.42 $
16.25 $
11.31 $
20.19 $

12.30 $
7.73 $
6.47 $
8.84 $

23.30 $
25.50 $
15.18 $
21.97 $

2.81
9.20
8.79
9.84

Our common stock was held by approximately 21,400 stockholders of record at December 31,

2017.

Dividend Policy

In 2017 and 2016, no dividends were paid. In 2015, we paid quarterly dividends of $0.10 per share

for the first three quarters of the year.

In November 2015, our Board of Directors suspended the payment of any dividends. This decision
remains consistent with the Company’s broader initiatives to contain costs and strengthen the balance
sheet. The payment of future dividends, if any, will be at the discretion of our Board of Directors and
will depend upon, among other things, our financial condition, results of operations, capital
requirements and development expenditures, future business prospects and any restrictions imposed
by future debt instruments. 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 in our credit facilities.

Securities Authorized for Issuance Under Equity Compensation Plans

Our stock-based compensation plans were approved by our stockholders at the May 2016 annual
meeting. A description of the plans can be found in Item 8—Financial Statements and Supplementary
Data—Note 10 Stock Compensation. The aggregate number of shares of our common stock
authorized for issuance under stock-based compensation plans for our employees and non-employee
directors is 5.7 million, of which approximately 4.3 million had been issued or reserved through
December 31, 2017.

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

December 31, 2017:

a) Number of securities to be issued

b) Weighted-average exercise price of

c) Number of securities remaining

upon exercise of outstanding options,
warrants and rights

outstanding options, warrants and
rights

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

2,906,623

$69.95 (1)

1,414,162 (2)

(1) Exercise price applies only to approximately 1.1 million options included in column (a) and not to any other awards.
(2)

Includes 306,154 shares available under our 2014 Employee Stock Purchase Plan (ESPP) for purchase at 85% of the
lower of the market price at (i) the beginning of a quarter and (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 returns
shown are based on historical results and are not intended to suggest future performance.

Our peer group changed in 2017 from prior years. Our current peer group consists of 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 Inc.; Parsley Energy, Inc.; QEP Resources, Inc.; Range Resources Corporation; SM Energy
Company; Whiting Petroleum Corporation and WPX Energy, Inc. Previously, our peer group also
included Noble Energy Inc. and Pioneer Natural Resources Co.

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

$140

$120

$100

$80

$60

$40

$20

12/1/14 12/14

3/15

6/15

9/15

12/15

3/16

6/16

9/16

12/16

3/17

6/17

9/17

12/17

California Resources Corp

S&P 500

Dow Jones US Exploration & Production

Current Peer Group

Prior Peer Group

2014

2015

2016

2017

12/1 12/31 3/31 6/30 9/30 12/31 3/31 6/30 9/30 12/31 3/31 6/30 9/30 12/31

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

Production

Current Peer Group
Prior Peer Group

$ 100 $ 75 $ 103 $ 82 $ 35 $ 32 $ 14 $ 17 $ 17 $ 29 $ 21 $ 12 $ 14 $ 27
138

109

102

120

100

101

100

101

113

129

124

105

100
100
100

99
97
98

102
100
102

99
100
97

79
71
72

76
62
67

74
70
73

81
86
87

88
93
96

94
92
96

88
83
89

80
70
75

86
74
77

95
82
85

* 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:

(cid:129)

The selected statement of operations and cash flows data for the years ended December 31,
2017, 2016 and 2015 consist of our stand-alone consolidated results post Spin-off. 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. The selected statement of operations and cash flow
data for the year ended December 31, 2013 consists entirely of the combined results of the
California business.

The selected balance sheet data at December 31, 2017, 2016, 2015 and 2014 consists of our
stand-alone consolidated balances, while the selected balance sheet data at December 31,
2013 consists of the combined balances of the California business.

All share-related information is presented on a split-adjusted basis.

2017

Year Ended December 31,
2015
2016

2014

2013

(in millions, except for per share data)

Statement of Operations Data
Revenues
(Loss) income before income taxes
Net (loss) income attributable to common stock

Per common share
Basic and diluted

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

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—principal amount
Deferred gain and issuance costs, net
Other long-term liabilities
Equity attributable to common stock

$ 2,006
$
$

(262) $
(266) $

$ 1,547
201
279

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

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

4,284
1,447
869

$
$
$
$
$
$
$
$

(6.26) $

6.76

$ (92.79) $

(37.54) $

22.38

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

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

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

0.30

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

2,476
(1,669)
(44)
—
—
—
(763)
—

As of December 31,

2017

2016

2015

2014

2013

(in millions)

701
$
438
$
425
$
483
$
$ 11,685
$ 6,312
$ 5,885
$ 5,696
$ 12,429
$ 7,053
$ 6,354
$ 6,207
$
100
$
100
— $
$
$
$
605
$
726
$
732
$
$ 6,043
$ 5,168
$ 5,306
$
491
$
397
$
287
$
830
620
602
$
$
$
$
(916) $
(557) $
(814) $
$

— $
$
$
(68) $
$
549
$
2,611

254
$
$ 14,008
$ 14,297
—
689
—
—
497
9,989

922
6,360

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 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 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 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, generally as a result
of market-related variables such as consumption patterns; inventory levels; global and local economic
conditions; the actions of the Organization of the Petroleum Exporting Countries (OPEC) and other
producers and governments; actual or threatened disruptions in production, refining and processing;
currency exchange rates; worldwide drilling and exploration activities; the effects of conservation,
weather, geophysical and technical limitations; technological advances; transportation and storage
capacity; bottlenecks and costs in producing areas; alternative energy sources; regional market
conditions; and other matters affecting the supply and demand dynamics for our products; as well as
the effect of changes in these variables on market perceptions. These and other factors make it
impossible to predict realized prices reliably.

Much of the global exploration and production industry has been challenged in the low-commodity
price cycle in recent years, putting pressure on the industry’s ability to generate positive cash flow and
access capital. Global oil prices were higher in 2017 compared to 2016. Natural gas liquids (NGLs)
prices have improved relative to crude oil prices throughout 2017 due to tighter domestic supplies, the
strength of exports and higher contract prices on natural gasoline. Full year average natural gas prices
in the U.S. were higher in 2017 than in 2016 due to lower production and higher demand.

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

ended December 31, 2017, 2016 and 2015:

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

2017

2016

2015

$
$
$

54.82 $
50.95 $
3.09 $

45.04 $
43.32 $
2.42 $

53.64
48.80
2.75

We currently 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. California is
heavily reliant on imported sources of energy, with approximately 72% of the oil consumed in 2017
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. to 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, as a
result of an increase in the benchmark prices to North America from the Middle East and higher-than-
expected demand in Asia. The improvement continued into the early part of 2018.

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 magnify pricing volatility.

Natural gas prices and differentials are strongly affected by local market fundamentals, as well as

availability of transportation capacity from producing areas. Capacity influences prices because
California imports about 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 cost of our steamflood projects
and power generation. In 2017, greater availability of hydroelectricity in California due to higher-than-
normal rainfalls caused downward pressure on natural gas prices, reducing our realized prices as a
percentage of the NYMEX index, and gas storage capacity disruptions caused seasonal price volatility.

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 Elk Hills and nearby fields and increase reliability. The remaining electricity is sold to the
grid and a utility under a power purchase and sales agreement that includes a capacity payment. The price
obtained for excess power impacts our earnings but generally by an insignificant amount.

We opportunistically seek strategic hedging transactions to help protect our cash flows, margins

and capital investment program from the cyclical nature of commodity prices and to improve our ability
to comply with our debt covenants. 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
necessarily accounted for as cash-flow or fair-value hedges.

We respond to economic conditions by adjusting the amount and allocation of our capital program,

aligning the size of our workforce with our level of activity, continuing to improve efficiencies and
finding cost savings. The reductions in our capital program in 2015 and 2016 negatively impacted our
2017 production levels. With our increased capital program in 2017, our oil production flattened. With
our 2018 program we expect to achieve sustained oil production growth and end the year with higher
production than the beginning of the year. 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 electricity costs,

overall, seasonality is not a material driver of changes in our earnings during the year.

Joint Ventures

Exploration and Development Joint Ventures

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

carry all or substantially all of our exploration and development costs. These JVs allow us to continue
to develop our assets while providing us with financial flexibility and immediate production benefit.

In February 2017, we entered into a 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 JV (BSP JV). The funds contributed by BSP are designated to be used to develop certain of our
oil and gas properties. We contributed a net profits interest (NPI) in existing and future cash flow from
such properties in exchange for a common interest in the 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 two $50 million
tranches in March and July 2017, which were net of a $2 million issuance fee. The $98 million net
proceeds were used to fund capital investments of $96 million and the remainder for hedging activities.
Proceeds from the NPI are used by the BSP JV to (1) pay quarterly minimum distributions to BSP,
(2) pay for development costs within the project area, upon mutual agreement between members, and
(3) make distributions to BSP until the predetermined threshold is achieved.

In April 2017, we entered into a 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 reverts
to 75% if MIRA receives cash distributions equal to a predetermined threshold return. MIRA initially
committed $160 million, which is intended to be invested over two years. Of the committed amount,
MIRA contributed $58 million for drilling projects in 2017, with additional funding of up to $96 million
expected in 2018.

Our consolidated results reflect the full operations of our BSP JV, with BSP’s share of net income

and stockholders’ equity being shown separately as a noncontrolling interest in the accompanying
consolidated statements of operations and consolidated balance sheets, respectively. Our
consolidated results reflect only our working interest share in our MIRA JV.

We also entered into several other development and exploration JVs in which our JV partners
have committed capital of approximately $30 million. These JVs could provide more than $75 million in
capital if certain milestones are met.

Midstream Joint Venture

In February 2018, we entered into a midstream JV with ECR Corporate Holdings L.P. (ECR), a
portfolio company of Ares. This Ares JV holds the Elk Hills power plant, a 550 megawatt natural gas
fired power plant, and the 200 million cubic foot per day cryogenic gas processing plant. Through one
of our wholly owned subsidiaries, 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 in the Ares JV. The proceeds will

be utilized for our highest value projects, including but not limited to, acquisitions, investing in our
business or buying our debt. At closing, in accordance with the terms of our credit agreement, we used
$297 million of the $747 million in net proceeds to pay off the then outstanding balance of our 2014
Revolving Credit Facility.

We will consolidate the Ares JV in our financial statements and reflect the Class A common
interest and Class B preferred interest as noncontrolling interest in mezzanine equity and the Class C
common interest in equity on our balance sheet. Net income allocable to ECR will be reported as
income attributable to noncontrolling interest. Distributions will be paid to the preferred interest on a
priority basis with the remaining cash distributed pro-rata to the common interests.

Private Placement

In February 2018 and in connection with the formation of the Ares JV, 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

In February 2017, we divested non-core assets resulting in $32 million of proceeds and a

$21 million gain. During the year ended December 31, 2016, we divested non-core assets resulting in
$20 million of proceeds and a $30 million gain. During the year ended December 31, 2015, we paid
approximately $140 million to acquire certain producing and non-producing oil and gas properties,
primarily in the San Joaquin basin.

Income Taxes

On December 22, 2017, the Tax Cuts and Jobs Act (the Tax Act) was enacted. 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 interest
expense deduction. We evaluated the provisions of the Tax Act, most of which are effective January 1,
2018, and determined that because of our tax loss and valuation allowance position there is no net
current impact in our financial statements. Over the long term, the provisions are expected to be
favorable to us and should result in the deferral of cash tax payments from when they otherwise would
have been due once we begin to generate taxable income.

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

For the years ended
December 31,
2016
(in millions)

2015

2017

Pre-tax (loss) income
Income tax benefit

Net (loss) income

(262) $
—

(262)

201 $
78

279

(5,476)
1,922

(3,554)

We did not make United States federal and state income tax payments in 2017, 2016 or 2015 due

to the tax losses we incurred.

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,
2016

2015

2017

U.S. federal statutory tax rate
State income taxes, net
Decrease in U.S. federal corporate tax rate
Changes in tax attributes, net
Cancellation of debt income, net
Stock-based compensation, net
Valuation allowance, net
Other

Effective tax rate

(35)%
(6)
91
(19)
—
1
(33)
1

35%
6
—
—
(275)
2
192
1

—%

(39)%

(35) %
(5)
—
—
—
—
5
—

(35)%

During 2017, our effective tax rate differed from the statutory tax rate of 35% due to (1) a 91%

decrease related to a one-time adjustment of $240 million for the remeasurement of our net deferred
tax asset as a result of the Tax Act, (2) a 19% increase related to EOR tax credits, marginal well tax
credits and other items, and (3) a 6% increase related to state taxes. All of these items resulted in a
corresponding change to our valuation allowance, increasing our effective tax rate by 33%, because it
is not more-likely-than-not that our net deferred tax asset is realizable.

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
a 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.

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, 2017, 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 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.

Cancellation of debt income

As a result of our 2015, 2016 and 2017 debt transactions and amendments, we generated CODI

income because we determined, in 2016, 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 federal and $800 million of California CODI was relieved without any future tax liability, which
reduced our 2016 effective rate by 275%.

Operations

We conduct our operations on properties that we hold through fee interests, mineral leases and

other contractual arrangements. We believe we are the largest private oil and natural gas mineral
acreage holder in California, with interests in approximately 2.3 million net mineral acres,
approximately 60% of which we hold in fee and approximately 15% of which is held by production. Our
oil and gas leases have a primary term ranging from one to ten years, which is extended through the
end of production once it commences. We also own 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 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 20% of our production for the year ended December 31,
2017.

In addition, in line with industry practice for reporting PSC-type contracts, we report 100% of
operating costs under the PSCs in our consolidated statements of operations as opposed to reporting
only our share of those costs. We report the proceeds from production designed to recover our
partners’ share of such costs (cost recovery) in our revenues. Our reported production volumes reflect
only our share of the total volumes produced, including cost recovery, which is less than the total
volumes produced under the PSCs. This difference in reporting full operating costs but only our net
share of production inflates our operating costs per barrel, with an equal corresponding increase in
revenues, with no effect on our net results.

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

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, 2017, 2016 and 2015:

2017

2016

2015

Oil (MBbl/d)

San Joaquin Basin
Los Angeles Basin
Ventura Basin
Sacramento Basin

Total
NGLs (MBbl/d)

San Joaquin Basin
Los Angeles Basin
Ventura Basin
Sacramento Basin

Total

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

Total

Total Production (MBoe/d)(a)

52
27
4
—

15
—
1
—

140
1
8
33

182

129

57
29
5
—

15
—
1
—

150
3
8
36

197

140

64
34
6
—

104

17
—
1
—

172
2
11
44

229

160

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

(a)

thousands of barrels of oil equivalent per day.
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.

The following table sets forth the average realized prices for our products for the years ended

December 31, 2017, 2016 and 2015:

Oil prices with hedge ($ per Bbl)
Oil prices without hedge ($ per Bbl)
NGLs prices ($ per Bbl)
Natural gas prices ($ per Mcf)(a)

2017

2016

2015

$
$
$
$

51.24 $
51.47 $
35.76 $
2.67 $

42.01 $
39.72 $
22.39 $
2.28 $

49.19
47.15
19.62
2.66

(a) For 2015, the average realized price of natural gas includes the effect of hedges.

The following table presents our average price realizations as a percentage of Brent, WTI and

NYMEX for the years ended December 31, 2017, 2016 and 2015:

Oil with hedge as a percentage of Brent
Oil with hedge as a percentage of WTI
Oil without hedge as a percentage of Brent
Oil without hedge as a percentage of WTI
NGLs as a percentage of Brent
NGLs as a percentage of WTI
Natural gas as a percentage of NYMEX(a)

2017

2016

2015

93%
101%
94%
101%
65%
70%
86%

93%
97%
88%
92%
50%
52%
94%

92%
101%
88%
97%
37%
40%
97%

(a) For 2015, the average realized price of natural gas as a percentage of NYMEX includes the effect of hedges.

Balance Sheet Analysis

The changes in our balance sheet as of December 31, 2017 and 2016, are discussed below:

Cash
Trade receivables
Inventories
Other current assets, net
Property, plant and equipment, net
Other assets
Current maturities of long-term debt
Accounts payable
Accrued liabilities
Long-term debt—principal amount
Deferred gain and financing costs, net
Other long-term liabilities
Equity attributable to common stock
Equity attributable to noncontrolling interest

2017

2016

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

12
232
58
123
5,885
44
100
219
407
5,168
397
620
(557)
—

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

Cash at December 31, 2017 included approximately $5 million that is restricted under our BSP JV

agreement for distributions to BSP unless otherwise mutually agreed to by the parties. See the
Liquidity and Capital Resources section below for discussion of changes in our cash.

The increase in trade receivables was largely the result of higher year-end prices partially offset by

lower production volumes in 2017 compared to 2016. The decrease in property, plant and equipment
reflected depreciation, depletion and amortization (DD&A) for the period, partially offset by capital
investments. The decrease in other assets was primarily due to changes in the fair value of our long-
term derivative assets.

The reduction in current maturities of long-term debt was the result of the repayment of the

remaining balance on our 2014 Term Loan in November 2017. The increase in accounts payable
reflected higher capital investments in 2017 compared to 2016. The increase in accrued liabilities was
primarily due to higher derivative and greenhouse gas obligations. The small increase in our debt,
including the current maturities of our long-term debt, reflected the proceeds from the $1.3 billion credit
agreement entered into in November 2017, net of transaction costs, partially offset by early repayment
of our 2014 Term Loan, net paydown on our 2014 Revolving Credit Facility and repurchases of our
Senior Notes. See the Liquidity and Capital Resources section below for further discussion on our
debt-related activities. The decrease in deferred gain and issuance costs, net, reflected the
amortization of deferred gains, partially offset by new deferred transaction costs related to our debt
transactions and the amortization of deferred issuance costs. The decrease in other long-term liabilities
reflected changes in the fair value of our derivative liabilities, partially offset by an increase in equity
and deferred compensation obligations. The decrease in equity attributable to common stock primarily
reflected the net loss for the period. Equity attributable to noncontrolling interest primarily reflected
contributions from BSP, partially offset by distributions to BSP.

Statement of Operations Analysis

Results of Oil and Gas Operations

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

corporate items, on a per Boe basis for the years ended December 31, 2017, 2016 and 2015:

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

2017

2016

2015

$
$
$
$
$
$
$
$

18.64 $
17.48 $
0.82 $
0.72 $
0.66 $
0.56 $
10.85 $
2.34 $

15.61 $
14.69 $
0.84 $
0.72 $
1.02 $
0.67 $
10.28 $
2.36 $

16.30
15.58
1.31
1.00
1.78
0.36
16.72
2.67

(a) As described in the Operations section, the reporting of our PSC-like 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. The amounts represent the production costs for the company after adjusting for this difference.

(b) Amounts exclude corporate charges.
(c) Amounts exclude corporate charges. Amounts also exclude unusual and infrequent charges related to severance and
early retirement costs associated with field personnel totaling $0.10 per Boe, $0.12 per Boe and $0.31 per Boe, for
2017, 2016 and 2015, respectively.

(d) Amounts exclude corporate charges. For 2017, the amount excludes net unusual and infrequent charges of $0.10

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 amount excludes net unusual and infrequent gains of $0.35 that include
refunds partially offset by plant turnaround charges and other items. For 2015, the amount excludes charges related to
the write-down of certain assets and rig termination charges of $1.42 per Boe.

Consolidated Results of Operations

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

December 31, 2017, 2016 and 2015:

2017

2016

2015

Oil and gas net sales
Net derivative (losses) gains
Other revenue
Production costs
General and administrative expenses
Depreciation, depletion and amortization
Asset impairments
Taxes other than on income
Exploration expense
Other expenses, net
Interest and debt expense, net
Net gains on early extinguishment of debt
Gains on asset divestitures
Other non-operating expense

(Loss) income before income taxes

Income tax benefit

Net (loss) income
Net income attributable to noncontrolling interest

Net (loss) income attributable to common stock

Adjusted net loss
Adjusted EBITDAX
Effective tax rate

Non-GAAP Financial Measures

$1,936
(90)
160
(876)
(259)
(544)
—
(136)
(22)
(106)
(343)
4
21
(7)

(262)
—

(in millions)
$ 1,621
(206)
132
(800)
(248)
(559)

$ 2,134
133
136
(951)
(354)
(1,004)
— (4,852)
(180)
(36)
(168)
(326)
20
—
(28)

(144)
(23)
(79)
(328)
805
30
—

201
78

(5,476)
1,922

(262)
(4)

279
$ — $

(3,554)
—

$ (266)

$ 279

$(3,554)

$ (187)
$ 761

$ (317)
$ 616
— % (39)%

$ (311)
906
$
(35)%

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 nature, timing, amount
and frequency. Therefore, management uses measures called adjusted net loss and adjusted general
and administrative expenses, both of which exclude those items. These measures are not meant to
disassociate items from management’s performance, but rather are 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 loss and
adjusted general and administrative expenses are not considered to be alternatives to net income
(loss) or general and administrative expenses, respectively, reported in accordance with U.S. generally
accepted accounting principles (GAAP).

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 Adjusted EBITDAX 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. While Adjusted EBITDAX is a non-GAAP measure, the
amounts included in the calculation of Adjusted EBITDAX were computed in accordance with GAAP.
This measure 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. Certain items excluded from Adjusted EBITDAX 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. Adjusted
EBITDAX should be read in conjunction with the information contained in our financial statements
prepared in accordance with GAAP.

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

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

Non-cash derivative losses (gains), excluding

noncontrolling interest

Early retirement, severance and other costs
Net gains on early extinguishment of debt
Gains on asset divestitures
Asset impairments
Write-down of certain assets
Debt issuance costs
Other

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

Adjusted net loss

$ (187)

Net (loss) income attributable to common stock per diluted

Adjusted net loss per diluted share

$ (6.26)
$ (4.40)
(a) Amount represents the out-of-period portion of the valuation allowance reversal.

2017

2016

2015

(in millions, except share data)

$ (266)

279

$ (3,554)

78
5
(4)
(21)
—
—
—
21

79
—
—
—

283
20
(805)
(30)
—
—
—
(13)

(545)
12
(63)
—

(317)

(52)
67
(20)
—
4,852
71
28
11

4,957
—
294
(2,008)

(311)

6.76
(7.85)

$ (92.79)
(8.12)
$

$
$

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

attributable to common stock to the non-GAAP financial measure of Adjusted EBITDAX:

Net (loss) income attributable to common stock
Interest and debt expense, net
Income tax benefit
Depreciation, depletion and amortization, excluding

noncontrolling interest

Exploration expense
Unusual and infrequent items
Other non-cash items

Adjusted EBITDAX

2017

2016

2015

(266)
343
—

535
22
79
48

761

(in millions)
279
$
328
(78)

$ (3,554)
326
(1,922)

559
23
(545)
50

1,004
36
4,957
59

616

906

The following table presents the components of our net derivative (losses) gains:

Non-cash derivative (losses) gains, excluding noncontrolling interest
Non-cash derivative losses for noncontrolling interest
Cash (payments) proceeds from settled derivatives

$ (78)
(5)
(7)

(in millions)
$ (283)
—
77

Net derivative (losses) gains

$ (90)

$ (206)

$ 52
—
81

$ 133

2017

2016

2015

The following table presents the reconciliation of our company-wide GAAP financial measure of

general and administrative expenses to the non-GAAP financial measure of adjusted general and
administrative expenses:

General and administrative expenses
Early retirement and severance costs

Adjusted general and administrative expenses

Year Ended December 31, 2017 vs. 2016

2017

2016

2015

$ 259
(5)

(in millions)
$ 248
(20)

$ 354
(67)

$ 254

$ 228

$ 287

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 8,000 barrels per day, from 91,000 barrels per day in 2016 to 83,000
barrels per day in 2017. NGL production was 16,000 barrels 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
margins from natural gas trading activities 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 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 general and administrative expenses increased $11 million to $259 million in 2017 compared

to 2016. Our adjusted general and administrative expenses, which excluded early retirement and
severance costs, were $254 million and $228 million in 2017 and 2016, respectively. The 2017 period

primarily reflected higher compensation expense related to bonus and the timing of equity-based
compensation grants between years. The non-cash portion of general and administrative expenses,
comprising equity compensation and pension settlement costs, was approximately $19 million and
$25 million in 2017 and 2016, respectively.

DD&A expense decreased by $15 million in 2017 compared to 2016. Of this decrease,
approximately $45 million was attributable to lower 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 greenhouse gas emissions 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 net loss 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 transaction costs related to our JVs.

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.

Year Ended December 31, 2016 vs. 2015

Oil and gas net sales decreased 24%, or $513 million, in 2016 compared to 2015, due to
reductions of approximately $282 million and $181 million from lower oil prices and volumes,
respectively; $28 million and $26 million from lower natural gas prices and volumes, respectively;
$14 million from lower NGL volumes; and an increase of $18 million from higher NGL prices. The lower
realized oil prices reflected a 16% decrease in global oil prices. Daily oil and gas production volumes
averaged 140,000 Boe in 2016, compared with 160,000 Boe in 2015, representing a 12.5% year-over-
year decline rate, consistent with our estimated overall annual base decline rate. The 2016 production
was negatively impacted by 1,000 Boe per day due to the PSCs in our Long Beach operations.
Excluding this PSC effect, our year-over-year production decline would have been under 12%.
Average oil production decreased by 13%, or 13,000 barrels per day, to 91,000 barrels per day in 2016
compared to 2015. NGL production decreased by 11% to 16,000 barrels per day. Natural gas
production decreased by 14% to 197,000 MMcf per day, consistent with our focus on oil-based
projects. The overall production decline continued to reflect our decision to withhold development
capital and selectively defer workover and downhole maintenance activity in the early part of the year.

Derivative losses were $206 million in 2016, compared to gains of $133 million in 2015. Of the

change, $335 million was due to the valuation of outstanding derivative contracts at the end of 2016
and $4 million was the result of lower gains from cash settlements. Overall, the 2016 derivative losses
were primarily a function of the higher commodity price curve at the end of 2016 compared to the curve
when the derivatives were implemented.

Production costs were $800 million or $15.61 per Boe in 2016, compared to $951 million or $16.30

per Boe in 2015, resulting in a 16% reduction on an absolute dollar basis. Of the absolute dollar
reduction, approximately 25% related to lower energy costs, largely resulting from lower natural gas
prices. The balance, or 75% of the reduction, came from ongoing cost-reduction initiatives which
reduced costs across our operations in all categories including surface operations, downhole
maintenance and labor costs.

Our general and administrative expenses were lower in 2016 compared to 2015 on a total dollar

and per Boe basis, reflecting continued employee and contractor cost-reduction initiatives. Severance
and early retirement costs of $20 million and $67 million were included in general and administrative
expenses in 2016 and 2015, respectively. The non-cash portion of general and administrative
expenses, comprising equity compensation and a portion of pension costs, was approximately
$25 million and $30 million in 2016 and 2015, respectively.

DD&A expense decreased 44%, or $445 million, in 2016 compared to 2015, primarily due to a

$376 million decrease in the DD&A rate that resulted from asset impairments in the fourth quarter of
2015, and an approximately $73 million decrease attributable to lower volumes.

At year-end 2015, we performed impairment tests with respect to our proved and unproved
properties triggered by the sharp drop in oil prices in the fourth quarter of 2015, resulting in pre-tax
asset impairment charges of $4.9 billion.

Taxes other than on income, which include ad valorem taxes, greenhouse gas emissions costs

and production taxes, decreased 20%, or $36 million, in 2016 compared to 2015, reflecting lower
property taxes assessed in the lower price environment.

Exploration expense decreased 36%, or $13 million, in 2016 compared to 2015, due to reduced

lease rentals that we negotiated during the year and lower exploration activity.

The decrease in other expenses from $168 million in 2015 to $79 million in 2016 was largely the

result of net gains in 2016 principally from energy and property tax refunds as well as certain 2015
asset write-downs.

Interest and debt expense, net, of $328 million in 2016, compared to $326 million in 2015,
reflected higher interest rates on our new debt, increased amortization of deferred financing costs
including a $12 million write-off of the deferred financing costs associated with the tender for our notes
during 2016. Offsetting these effects were $71 million of amortization of the deferred gains from our
December 2015 debt exchange and lower overall debt principal amounts.

Net gains on early extinguishment of debt of $805 million in 2016 consisted of open-market
purchases, a debt-for-equity exchange and a cash tender for our Senior Notes. Net gains on early
extinguishment of debt of $20 million in 2015 resulted from note repurchases, net of related expenses.

Gains on asset divestitures reflected non-core asset sales during 2016.

Other non-operating expense consisted of debt-related transaction costs in 2015.

In 2016, we had pre-tax income of $201 million and an income tax benefit of $78 million reflecting
the release of a portion of the beginning of the year valuation allowance. Further, in 2016, we excluded
CODI from taxable income which resulted in a tax loss. We did not recognize a resulting tax benefit
due to the uncertainty of realizing such benefit. For 2015, we had a pre-tax loss of $5.5 billion and a
$1.9 billion benefit which was net of a $294 million change related to a valuation allowance.

Liquidity and Capital Resources

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 JV
funding to supplement our capital program. During 2017, we closed two key JV transactions. Under
these arrangements our JV partners invested $154 million in our drilling programs, some of which is
not included in our consolidated results. In February 2018, we entered into the Ares JV in which 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.

We expect the combination of these sources of capital will be adequate to fund future capital
expenditures, debt service and operating needs. Through 2017, we maintained limited cash on hand
due to our leverage position. Following the Ares JV and the private placement in February 2018, we
paid off the then outstanding balance on our 2014 Revolving Credit Facility of $297 million and expect
to carry a greater amount of cash on hand until the proceeds from these transactions are invested.

Significant changes in oil and natural gas prices have a material impact on our liquidity. Declining

commodity prices negatively affect our operating cash flow but have a positive indirect effect on
operating expenses. The inverse is also true during periods of rising commodity prices. To mitigate
some of the risk inherent in oil prices, we have utilized various derivative instruments to hedge price
risk. If commodity prices were to prevail through 2018 at about current levels, we would expect to be
able to fund our operations and capital program with our operating cash flows and would not anticipate
a net draw down on our 2014 Revolving Credit Facility. We maintain flexibility within our capital
program that helps us to scale our internally funded capital as necessary to stay within our operating
cash flow.

The Tax Act, signed into law on December 22, 2017, includes significant changes to corporate tax

provisions including a reduction in the corporate tax rate, limitations on certain corporate deductions
and favorable capital recovery provisions. This change in tax law is not expected to have any impact
on our liquidity in the foreseeable future.

Currently, we have approximately $850 million of available borrowing capacity under our 2014

Revolving Credit Facility, before taking into account the monthly minimum $150 million liquidity
requirement. Our ability to borrow funds under our 2014 Revolving Credit Facility is limited by the terms
and conditions of that facility and our ability to comply with its covenants.

As of December 31, 2017, our debt consisted of the following credit agreements, second lien

notes and senior notes:

Outstanding
Principal
(in millions)

Interest Rate

Maturity

Security(a)

Credit Agreements

2014 Revolving Credit Facility(a)

363

LIBOR plus 3.25%-4.00%
ABR plus 2.25%-3.00%

June 30, 2021

2017 Credit Agreement

2016 Credit Agreement

Second Lien Notes
Second Lien Notes

Senior Notes

5% Senior Notes due 2020

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

1,300

1,000

2,250

100

100
193

LIBOR plus 4.75%
ABR plus 3.75%

LIBOR plus 10.375%
ABR plus 9.375%

5.5%
6%

Shared First-Priority
Lien

December 31, 2022(b)

December 31, 2021

First-Priority Lien

December 15, 2022

Second-Priority Lien

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

Unsecured

Unsecured
Unsecured

Long-Term Debt—Principal Amount $

5,306

(a) Following the Ares JV transaction in February 2018, (i) we have no outstanding principal balance on our 2014

Revolving Credit Facility and (ii) the Elk Hills power plant and certain other midstream assets are no longer subject to
liens securing our indebtedness.

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

Agreement if more than $100 million is outstanding at that time.

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. Previously this credit
agreement included a term loan facility (2014 Term Loan) that was repaid in full in November 2017.

As of December 31, 2017, we had approximately $489 million of available borrowing capacity,

before taking into account 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, 2017 and 2016, we had letters of credit of approximately $148 million and
$130 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. Following the formation of the Ares JV in February 2018, the
Elk Hills power plant and certain other midstream assets are no longer subject to the shared first-
priority lien.

LIBOR loans, 3.25% to 4.00% and (ii) in the case of ABR loans, 2.25% to 3.00%. The unused portion
of our commitments is subject to a commitment fee that ranges from 0.30% to 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. Previously this
facility was subject to a springing maturity of 273 days prior to the maturity of each of our 2020 Notes
or our 2021 Notes if more than $100 million of such notes were outstanding on such date. During the
fourth quarter of 2017, we repurchased $65 million in principal amount of 2020 Notes and $35 million in
principal amount of 2021 Notes which eliminated this springing maturity feature.

Amortization Payments – The 2014 Revolving Credit Facility does not include any obligation to
make amortization payments. In November 2017, we paid the remaining balance of our 2014 Term
Loan in the amount of $559 million. Prior to that, we made a $16 million prepayment on our 2014 Term
Loan from the proceeds of non-core asset sales in February 2017. In 2016 and through the nine
months ended September 30, 2017, we made scheduled quarterly payments of $25 million on our
2014 Term Loan for an aggregate amount of $175 million. In August 2016, we made a $250 million
prepayment on our 2014 Term Loan from the proceeds of our 2016 Credit Agreement.

Borrowing Base – The borrowing base is redetermined each May 1 and November 1, and was
mostly recently reaffirmed at $2.3 billion on November 1, 2017. 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, 2017, our financial performance covenants included a

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

Components(a)

Required Levels

Ratio

Maximum leverage
ratio

Minimum interest
coverage ratio

Minimum asset
coverage ratio

Ratio of indebtedness under our
2014 Revolving Credit Facility to
trailing four-quarter Adjusted
EBITDAX
Ratio of Adjusted EBITDAX to
consolidated cash interest
charges
Ratio of PV-10 to first lien
indebtedness

Not greater than 1.90 to 1.00
through 2019
Not greater than 1.50 to 1.00
after 2019
Not less than 1.20 to 1.00

Tested

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 include covenants that, among other things,

restrict our ability to incur additional indebtedness, grant liens, make asset sales and investments,
repay existing indebtedness, pay dividends to common stockholders, make subsidiary distributions and
enter into transactions that would result in fundamental changes. Generally, these covenants include
In addition to
exceptions that allow us to pursue some of these activities in certain circumstances.
these covenants, we must also apply cash on hand in excess of $150 million daily to repay amounts
outstanding.

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

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

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

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

We are permitted to use the balance of the proceeds for general corporate purposes, including
acquisitions, and to repurchase our Second Lien Notes and Senior Notes subject to certain conditions,
including that any repurchase be at a 20% minimum discount to par, pro-forma compliance with our
financial performance covenants and that we maintain minimum liquidity of $250 million following such
repurchase.

In connection with the Ares JV transaction, we used $297 million of the net proceeds to repay all

of the then outstanding loans under our 2014 Revolving Credit Facility.

Prior Amendments – Our 2014 Revolving Credit Facility was most recently amended in November

2017. As part of that amendment, we repaid the $559 million balance of our 2014 Term Loan and
modified the financial and other covenants of our 2014 Revolving Credit Facility.

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, 2017, 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. Previously these loans included a springing maturity of 91 days prior to the maturity of our 2020
Notes or our 2021 Notes if more than $100 million of such notes were outstanding on such date.
During the fourth quarter of 2017, we repurchased $65 million in principal amount of 2020 Notes and
$35 million in principal amount of 2021 Notes which eliminated the springing maturity feature in the
2017 Credit Agreement that was tied to those notes. 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, including limitations on additional
indebtedness, liens, asset dispositions, investments and restricted payments and other negative
covenants, in each case subject to certain limitations and exceptions.

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, 2017, 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 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. Previously these loans included a
springing maturity of 91 days prior to the maturity of our 2020 Notes or our 2021 Notes if more than
$100 million of such notes were outstanding on such date. During the fourth quarter of 2017, we
repurchased $65 million in principal amount of 2020 Notes and $35 million in principal amount of 2021
Notes which eliminated the springing maturity feature in the 2016 Credit Agreement that was tied to
those notes. 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.

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.

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.

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 connection with the Spin-off in October
2014.

Repurchases and Exchanges – In 2015, we repurchased approximately $33 million in principal
amount of our 2020 Notes for $13 million in cash. We also exchanged a substantial majority of our
Senior Notes for our Second Lien Notes in December 2015 as described above. In 2016, we
repurchased over $1.5 billion in principal amount of our outstanding Senior Notes, primarily using
drawings of $750 million on our 2014 Revolving Credit Facility and cash from operations. We also
exchanged approximately 3.4 million shares of our common stock for $100 million in aggregate
principal amount of our Senior Notes. In the first quarter of 2017, we purchased $28 million in
aggregate principal amount of our 2020 Notes for $24 million in cash, resulting in a $4 million pre-tax
gain. As described above, in the fourth quarter of 2017, we also repurchased $65 million and
$35 million in aggregate principal amount of our 2020 Notes and our 2021 Notes, respectively, for
$92 million in cash, resulting in an $8 million pre-tax gain.

Financial and Other Covenants – The indenture includes covenants that, among other things,
limits our ability to grant liens securing borrowed money subject to certain exceptions and restricts 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.

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.

Other

At December 31, 2017, 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 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.

A one-eighth percent change in the variable interest rates on the borrowings under our Credit

Facilities on December 31, 2017 would result in a $3 million change in annual interest expense.

Derivatives and Hedging

Our most significant market exposure is the volatility of commodity prices. Realized prices are
primarily driven by prevailing worldwide prices for crude oil and fluctuations in spot market prices,
which are outside of our control, and can result in unpredictable operating cash flows. Global oil
markets are influenced by many factors, including the over-supply of oil in the last few years. We
maintain a commodity hedging program to help protect our cash flows, margins and capital program
from the volatility of commodity prices and to improve our ability to comply with our debt covenants.

We currently have the following Brent-based crude oil contracts, which includes activity

subsequent to December 31, 2017:

Q1
2018

Q2
2018

Q3
2018

Q4
2018

Q1
2019

Q2 -Q4
2019

FY
2020

Sold Calls:

Barrels per day
Weighted-average price per barrel

9,000
$ 59.58

6,200
$ 60.24

16,100
$ 58.91

1,100
$ 60.00

1,000
$60.00

500
$60.00

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

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

Sold Puts:

—
— $

—
2,000
— $ 71.00

—

—
$ — $ —

1,200
$ 45.82

1,200
$ 45.83

6,100
$ 61.48

1,100
$ 45.85

14,100
$ 58.93

1,000
$45.85

500
$43.91

Barrels per day
Weighted-average price per barrel

29,000
$ 45.00

24,000
$ 46.04

19,000
$ 45.00

10,000
$ 47.50

—

—
$ — $ —

Swaps:

Barrels per day
Weighted-average price per barrel

38,300
$ 60.03

34,000 (1) 19,000 (2) 19,000 (2)

7,000 (3)

$ 60.00

$ 60.13

$ 67.71

—

—
$ — $ —

(1) Certain of our counterparties have options to increase swap volumes by up to 19,000 barrels per day at a weighted-

average price of $60.00 for the second quarter of 2018.

(2) Certain of our counterparties have options to increase swap volumes by up to 29,000 barrels per day at a weighted-

average price of $60.50 for the second half of 2018.

(3) Certain of our counterparties have options to increase swap volumes by up to 5,000 barrels per day at a weighted-

average price of $70.00 for the first quarter of 2019.

A small portion of the crude oil derivatives in the table above were entered into by the BSP joint
venture entity, including some of the 2019 positions and all of the 2020 positions. This joint venture
also entered into natural gas swaps for insignificant volumes for the period of February 2018 to July
2020.

The outcomes of the derivative positions are as follows:

(cid:129) Sold calls – we make settlement payments for prices above the indicated weighted-average

price per barrel.

(cid:129) Purchased calls – we receive settlement payments for prices above the indicated weighted-

average price per barrel.

(cid:129) Purchased puts – we receive settlement payments for prices below the indicated weighted-

average price per barrel.

(cid:129) 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.

Cash Flow Analysis

Net cash provided by operating activities
Net cash used in investing activities
Net cash provided (used) by financing activities
Adjusted EBITDAX

Year Ended December 31, 2017 vs. 2016

2017

$ 248
$ (313)
$
73
$ 761

2016
(in millions)
$ 130
(61)
$
$
(69)
$ 616

2015

$ 403
$ (757)
$ 352
$ 906

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 on lower volumes, partially offset by lower receipts from settlements related to
our derivative contracts. 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

average borrowings on our overall debt. Taxes other than on income decreased $8 million from 2016
due to lower property taxes and greenhouse gas taxes, partially offset by an increase in the production
tax rate. Other changes in operating cash flow relate 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 $96 million
was funded by BSP and reported as cash provided by financing activities. 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 was primarily comprised of
$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.

Year Ended December 31, 2016 vs. 2015

Our net cash provided by operating activities in 2016 decreased by $273 million from $403 million
in 2015 to $130 million in 2016. The decrease reflected lower revenues of approximately $521 million,
primarily due to lower commodity prices and volumes, net of cash generated from our hedging

program, $25 million of higher interest payments and the negative effect of working capital changes of
$16 million, partially offset by lower costs including lower production costs of $151 million, cash general
and administrative expenses of $47 million, taxes other than on income of $36 million and exploration
expense of $13 million.

Our net cash used in investing activities decreased by approximately $696 million from
$757 million in 2015 to $61 million in 2016. The decrease reflected significantly reduced capital
investments, lower payments related to capital activity from prior periods and no acquisitions in 2016.

Our net cash used in financing activities of $69 million in 2016 included approximately $350 million

of payments on our 2014 Term Loan and debt repurchases and transaction costs of $821 million,
partially offset by the issuance of our 2016 Credit Agreement for $990 million and $108 million of net
proceeds from our 2014 Revolving Credit Facility. Our net cash provided by financing activities of
$352 million in 2015 primarily included approximately $379 million of net proceeds on our 2014
Revolving Credit Facility, partially offset by 2015 debt repurchase and amendment costs of $23 million
and $12 million in cash dividends paid.

Non-GAAP Financial Measures

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. For a discussion of our
non-GAAP financial measure of Adjusted EBITDAX, see Statements of Operations above.

Net cash provided by operating activities

Cash interest
Exploration expenditures
Other changes in operating assets and liabilities
Other, net

Adjusted EBITDAX

2017

2016

2015

$ 248
396
20
76
21

(in millions)
$ 130
384
20
95
(13)

$ 403
359
27
106
11

$ 761

$ 616

$ 906

The increase in Adjusted EBITDAX in 2017 compared to 2016 primarily resulted from higher
revenues partially offset by higher production costs, reflecting increased activity and higher gas and
electricity costs. The decrease in Adjusted EBITDAX in 2016 compared to 2015 primarily resulted from
lower revenues partially offset by lower production costs and general and administrative expenses.

2017 and 2018 Capital Program

We create value by investing our operating cash flows back into our business. We are focusing
our 2018 capital plan on oil projects, which provide high margins and low decline rates that we believe
will generate positive cash flow to fund increasing capital budgets that will grow production. Our low
decline rates compared to our industry peers plus our high level of operational control give us the
flexibility to adjust the level of such capital investments as circumstances warrant.

In 2017, we invested approximately $371 million of capital, excluding $58 million funded by our JV

partner MIRA, as compared to the total capital deployed of approximately $75 million in 2016. Our
capital predominantly targeted projects in the San Joaquin and Los Angeles basins. Virtually all of our
2017 capital was directed towards oil-weighted production consistent with 2016 and 2015. Of the total
2017 capital program, approximately $177 million was allocated to drilling wells, $89 million to capital
workovers, $71 million to facilities and compression expansion, $25 million to maintenance and
occupational health, safety and environmental projects and $9 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, 2017 (in millions):

Conventional

Unconventional

Primary

Waterflood

Steamflood

Total

Primary

Other

Total Capital
Investments

Basin:

San Joaquin
Los Angeles
Ventura
Sacramento

Basin Total

Exploration and other

Total(a)

27
—
23
6

—

40
54
2
—

—

38
—
—
—

—

105
54
25
6

190

—

172
—
—
—

172

—

190

172

$ — $
—
—
—

—

277
54
25
6

362

371

(a) Of the net $98 million contributed by BSP, $96 million was used for capital investment.

With stronger expected cash flows, we estimate our 2018 capital program will range from

We are focusing our 2018 capital on oil projects, which provide higher margins and low decline

rates that we believe will generate cash flow to fund increasing capital budgets that will grow
production. Our approach to our 2018 drilling program is consistent with our stated strategy to remain
financially disciplined and fund projects through either internally generated cash flow or JV capital to
maintain our liquidity and further strengthen our balance sheet. We 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, Wilmington, Kern Front and the delineation

and appraisal of Kettleman North Dome and Buena Vista. We will also restart our development
activities in the Huntington Beach field.

Our 2018 drilling program includes development of conventional and unconventional resources.

The depth of our primary conventional wells is expected to range from 2,000 to 15,000 feet. With a
significant reduction in our drilling costs since 2014, many of our deep conventional and
unconventional wells have become more competitive, and we expect to use approximately 60% of our
capital on drilling. We expect to focus our conventional program of approximately 130 wells primarily in
Wilmington, Huntington Beach, Kern Front, Pleito Ranch and Mount Poso, which will largely consist of
waterfloods and steamfloods along with some primary drilling. We intend to drill approximately 20
unconventional wells in the Buena Vista and Kettleman areas.

We also plan to use over 20% of our 2018 capital program for capital workovers on existing well

Further, over 15% of our 2018 capital program is intended for development facilities for our newer

As a result of higher activity levels, our production flattened in the second half of 2017 and
continues to improve in 2018 on a gross basis. We believe that the actions we have taken since the
Spin-off to streamline our business and reduce costs, together with recent price increases, have
enabled us to increase our activity level and grow our production. In addition, we will continue to build
our inventory of available projects, which will position us to take advantage of future higher prices.

Off-Balance-Sheet Arrangements

As of December 31, 2017, we had letters of credit of $148 million under our 2014 Revolving Credit

Facility and no other material off-balance-sheet arrangements other than those noted below.

Leases

We, or certain of our subsidiaries, have entered into various operating lease agreements, mainly

for field equipment, office space and office equipment. We lease assets when leasing offers greater
operating flexibility. Lease payments are generally expensed as part of production costs or general and
administrative expenses. For more information, see Contractual Obligations below.

Contractual Obligations

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

2017. This summary indicates on- and off-balance-sheet obligations as of December 31, 2017.

Payments Due by Year
2019 and
2020

2021 and
2022

2018

2023 and
thereafter

Total

On-Balance Sheet

Long-term debt—principal

amount(a)

Interest on long-term debt(b)
Asset retirement obligations(c)
Pension and postretirement
Greenhouse gas emissions(d)
Production and ad valorem taxes
Other liabilities
Off-Balance Sheet
Operating leases
Purchase obligations(e)(f)

Total(g)

(in millions)

5,306 $
1,960
422
113
106
24
14

43
215
8,203 $

— $

423
19
3
106
24
5

100 $
842
—
7

—
4

12
129
721 $

16
51
1,020 $

5,013
673
—
7

—
4

7
7
5,711

193
22
403
96

—
1

8
28
751

(a)

In performing the calculation, the 2014 Revolving Credit Facility borrowings outstanding at December 31, 2017 of
$363 million were assumed to be outstanding for the entire term of the agreement. See Item 8—Financial Statements
and Supplementary Data—Note 5 Debt for more information.

(b) The calculation of interest payable on the variable interest debt assumes the interest rate at December 31, 2017 to be

the applicable interest rate for the entire term.

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 the political and regulatory environment. See Item 8—Financial Statements and Supplementary Data—
Note 1 The Spin-Off, Summary of Significant Accounting Policies and Other for more information.

(d) The amount reflects (i) our expected cost in 2018 to acquire remaining allowances for the 2015-2017 compliance

period, including replacement of GHG allowances that we previously monetized in 2016 and (ii) a minor amount to
obtain and acquire allowances for the compliance period that commences in 2018.

(e) Amounts include payments that will become due under long-term agreements to purchase goods and services used in

(f)

the normal course of business including pipeline capacity and rig termination costs.
Included in these obligations is a commitment to invest approximately $84 million in evaluation and development
activities for one of our oil and gas properties prior to the end of 2018. Any deficiency in meeting this capital investment
obligation would need to be paid in cash. Our 2018 capital program includes the required development plans for this
property, and we expect to fulfill the minimum investment requirement.

(g) Amount excludes (1) unrecognized tax benefit of $25 million due to uncertainty with respect to the timing of future cash
outflows and (2) $19 million in obligations for derivatives based on market information as of December 31, 2017 due to
the potential significant changes to the value based on changing market conditions.

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, 2017 and 2016 were not material to our 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 on our
balance sheet 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 including pipeline capacity and rig termination costs. At
December 31, 2017, total purchase obligations on a discounted basis were approximately $215 million,
which included approximately $129 million, $33 million, $18 million, $4 million and $3 million that will be
paid in 2018, 2019, 2020, 2021 and 2022, respectively. Included in these obligations is a commitment
to invest approximately $84 million in evaluation and development activities for one of our oil and gas
properties prior to the end of 2018. Any deficiency in meeting this capital investment obligation would
need to be paid in cash. Our 2018 capital program includes development plans for these properties,
and we expect to fulfill the minimum investment requirement.

We, our subsidiaries, or both, have indemnified various parties against specific liabilities those
parties might incur in the future in connection with the Spin-off, purchases and other transactions that
they have entered into with us. These indemnities include indemnities made to Occidental Petroleum
Corporation (Occidental), our former parent, against certain tax-related liabilities that may be incurred
by Occidental relating to the Spin-off and liabilities related to operation of our business while it was still
owned by Occidental. As of December 31, 2017, we are not aware of material indemnity claims
pending or threatened against us.

We are currently under examination by the Internal Revenue Service for our U.S. federal income

tax returns for the post-Spin-off period in 2014 and calendar year 2015. No significant issues have
been raised to date. The U.S. federal income tax return for 2016 and the California franchise tax
returns for 2014 through 2016 remain subject to examination.

Critical Accounting Policies and Estimates

See Item 8—Financial Statements and Supplementary Data—Note 1 The Spin-Off, Summary of

Significant Accounting Policies and Other for our 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 matters.

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

General

Our financial results are sensitive to fluctuations in oil, NGL and gas prices. In 2018, we expect
that price changes at current levels of production, including the impact of existing hedges, will affect
our pre-tax annual income and cash flows as follows:

Pre-tax 2018 Price Sensitivities
$1 change in Brent index - Oil(a)
$1 change in Brent index - NGLs
$0.50 change in NYMEX - Gas(b)

(in millions)

$
$
$

3.3
3.2
14.0

(a) Amounts reflect the sensitivity with respect to unhedged barrels at a Brent index price at $60.00 per barrel and include

the effect of production sharing type contracts in our Wilmington field operations.

(b) Amounts reflect the sensitivity with respect to unhedged barrels at a NYMEX index price at $3.00 per barrel and

includes the offsetting effect of Elk Hills power plant and steam consumption.

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 arrangements
similar to production-sharing contracts. If production and price levels change in the future, the
sensitivity of our results to prices also will change.

Derivatives

As of December 31, 2017, we had a net derivative liability of $133 million carried at fair value,
using industry-standard models with various inputs, including quoted forward prices. 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, 2017, 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, 2017 was not material and losses associated with credit risk have been
insignificant for all years presented.

Interest Rate Risk

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

Agreement, $1 billion outstanding under our 2016 Credit Agreement and $363 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 $3 million change in annual interest expense.

The following table shows our fixed- and variable-rate debt as of December 31, 2017 (in millions):

Year of Maturity

2018
2019
2020
2021
2022
Thereafter

Total

Weighted-average interest rate

Fair value

U.S. Dollar
Fixed-Rate
Debt

U.S. Dollar
Variable-
Rate Debt

—
—
100
526
1,824
193

2,643

7.65%

2,185

—
—
—
1,363
1,300
—

2,663

8.31%

2,663

Total

—
—
100
1,889
3,124
193

5,306

7.98%

4,848

FORWARD-LOOKING STATEMENTS

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

(cid:129)

financial position, liquidity, cash flows
and results of operations
business prospects
transactions and projects
operating costs

(cid:129)
(cid:129)
(cid:129)
(cid:129) Value Creation Index (VCI) metrics are
based on certain estimates including
future rates, costs and commodity prices

(cid:129)

operations and operational results
including production, hedging and capital
investment
budgets and maintenance capital
requirements
reserves

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

(cid:129)
(cid:129)

(cid:129)

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

commodity price changes
debt limitations on our financial
flexibility
insufficient cash flow to fund planned
investment
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
unexpected geologic conditions
changes in business strategy
inability to replace reserves

(cid:129)

(cid:129)
(cid:129)

(cid:129)

insufficient capital, including as a result
of lender restrictions, unavailability of
capital markets or inability to attract
potential investors
inability to enter efficient hedges
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 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 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, 2017 and 2016, 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, 2017, 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, 2017, 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, 2017 and 2016, and the results of
its operations and its cash flows for each of the years in the three-year period ended December 31,
2017, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2017, based on criteria established in Internal Control—Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Basis for Opinion

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 26, 2018

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2017 and 2016
(in millions, except share data)

CURRENT ASSETS

Cash
Trade receivables
Inventories
Other current assets, net

Total current assets

PROPERTY, PLANT AND EQUIPMENT

Accumulated depreciation, depletion and amortization

Total property, plant, equipment, net

OTHER ASSETS

TOTAL ASSETS

CURRENT LIABILITIES

Current maturities of long-term debt
Accounts payable
Accrued liabilities

Total current liabilities

LONG-TERM DEBT—PRINCIPAL AMOUNT

DEFERRED GAIN AND ISSUANCE COSTS, NET

OTHER LONG-TERM LIABILITIES

EQUITY

Preferred stock (20 million shares authorized at $0.01 par value) no

shares outstanding at December 31, 2017 or 2016

Common stock (200 million shares authorized at $0.01 par value)

outstanding shares (2017—42,901,946 shares and 2016—42,542,637
shares)

Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss

Total equity attributable to common stock

Noncontrolling interest

Total equity

2017

2016

20 $

277
56
130

483
21,260
(15,564)

5,696
28

6,207 $

— $

257
475

732
5,306

287

602

12
232
58
123

425
20,915
(15,030)

5,885
44

6,354

100
219
407

726
5,168

397

620

—

—
4,879
(5,670)
(23)

(814)
94

(720)

—
4,861
(5,404)
(14)

(557)
—

(557)

TOTAL LIABILITIES AND EQUITY

6,207 $

6,354

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, 2017, 2016 and 2015
(in millions, except share data)

2017

2016

2015

1,936 $
(90)
160

1,621 $
(206)
132

2,006

1,547

876
259
544
—
136
22
106

800
248
559
—
144
23
79

1,943

1,853

2,134
133
136

2,403

951
354
1,004
4,852
180
36
168

7,545

(306)

(5,142)

(343)
4
21
(7)

(262)
—

(262)
(4)

(328)
805
30
—

201
78

279
—

(326)
20
—
(28)

(5,476)
1,922

(3,554)
—

(266) $

279 $ (3,554)

(6.26) $

6.76 $ (92.79)

— $

0.30

REVENUES AND OTHER
Oil and gas net sales
Net derivative (losses) gains
Other revenue

Total revenues and other

COSTS AND OTHER
Production costs
General and administrative expenses
Depreciation, depletion and amortization
Asset impairments
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 gains on early extinguishment of debt
Gains on asset divestitures
Other non-operating expense

(LOSS) INCOME BEFORE INCOME TAXES
Income tax benefit

NET (LOSS) INCOME
Net income attributable to noncontrolling interest

NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCK

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

Dividends per common share

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, 2017, 2016 and 2015
(in millions)

Net (loss) income
Other comprehensive (loss) income items:
Pension and postretirement losses(a)
Reclassification to income of realized losses on pension and

postretirement(b)

Total other comprehensive income, net of tax

Comprehensive income attributable to noncontrolling interest

2017

2016

2015

(262) $

279 $

(3,554)

(14)

(9)
—

(9)

1
—

(2)

9
—

Comprehensive (loss) income attributable to common stock

(271) $

280 $

(3,545)

(a) No associated tax for 2017 and 2016. Net of tax of $1 million for 2015. See Note 13 Pension and Postretirement Benefit

Plans, for additional information.

(b) No associated tax for 2017 and 2016. Net of tax $(7) million for 2015. See Note 13 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, 2017, 2016 and 2015
(in millions)

Common
Stock

Additional
Paid-in
Capital

Accumulated
Deficit

Accumulated
Other
Comprehensive
(Loss) Income

Equity
Attributable
to Common
Stock

Noncontrolling
Interest

Total
Equity

Balance, December 31, 2014

Net loss
Other comprehensive income,

net of tax

Dividends on common stock
Share-based compensation,

net

Balance, December 31, 2015

Net income
Other comprehensive income
Share-based compensation,

net

Balance, December 31, 2016

Net loss (income)
Contribution from

noncontrolling interest, net

Distributions paid to

noncontrolling interest
holders

Other comprehensive income
Share-based compensation,

net

— $
—

4,752 $
—

(2,117) $
(3,554)

(24) $
—

2,611 $
(3,554)

—
—

—

— $
—
—

—

— $
—

—

—
—

—

—
—

4,782 $
—
—

4,861 $
—

—

—
—

—
(12)

—

(5,683) $
279
—

—

(5,404) $
(266)

—

—
—

—

9
—

—

(15) $
—
1

—

(14) $
—

—

—
(9)

—

9
(12)

(916) $
279
1

(557) $
(266)

—

—
(9)

— $ 2,611
— (3,554)

—
—

—

— $
—
—

9
(12)

(916)
279
1

—

— $
4

(557)
(262)

(8)
—

—

(8)
(9)

Balance, December 31, 2017

— $

4,879 $

(5,670) $

(23) $

(814) $

94 $

(720)

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, 2017, 2016 and 2015
(in millions)

CASH FLOW FROM OPERATING ACTIVITIES

Net (loss) income
Adjustments to reconcile net income (loss) to net cash provided

2017

2016

2015

(262) $

279 $

(3,554)

by operating activities:
Depreciation, depletion and amortization
Asset impairments
Deferred income tax benefit
Net derivative losses (gains)
Net (payments) proceeds on settled derivatives
Net gains on early extinguishment of debt
Amortization of deferred gain
Gains on asset divestitures
Other non-cash tax provision
Other non-cash charges to income, net
Dry hole expenses

Changes in operating assets and liabilities, net:

(Increase) decrease in trade receivables
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 and 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
Contribution from noncontrolling interest, net
Distributions paid to noncontrolling interest holders
Employee stock purchases and other
Shares canceled for taxes
Issuance of common stock
Cash dividends paid

Net cash provided (used) by financing activities

Increase (decrease) in cash

Cash—beginning of year

Cash—end of year

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)
—
—

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)

—

20 $

12 $

1,004
4,852
(2,258)
(133)
81
(20)
(3)
—
310
210
9

99
—
18
(212)

403

(401)
(205)
—
(151)

(757)

2,035
(1,656)
—
—
—
(12)
(11)
—
—
—
—
8
(12)

352

(2)

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

NOTE 1 THE SPIN-OFF, SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER

The Separation and Spin-off

We are an independent oil and natural gas exploration and production company operating
properties 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. We became an
independent, publicly traded company (the Spin-off) 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, (1) all references to

‘‘CRC,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its
subsidiaries or the California business, (2) all references to the ‘‘California business’’ refer to
Occidental’s California oil and gas exploration and production operations and related assets, liabilities
and obligations, which we have assumed in connection with the Spin-off, and (3) 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 the balance sheets and
statements of operations and cash flows.

As discussed more fully in Note 3 Acquisitions and Divestitures, we entered into a development

joint venture with Benefit Street Partners (BSP) in 2017 in which we have a controlling financial
interest. Therefore, the accounts of the BSP joint venture (BSP JV) are included in our accompanying
consolidated financial statements beginning with the completion of the transaction. BSP’s portion of net
earnings and stockholders’ equity is shown separately as a noncontrolling interest in the accompanying
consolidated statements of operations and consolidated balance sheets, respectively. Our
consolidated results reflect only our working interest share in our JV with Macquarie Infrastructure and
Real Assets Inc. (MIRA JV).

Certain prior year amounts have been reclassified to conform to the 2017 presentation. On the
statement of operations, we reclassified gains on asset divestitures out of other non-operating income
(expense). On the statement of cash flows, we also moved gains on asset divestitures out of other
non-cash charges to income, net.

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. The Compensation Committee of our Board approved proportionate
adjustments to the number of shares outstanding and available for issuance under our stock-based
compensation plans and to the exercise price, grant price or purchase price relating to any award
under the plans, using the same reverse-split ratio, pursuant to existing authority granted to the
Committee under the plans.

Risks and Uncertainties

The process of preparing financial statements in conformity with United States generally accepted

accounting principles 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 years ended December 31, 2017 and 2016, 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. For the year
ended December 31, 2015, Phillips 66 Company, Tesoro Refining & Marketing Company LLC and
Valero Marketing & Supply Company each accounted for more than 10%, and collectively, 64% of our
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 which, 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 product prices typically result in additional reserves becoming economic and lower

product 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, 2017, the net capitalized costs attributable to unproved properties were
approximately $300 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 DD&A until they are classified as proved
properties. As exploration and development work progresses, if reserves on these properties are
proved, capitalized costs attributable to the properties become subject to DD&A.

Impairments of unproved properties are primarily based on qualitative factors including intent of

property development, primary 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 capitalize
development and successful exploration costs over proved developed reserves. Our remaining assets
are depreciated on a straight-line basis.

The most significant ongoing 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 $0.61 per barrel, which would increase or decrease pre-tax income (loss) by $29 million
annually based on production rates for the year ended December 31, 2017.

Asset Retirement Obligations

We recognize the fair value of asset retirement obligations 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 liability amounts
are based on future retirement cost estimates and incorporate many assumptions such as time of
abandonment, 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 PP&E balances. If the
estimated future cost of the asset retirement obligation changes, we record an adjustment to both the
asset retirement obligation 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 asset retirement obligations 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 may settle these obligations and, therefore, we cannot
reasonably estimate the fair value of these liabilities. We will recognize these asset retirement
obligations 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 asset retirement obligation, of which

$403 million and $397 million is included in other long-term liabilities, with the remaining current portion
in accrued liabilities at December 31, 2017 and 2016, respectively.

Beginning balance
Liabilities incurred—capitalized to PP&E
Liabilities settled and paid
Accretion expense
Disposition and other—changes in PP&E
Revisions to estimated cash flows—changes in PP&E

Ending balance

Pension and Postretirement Benefit Plans

For the years ended
December 31,
2016
2017

(in millions)
411 $
2
(9)
25
—
(7)

422 $

357
2
(10)
22
(17)
57

411

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 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.

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 derivatives are carried at fair value. We utilize the mid-point between bid and ask
prices for valuing these instruments. 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 (OTC) 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.
Based on the $133 million net derivative liability as of December 31, 2017, a 10% increase or decrease
in their fair value would affect pre-tax earnings by approximately $13 million.

Our property, plant and equipment 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 from oil and natural gas production when delivery occurs and title has
passed from us to the transportation company or the customer, as applicable. We recognize our share
of revenues net of any royalties and other third-party share.

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for
obsolescence. Finished goods is primarily comprised of oil and NGLs, which are valued at the lower of
cost or market. Inventories as of December 31, 2017 and 2016 consisted of the following:

Materials and supplies
Finished goods

Total

Derivative Instruments

2017

2016

(in millions)
53 $

56 $

55
3

Our derivatives are carried at fair value and on a net basis when a legal right of offset exists with

the same counterparty. Fair value gains and losses from derivative instruments are recognized on a
net basis in our consolidated statements of operations. Unless otherwise indicated, we use the term
“hedge” to describe derivative instruments that are designed to achieve our hedging program goals,
even though they are not necessarily accounted for as cash-flow or fair-value hedges.

Stock-Based Incentive Plans

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

that are more fully described in Note 10 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 at the same rate as common stock.

Under the two-class method, undistributed earnings allocated to participating securities are
subtracted from net income attributable to common stock in determining net income available to
common stockholders. In loss periods, no allocation is made to participating securities because 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 20% of our production for the year ended December 31, 2017.

Cash

Cash at December 31, 2017 included approximately $5 million that is restricted for distributions to

BSP unless otherwise mutually agreed to by the parties. For more on this acquisition, see Note 3
Acquisitions and Divestitures.

Other Current Assets

Other current assets as of December 31, 2017 and 2016 consisted of the following:

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

Other current assets

Accrued Liabilities

2017

2016

(in millions)
76 $
23
12
19

51
39
19
14

130 $

123

Accrued liabilities as of December 31, 2017 and 2016 consisted of the following:

Derivative liabilities from commodities contracts
Greenhouse gas obligations
Accrued employee-related costs
Other

Accrued liabilities

Supplemental Cash Flow Information

2017

2016

(in millions)
154 $
106
86
129

475 $

103
89
91
124

407

We did not make U.S. federal and state income tax payments in 2017, 2016 or 2015. Interest paid,

net of capitalized amounts, totaled approximately $393 million, $382 million and $350 million,
respectively, for the years ended December 31, 2017, 2016 and 2015.

NOTE 2 ACCOUNTING AND DISCLOSURE CHANGES

Recently Issued Accounting and Disclosure Changes

In 2016, the Financial Accounting Standards Board (FASB) issued rules clarifying the revenue

recognition standard issued in 2014. The new revenue recognition model is based on control, which
differs from the previous model which was based on a transfer of risks and rewards. Under the new
rules, revenue is recognized when a customer obtains control of promised goods or services in an
amount that reflects the consideration the entity expects to receive in exchange for those goods or
services. As a result, depending on where control transfers, certain fees for transportation, marketing
and processing, which were previously netted against revenue, will prospectively be presented as
expenses. We have not identified any changes to the timing of revenue recognition based on the
requirements of the new rules. The new rules also require more detailed disclosures related to the
nature, timing, amount and uncertainty of revenue and cash flows arising from contracts with
customers. We will adopt these rules in the first quarter of 2018 and apply the modified retrospective
approach.

In February 2016, the 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. These rules will be effective for fiscal years beginning
after December 15, 2018, including interim periods within those fiscal years, with earlier application
permitted. We are currently evaluating the impact of these rules on our financial statements.

In January 2017, the FASB issued rules that changed the definition of a business to assist entities
with evaluating when a set of transferred assets and activities is a business. The rules are effective for
fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with
early adoption permitted. We do not expect the adoption of these rules to have a significant impact on
our financial statements.

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 in assets.
Employers will 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. The rules are
effective for fiscal years beginning after December 15, 2017, including interim periods within those
fiscal years, with early adoption permitted. We do not expect the adoption of these rules to have a
significant impact on our financial statements.

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. The rules
are effective for fiscal years beginning after December 15, 2017, including interim periods within those
fiscal years, with early adoption permitted. The new rules will be applied prospectively to any awards
modified on or after the adoption date.

Recently Adopted Accounting and Disclosure Changes

In July 2015, the FASB issued rules requiring entities to measure inventory at the lower of cost or

net realizable value. We adopted these rules in the first quarter of 2017 with no changes to our
financial statements.

NOTE 3 ACQUISITIONS AND DIVESTITURES

2017

In February 2017, we divested non-core assets resulting in $32 million of proceeds and a

$21 million gain.

In February 2017, we entered into a joint venture (JV) with BSP where BSP will contribute up to
$250 million, subject to agreement of the parties, in exchange for a preferred interest in the BSP JV.
The funds contributed by BSP are designated to be used to develop certain of our oil and gas
properties. We contributed a net profits interest (NPI) in existing and future cash flow from such
properties in exchange for a common interest in the 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 two $50 million tranches in
March and July 2017, which were net of a $2 million issuance fee. The $98 million net proceeds were
used to fund capital investments of $96 million and the remainder for hedging activities. Proceeds from
the NPI are used by the BSP JV to (1) pay quarterly minimum distributions to BSP, (2) pay for
development costs within the project area, upon mutual agreement between members, and (3) make
distributions to BSP until the predetermined threshold is achieved.

Our consolidated results reflect the full operations of our BSP JV, with BSP’s share of net income

2016

During the year ended December 31, 2016, we divested non-core assets resulting in $20 million of

proceeds and a $30 million gain.

2015

During the year ended December 31, 2015, we paid approximately $140 million to acquire certain

producing and non-producing oil and gas properties, primarily in the San Joaquin basin.

NOTE 4 PROPERTY, PLANT AND EQUIPMENT

The carrying value of our property, plant and equipment (PP&E) represents the cost incurred to

acquire or develop the asset, including any asset retirement obligations and capitalized interest, net of
accumulated depreciation, depletion and amortization (DD&A) and any impairment charges. For assets
acquired, initial PP&E cost is based on fair values at the acquisition date. Asset retirement obligations
are capitalized and amortized over the lives of the related assets.

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 pending the determination of

proved reserves

Reclassification to property, plant and equipment based on the

determination of proved reserves

Capitalized exploratory well costs charged to expense

Balance—end of year

2017

2016

2015

(in millions)

4 $

6 $

(2)
(2)

—
(3)

4 $

(5)
(9)

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.

Our gas plant 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 ranging from two

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 ranging from two to 20 years.

No impairment charges were recorded in 2017 or 2016. In 2015, we recorded impairment charges

on our properties, in part, based on year-end forward price curves, as well as assessing projects we
determined we would not pursue in the foreseeable future given the then current environment. As a
result, in the fourth quarter of 2015, we recorded pre-tax asset impairment charges of $4.9 billion on
certain proved and unproved properties throughout our asset base. Approximately $100 million of the
charge was related to unproved properties.

NOTE 5 DEBT

As of December 31, 2017 and 2016, our debt consisted of the following credit agreements, second

lien notes and senior notes:

Outstanding
Principal
(in millions)

2017 2016

Interest Rate

Maturity

Security

Credit Agreements

2014 Revolving Credit Facility(a)

$ 363 $ 847

LIBOR plus 3.25%-4.00%
ABR plus 2.25%-3.00%

June 30, 2021

2014 Term Loan

— 650

LIBOR plus 3.25%-4.00%
ABR plus 2.25%-3.00%

June 30, 2021

Shared First-Priority
Lien

2017 Credit Agreement

1,300

—

2016 Credit Agreement

1,000 1,000

LIBOR plus 4.75%
ABR plus 3.75%

December 31,
2022(b)

Shared First-Priority
Lien

LIBOR plus 10.375%
ABR plus 9.375%

December 31, 2021

First-Priority Lien

Second Lien Notes
Second Lien Notes

Senior Notes

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

2,250 2,250

100
100
193

193
135
193

5%
5.5%
6%

December 15, 2022 Second-Priority Lien

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

Unsecured
Unsecured
Unsecured

Total Debt—Principal Amount

5,306 5,268

Less Current Maturities of Long-Term

Debt

— (100)

Long-Term Debt—Principal Amount

$5,306 $5,168

(a) Following the Ares JV transaction in February 2018, we have no outstanding principal balance on our 2014 Revolving

Credit Facility. See Note 14 Subsequent Event for further information on the Ares JV.

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

Agreement if more than $100 million is outstanding at that time.

At December 31, 2017, deferred gain and issuance costs were $287 million net, consisting of
$415 million of deferred gains offset by $128 million of deferred issuance costs and original issue

discounts. The December 31, 2016 deferred gain and issuance costs were $397 million net, consisting
of $489 million of deferred gains offset by $92 million of deferred issuance costs and original issue
discounts.

Credit Agreements

2014 Revolving Credit Facility

As of December 31, 2017, we had approximately $489 million of available borrowing capacity,

Security – As of December 31, 2017, the lenders had a shared first-priority lien on a substantial

majority of our assets, including our Elk Hills power plant and midstream assets. Following the
formation of the Ares JV in February 2018, the Elk Hills power plant and certain other midstream
assets are no longer subject to the shared first-priority lien. See Note 14 Subsequent Event for further
information on 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 our commitments is subject to a commitment fee that ranges from 0.30% to 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.

Borrowing Base – The borrowing base is redetermined each May 1 and November 1, and was
mostly recently reaffirmed at $2.3 billion on November 1, 2017. 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, 2017, 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

Minimum interest coverage
ratio

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

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

Not less than 1.20 to
1.00

Minimum asset coverage
ratio

Ratio of PV-10 to first lien
indebtedness

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, pay dividends to common stockholders, make subsidiary
distributions and enter into transactions that would result in fundamental changes. Generally, these
covenants include exceptions that allow us to pursue some of these activities in certain
circumstances.
$150 million daily to repay amounts outstanding.

In addition to these covenants, we must also apply cash on hand in excess of

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

(cid:129)

25% of such proceeds for all net cash proceeds received up to $500 million

50% of such proceeds for all net cash proceeds received between $500 million and $1 billion

75% of such proceeds for all net cash proceeds received in excess of $1 billion.

We are permitted to use the balance of the proceeds for general corporate purposes including
acquisitions and to repurchase our Second Lien Notes and Senior Notes subject to certain conditions,
including that any repurchase be at a 20% minimum discount to par, pro-forma compliance with our
financial performance covenants and that we maintain minimum liquidity of $250 million following such
repurchase.

Consistent with the terms of the 2014 Credit Facility, 50% of the proceeds of an Elk Hills power
plant sale are required to be used to repay outstanding loans with the balance of the funds used as
described above for non-borrowing base assets. In connection with the February 2018 Ares JV

100

transaction, we used $297 million of the net proceeds to repay all of the then outstanding loans under
our 2014 Revolving Credit Facility. See Note 14 Subsequent Event for further information on the Ares
JV.

Prior Amendments – Our 2014 Revolving Credit Facility was most recently amended in November

2017. As part of that amendment, we repaid the $559 million balance of our 2014 Term Loan and
modified the financial and other covenants of our 2014 Revolving Credit Facility.

2017 Credit Agreement

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

Security – Our 2017 Credit Agreement is secured by the same shared first-priority lien used to

secure our 2014 Revolving Credit Facility.

2016 Credit Agreement

In August 2016, we entered into a $1 billion credit agreement with The Bank of New York Mellon

Security – Our 2016 Credit Agreement is secured by a first-priority lien on a substantial majority of

our assets but is second in collateral recovery to our 2014 Revolving Credit Facility and 2017 Credit
Agreement.

101

Maturity Date – The loans mature on December 31, 2021. Previously these loans included a

springing maturity of 91 days prior to the maturity of our 2020 Notes or our 2021 Notes if more than
$100 million of such notes were outstanding on such date. During the fourth quarter of 2017, we
repurchased $65 million in principal amount of 2020 Notes and $35 million in principal amount of 2021
Notes which eliminated the springing maturity feature in the 2016 Credit Agreement that was tied to
those notes. 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.

Second Lien Notes

In December 2015, we issued $2.25 billion in aggregate principal amount of 8% senior secured

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.

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

Repurchases and Exchanges – In 2015, we repurchased approximately $33 million in principal
amount of our 2020 Notes for $13 million in cash. We also exchanged a substantial majority of our

102

Senior Notes for our Second Lien Notes in December 2015 as described above. In 2016, we
repurchased over $1.5 billion in principal amount of our outstanding Senior Notes, primarily using
drawings of $750 million on our 2014 Revolving Credit Facility and cash from operations. We also
exchanged approximately 3.4 million shares of our common stock for $100 million in aggregate
principal amount of our Senior Notes. In the first quarter of 2017, we purchased $28 million in
aggregate principal amount of our 2020 Notes for $24 million in cash, resulting in a $4 million pre-tax
gain. As described above, in the fourth quarter of 2017, we also repurchased $65 million and
$35 million in aggregate principal amount of our 2020 Notes and our 2021 Notes, respectively, for
$92 million in cash, resulting in an $8 million pre-tax gain.

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.

Other

At December 31, 2017, we were in compliance with all financial and other debt covenants.

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, 2017 are as follows (in

millions):

2018
2019
2020
2021
2022
Thereafter

Total

—
—
100
1,890
3,123
193

5,306

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,
2017 and 2016, including the fair value of the variable-rate portion, was approximately $4.8 billion and
$4.9 billion, respectively, compared to a carrying value of approximately $5.3 billion in both years. A
one-eighth percent change in the variable interest rates on the borrowings under our Credit Facilities
on December 31, 2017 would result in a $3 million change in annual interest expense.

103

NOTE 6 LEASE COMMITMENTS

We have entered into various operating lease agreements, mainly for office space, office
equipment and field equipment. We lease assets when leasing offers greater operating flexibility.
Lease payments are generally expensed as part of production costs or general and administrative
expenses. At December 31, 2017, future net minimum lease payments for noncancelable operating
leases (excluding oil and natural gas and other mineral leases, utilities, taxes, insurance and
maintenance expense) totaled:

2018
2019
2020
2021
2022
Thereafter

Total minimum lease payments

Amount
(in millions)
12
$
11
5
4
3
8

Rental expense for operating leases was $13 million in both 2017 and 2016 and $11 million in
2015. Minimum future lease payments and rental income from subleases was immaterial in 2017, 2016
and 2015.

NOTE 7 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

We, our subsidiaries, or both, have indemnified various parties against specific liabilities those
parties might incur in the future in connection with the Spin-off, purchases and other transactions that
they have entered into with us. These indemnities include indemnities made to Occidental against
certain tax-related liabilities that may be incurred by Occidental relating to the Spin-off and liabilities
related to operation of our business while it was still owned by Occidental. As of December 31, 2017,
we are not aware of material indemnity claims pending or threatened against us.

104

We are currently under examination by the Internal Revenue Service for our U.S. federal income

NOTE 8 DERIVATIVES

We maintain a commodity hedging program 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 as market conditions permit.

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the
same counterparty. We apply hedge accounting when transactions meet specified criteria for cash-flow
hedge treatment and management elects and documents such treatment. Otherwise, we recognize
any fair value gains or losses, over the remaining term of the hedge instrument, in earnings in the
current period.

As of December 31, 2017, we did not have any derivatives designated as hedges. 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 necessarily accounted for as cash-flow
or fair-value hedges. As part of our hedging program, we entered into a number of derivative
transactions that resulted in the following Brent-based crude oil contracts as of December 31, 2017:

Q1
2018

Q2
2018

Q3
2018

Q4
2018

FY
2019

FY
2020

Sold Calls:

Barrels per day
Weighted-average price per barrel

10,400
$ 59.38

10,400
$ 59.37

16,100
$ 58.91

1,000
$60.00

500
$60.00

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

Sold Puts:

1,200
$ 45.82

1,200
$ 45.83

1,100
$ 45.83

1,100
$ 45.85

1,000
$45.84

500
$43.91

Barrels per day
Weighted-average price per barrel

29,000
$ 45.00

19,000
$ 45.00

—

—
$ — $ —

Swaps:

Barrels per day
Weighted-average price per barrel
Note: Additional hedges for 2018 and 2019 were put in place after December 31, 2017 that are not included in the table

—
$ — $ —

38,300
$ 60.03

19,000(2)

34,000(1)

$ 60.13

$ 60.00

$ 60.13

—

(1)

(2)

above.
Certain of our counterparties have options to increase swap volumes by up to 19,000 barrels per day at a weighted-
average price of $60.00 for the second quarter of 2018.
Certain of our counterparties have options to increase swap volumes by up to 29,000 barrels per day at a weighted-
average price of $60.50 for the second half of 2018.

As of December 31, 2017, a small portion of the crude oil derivatives in the table above were
entered into by our BSP joint venture entity, including all of the 2019 and 2020 positions. This joint
venture also entered into natural gas swaps for insignificant volumes for the period of February 2018 to
July 2020.

The outcomes of the derivative positions are as follows:

(cid:129)

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

105

(cid:129)

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

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

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

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, 2017, 2016 and 2015, we recognized non-cash derivative
(losses) gains of approximately $(83) million, $(283) million and $52 million, respectively, from marking
these contracts to market, which were included in revenues.

We did not have any cash-flow hedges in 2017 and 2016. The after-tax gains and losses

recognized in, and reclassified to income from accumulated other comprehensive income (AOCI), for
derivative instruments classified as cash-flow hedges for the year ended December 31, 2015, and the
ending AOCI balances for each period were not material. The amount of the ineffective portion of cash-
flow hedges was immaterial for the year ended December 31, 2015.

We had no fair-value hedges as of and during the years ended December 31, 2017, 2016 and

2015.

106

Fair Value of Derivatives

Our commodity derivatives are measured at fair value using industry-standard models with various

inputs, including quoted forward prices, and are all classified as Level 2 in the required fair value
hierarchy for the periods presented. The following table presents the fair values (at gross and net) of
our outstanding derivatives as of December 31, 2017 and 2016 (in millions):

December 31, 2017

Gross
Amounts
Recognized at
Fair Value

Gross
Amounts
Offset in the
Balance Sheet

Net Fair Value
Presented in
the Balance
Sheet

Balance Sheet
Classification

Assets

Commodity Contracts
Commodity Contracts

Other current assets
Other assets

Liabilities

Commodity Contracts
Commodity Contracts

Accrued liabilities
Other long-term liabilities

Total derivatives

39
1

(170)
(3)

(16) $
—

16
—

(133) $

— $

23
1

(154)
(3)

(133)

December 31, 2016

Gross
Amounts
Recognized at
Fair Value

Gross
Amounts
Offset in the
Balance Sheet

Net Fair Value
Presented in
the Balance
Sheet

Balance Sheet
Classification

Assets

Commodity Contracts
Commodity Contracts

Other current assets
Other assets

Liabilities

Commodity Contracts
Commodity Contracts

Accrued liabilities
Other long-term liabilities

Total derivatives

Counterparty Credit Risk

88
25

(49) $
(6)

(152)
(58)

49
6

(97) $

— $

39
19

(103)
(52)

(97)

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
swaps and options 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 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, 2017, 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, 2017 was not material and losses associated with credit risk have been
insignificant for all years presented.

107

NOTE 9 INCOME TAXES

Income (loss) before income taxes, which is all domestic, was $(262) million, $201 million and
$(5,476) million for the years ended December 31, 2017, 2016 and 2015, respectively. The provision
(benefit) for federal, state and local income taxes consisted of the following:

For the years ended December 31,

2017

Current
Deferred

2016

Current
Deferred

2015

Current
Deferred

United States
Federal

State
and Local

Total

(in millions)

— $
—

— $

— $
(66)

(66) $

— $
—

— $

— $
(12)

(12) $

—
—

—

—
(78)

(78)

255 $

(1,961)

(1,706) $

81 $

(297)

(216) $

336
(2,258)

(1,922)

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,
2016

2017

2015

(35)%
(6)
91
(19)
—
1
(33)
1

—%

35%
6
—
—
(275)
2
192
1

(39)%

(35)%
(5)
—
—
—
—
5
—

(35)%

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 interest
expense deduction. We evaluated the provisions of the Tax Act, most of which are effective January 1,
2018, and determined that because of our tax-loss and valuation allowance position there will be no
net current impact on our financial statements. Over the long term, the provisions are expected to be
favorable to us when we begin to generate taxable income and should result in the deferral of cash tax
payments from when they otherwise would have been due.

108

During 2017, our effective tax rate differed from the statutory tax rate of 35% due to (1) a 91%

decrease related to a one-time adjustment of $240 million for the remeasurement of our net deferred
tax asset as a result of the Tax Act, (2) a 19% increase related to enhanced oil recovery (EOR) tax
credits, marginal well tax credits and other items and (3) a 6% increase related to state taxes. All of
these items resulted in a corresponding change to our valuation allowance increasing our effective tax
rate by 33%, because it is not more-likely-than-not that our net deferred tax asset is realizable.

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

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

Cancellation of debt income

As a result of our 2015, 2016 and 2017 debt transactions and amendments, we generated CODI

of $1.4 billion, $1.3 billion and $13 million, 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, in 2016, 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 federal and $800 million of California CODI was relieved without any future tax liability, which
reduced our effective rate by 275%.

109

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2017

and 2016 were as follows:

2017

2016

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
Federal effect of state income taxes
Net operating loss carryforwards and

credits
All other

Subtotal

Valuation allowance

324
33
33
53
126
—

417
22

1,008
(706)

(in millions)
— $

(261)
—
—
—
—

—
(41)

(302)
—

693
60
45
74
183
—

61
39

1,155
(780)

Total net deferred taxes

302

(302) $

375

—
(335)
—
—
—
—

—
(40)

(375)
—

(375)

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, 2017 and 2016 under the tax sharing agreement.

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, 2017 and 2016, we recorded a
$25 million liability for tax positions taken in prior periods which has been 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.

As of December 31, 2017, we had a U.S. federal net operating loss carryforward of $1.1 billion
and $1.9 billion of net operating loss carryforwards in California. The U.S. federal net operating loss
carryforward expires in 2037. The California net operating loss carryforwards began expiring in 2026. A
portion of the California net operating loss carryforwards resulted from acquisitions in prior years and is
subject to an annual limitation. Accordingly, no financial statement benefit has been recognized for
$88 million of the California net operating loss carryforwards. The deduction and carryforward period
for the U.S. federal net operating loss generated in 2017 are unchanged by the Tax Act.

During 2017, we generated $27 million of U.S federal credits primarily related to EOR projects and

marginal well credits. We also generated an $8 million California credit related to EOR projects. The
U.S. federal and California credits begin expiring in 2037.

110

NOTE 10 STOCK COMPENSATION

General

Effective May 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 officers, 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, 2017, 3.6 million shares were issued or
reserved under the Plan and 1.1 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.

Compensation expense for stock-based awards for the year ended December 31, 2017 was
$29 million, of which $22 million was included in general and administrative expenses and $7 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 $34 million, of which $27 million
was included in general and administrative expenses and $7 million was included in production costs in
our consolidated statement of operations. Compensation expense for stock-based awards for the year
ended December 31, 2015 was $37 million, of which $28 million was included in general and
administrative expenses and $9 million was included in production costs in our consolidated statement
of operations. For the years ended December 31, 2017 and 2016, we did not recognize any income tax
benefit related to our stock-based compensation. For the year ended December 31, 2015, we
recognized income tax expense of approximately $2 million. For the years ended December 31, 2017,
2016 and 2015, we made cash payments of $6 million, $5 million and $10 million for the cash-settled
portion of our awards, respectively.

As of December 31, 2017, unrecognized compensation expense for all our unvested stock-based
incentive awards, based on the year-end value of our common stock, was $40 million. This expense is
expected to be recognized over a weighted-average period of two years.

Restricted Stock

Certain employees and non-employee directors are granted restricted stock units (RSUs) or
restricted stock awards (RSAs) which are in the form of, or equivalent in value to, actual shares of our
common stock. Restricted stock is service-based and, depending on the terms of the grants, is settled
in cash or stock at the time of vesting. The service-based awards vest ratably over three years or at
the end of three years for employees and one year for directors following the date of grant. Our RSUs
and RSAs 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 and RSAs, 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 quarterly basis for the cumulative change in the value of the underlying
stock. Compensation expense for the stock-settled RSUs and RSAs is recognized on a straight-line
basis over the requisite service periods, adjusted for actual forfeitures.

111

The following summarizes our restricted stock activity for the year ended December 31, 2017:

Unvested at January 1
Granted
Vested
Forfeited

Unvested at December 31

Stock-Settled

Cash-Settled

Number of
Awards and
Units
(in thousands)

Weighted-
Average Grant-
Date Fair Value

Number of Units
(in thousands)

682 $
718 $
(337) $
(28) $

1,035 $

20.90
16.20
25.97
18.41

16.04

1,580
1,184
(597)
(101)

2,066

Note: During 2017 and 2016, our directors were granted stock-settled RSUs representing approximately 98,000 shares and

77,000 shares, respectively.

Performance Stock Unit Awards

Our performance stock units (PSUs) granted prior to 2015 are RSAs with a performance target
based on cumulative earnings before interest, taxes and depreciation. The units vest 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. 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 have nonforfeitable dividend rights with any dividends or dividend
equivalents declared during the vesting period paid as declared.

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. Less than 50 people were impacted by this modification, which resulted
in no incremental compensation cost.

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 is 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 is based on the vesting period of the award. The risk-free
rate is 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 is 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.

112

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 is 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 are 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 following summarizes our PSU activity for the year ended December 31, 2017:

Unvested at January 1
Granted
Vested
Forfeited

Unvested at December 31

Stock Options

Stock-Settled

Number of Awards
(in thousands)

Weighted-Average
Grant-Date Fair
Value

459
—
(72)
(3)

384

$
$
$
$

44.34
—
73.70
18.50

39.05

In 2014 and 2015, we granted stock options to certain executives under our long-term incentive
plan. The options permit 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 shares becoming exercisable on each
anniversary date following the date of grant, subject to certain restrictions including continued
employment. No stock options were issued during 2017 and 2016.

The fair value of stock options 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 stock option
award. The expected life of stock options is calculated based on the simplified method and represents
the period of time that options granted are expected to be held prior to exercise. In the absence of
adequate stock price history of our common stock at the time of grant, the volatility factor was based
on the average volatilities of the stocks of a select group of peer companies. The risk-free interest rate
is the implied yield available on zero-coupon United States (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.

113

The grant date assumptions used in the Black-Scholes valuation for options granted during 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 granted

2015

2014

$ 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, 2017:

Options
(000’s)

Weighted-
Average
Exercise
Price

Weighted-
Average
Grant-Date
Fair Value

Aggregate
Intrinsic
Value

Beginning balance, January 1
Granted
Exercised
Forfeited

Ending balance, December 31

1,109 $
— $
— $
(4) $

1,105 $

69.89 $
— $
— $
54.12 $

69.95 $

Exercisable at December 31

1,013 $

72.47 $

Employee Stock Purchase Plan

18.42

$
— $
— $
$

16.49

18.43

18.74

—
—
—
—

—

Effective January 1, 2015, we adopted the California Resources Corporation 2014 Employee
Stock Purchase Plan (ESPP), which was subsequently amended in May 2016. 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 shares of our common stock that may be issued pursuant to the ESPP is

subject to certain annual limits and has a cumulative limit of one million shares, subject to adjustment
pursuant to the terms of the ESPP. For the year ended December 31, 2017, we issued approximately
0.2 million shares of common stock in connection with our ESPP.

NOTE 11 EQUITY

The following is a summary of common stock issuances on a post-split basis:

Balance, December 31, 2015

Issued

Balance, December 31, 2016

Issued

Balance, December 31, 2017

114

Common Stock
(in thousands)

38,818
3,725

42,543
359

42,902

At December 31, 2017 and 2016, we had 200 million authorized shares of common stock and

20 million authorized shares of preferred stock, both with a $0.01 par value per share, and no
outstanding shares of preferred stock on either date.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) consisted of pension and post-retirement losses

of $23 million and $14 million, at December 31, 2017 and 2016, respectively.

NOTE 12 EARNINGS PER SHARE

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

December 31:

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

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

Net (loss) income available to common stockholders

Weighted-average common shares outstanding—basic

Basic EPS

Diluted EPS calculation

Net income (loss)
Less: net income attributable to noncontrolling interest

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

2017
2015
2016
(in millions, except per-share amounts)

(262) $
(4)

(266)
—

279 $ (3,554)
—

—

279
(6)

(3,554)
—

(266) $

273 $ (3,554)

42.5

40.4

38.3

(6.26) $

6.76 $ (92.79)

(262) $
(4)

(266)
—

279 $ (3,554)
—

—

279
(6)

(3,554)
—

Net (loss) income available to common stockholders

(266) $

273 $ (3,554)

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

Weighted-average common shares outstanding—diluted

Diluted EPS

42.5
—

42.5

40.4
—

40.4

38.3
—

38.3

(6.26) $

6.76 $ (92.79)

Weighted-average anti-dilutive shares(a)

2.1

1.7

1.3

(a) Anti-dilutive shares represent potentially dilutive securities that are excluded from the computation of diluted EPS due to

our net loss position. Anti-dilutive shares include the effect of out-of-the-money stock options and exclude the
performance stock units issued in 2015.

NOTE 13 PENSION AND POSTRETIREMENT BENEFIT PLANS

We have various qualified and non-qualified benefit plans for our salaried and union and nonunion

hourly employees.

Defined Contribution Plans

All of our employees are eligible to participate in our defined contribution retirement plan that

provides for periodic contributions by us based on plan-specific criteria, such as eligible pay and
employee contributions.

115

Certain salaried employees participate in supplemental plans that restore benefits lost due to

governmental limitations on qualified plans. As of December 31, 2017 and 2016, we recognized
$32 million and $31 million in other long-term liabilities for these supplemental plans.

We expensed $33 million in 2017, $32 million in 2016 and $39 million in 2015 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 2017,

approximately 70 employees accrued benefits under these plans, all of whom were union
employees. Effective December 31, 2015, the plans were amended such that participants other than
union employees no longer earn benefits for service after December 31, 2015.

Pension costs for the defined benefit pension plans, determined by independent actuarial

valuations, are funded by us through payments to trust funds, which are administered by independent
trustees.

Postretirement Benefit Plans

We provide postretirement medical and dental benefits for our eligible former employees and their

dependents. The benefits are funded by us and required contributions from former employees as
claims are paid during the year.

116

(2)
(75)

(77)

2016

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:

As of December 31,
2017
2016
2017
Pension Benefits

2016

Postretirement Benefits

Amounts recognized in the balance sheet:

Accrued liabilities
Other long-term liabilities

Amounts recognized in accumulated other

comprehensive (loss) income:

(in millions)

—
(19)

(19)

(13)

—
(26)

(26)

(16)

(3)
(90)

(93)

(10)

As of December 31,
2017
2016
2017
Pension Benefits

Postretirement Benefits

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

Service cost—benefits earned during the

period

Interest cost on projected benefit obligation
Actuarial loss
Benefits paid

Benefit obligation—end of year

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

Actual return on plan assets
Employer contributions
Benefits paid

Fair value of plan assets—end of year

Unfunded status

(in millions)

1
2
7
(15)

44
5
12
(15)

(19)

1
3
7
(24)

56
2
10
(24)

(26)

3
4
11
(2)

—
—
2
(2)

—

(93)

3
3
1
(1)

—
—
1
(1)

—

(77)

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

2017

2016

(in millions)
65 $
62 $
46 $

70
67
44

$
$
$

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

obligations. We do not expect any plan assets to be returned during 2018.

117

Components of Net Periodic Benefit Cost

The following tables set forth our pension and postretirement benefit costs and amounts

recognized in other comprehensive income (before tax):

For the years ended December 31,

2017

2016
Pension Benefits

2015

2017
2015
2016
Postretirement Benefits

(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 cost
Curtailment loss

1 $
2
(3)
2
5
—

1 $
3
(3)
2
8
—

4 $
4
(5)
3
18
—

Net periodic benefit cost

7 $

11 $

24 $

3 $
4
—
—
—
—

7 $

3 $
3
—
—
—
—

5
3
—
—
—
5

6 $

For the years ended December 31,

2017

2016
Pension Benefits

2015

2017
2015
2016
Postretirement Benefits

Amounts recognized in other comprehensive

income (loss):
Net actuarial (loss) gain
Net prior service credit
Settlement cost
Amortization of net actuarial gain/loss

Total recognized in other comprehensive

(4) $
—
5
2

(in millions)

(9) $ (28) $ (12) $ — $
—
8
2

12
18
3

—
—
—

9
—
—
—

income (loss)

3 $

1 $

5 $ (12) $ — $

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

curtailment loss in 2015 related to employee reductions.

The estimated net actuarial loss and prior service credit for the defined benefit pension plans that

will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $2 million and
$0, respectively. We do not expect to have any estimated net actuarial loss or prior service cost for the
defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over
the next fiscal year.

118

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,

2016
2017
Pension Benefits

2017

2016

Postretirement Benefits

3.53%
4.00%

3.88%
6.50%
4.00%

3.88%
4.00%

3.99%
6.50%
4.00%

3.87%
—

4.58%
—
—

4.58%
—

4.81%
—
—

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 2017 and 2016. 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 2017, we adopted the Society of Actuaries MP-2017 Mortality Improvement Scale,

which updated the Society of Actuaries Adjusted RP-2014 mortality assumptions that private defined
benefit pension plans in the United States use in the actuarial valuations that determine a plan
sponsor’s pension and postretirement obligations. In 2016, we utilized the Society of Actuaries
Adjusted RP-2014 Mortality Table reflecting the MP-2016 Mortality Improvement Scale. At
December 31, 2017, the changes in the mortality assumptions resulted in no significant change to the
pension benefit obligations and a decrease of $1 million in 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 1.97% as of December 31, 2017 and 2016. 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, 2017, healthcare cost trend rates would decrease 0.25 percent per year from 7.00% in
2018 until they reach 6.00% in 2022, then decrease 0.50 percent per year until they reach 4.50% in
2025, and remain at 4.50% thereafter. A one-percent increase or a one-percent decrease in these
assumed healthcare cost trend rates would result in an increase of $5 million or a reduction of
$4 million, respectively, in the postretirement benefit obligation as of December 31, 2017. The annual
service and interest costs would not be materially affected by these changes.

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

119

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 2017 and 2016, the
target allocation of plan assets was 65% equity securities and 35% debt securities. Investment
performance was measured and monitored on an ongoing basis through quarterly investment portfolio
and manager guideline compliance reviews, annual liability measurements and periodic studies.

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, 2017 Using

Level 1

Level 2

Level 3

Total

(in millions)

— $

—
—
—

6
3
3
3
—

7
9
5

—
—
—
—
—

—
—
—

—
—
—
—
7

Fair Value Measurements at
December 31, 2016 Using

Level 1

Level 2

Level 3

Total

(in millions)

— $

—
—
—

4
2
2
2
—

9
10
6

—
—
—
—
—

—
—
—

—
—
—
—
6

7
9
5

6
3
3
3
7

9
10
6

4
2
2
2
6

The activity during the years ended December 31, 2017 and 2016, for the assets using Level 3 fair

value measurements was insignificant.

120

Expected Cash Flows

In 2018, we plan to contribute $3 million to our postretirement benefit plans and at least our

minimum funding requirement of $4 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,

2018
2019
2020
2021
2022
2023 - 2027

Pension
Benefits

Postretirement
Benefits

(in millions)
21
5
5
5
4
16

$
$
$
$
$
$

3
3
4
4
4
23

$
$
$
$
$
$

NOTE 14 SUBSEQUENT EVENT

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,
the 550 megawatt natural gas fired power plant, and the 200 million cubic foot per day cryogenic gas
processing plant. Through one of our wholly owned subsidiaries, 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 in
the Ares JV. At closing, in accordance with the terms of our credit agreement, we used $297 million of
the $747 million in net proceeds to pay off the then outstanding balance of our 2014 Revolving Credit
Facility.

In February 2018 and in connection with the formation of the Ares JV, 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.

NOTE 15 CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Our Credit Facilities and Second Lien Notes are guaranteed both fully and unconditionally and
jointly and severally by our material wholly owned subsidiaries (Guarantor Subsidiaries). Certain of our
subsidiaries are not required to guarantee our Credit Facilities and Second Lien Notes
(Non-Guarantor Subsidiaries) either because they hold assets that are less than 1% of our total
consolidated assets or because they are not deemed a “subsidiary” under the applicable financing
agreement. The following condensed consolidating balance sheets at December 31, 2017 and 2016,
condensed consolidating statements of operations and statements of cash flows for the years
ended December 31, 2017, 2016 and 2015 reflect the condensed consolidating financial information of
our parent company, CRC (Parent), our combined Guarantor Subsidiaries, our combined
Non-Guarantor Subsidiaries and the consolidation and elimination entries necessary to arrive at the
information for CRC on a consolidated basis.

The financial information may not necessarily be indicative of results of operations, cash flows or

financial position had the Guarantor Subsidiaries operated as independent entities.

121

Condensed Consolidating Balance Sheets

Combined
Guarantor
Subsidiaries

Combined
Non-
Guarantor
Subsidiaries Eliminations Consolidated

Parent

As of December 31, 2017
Total current assets
Total property, plant and equipment,

net

Investments in consolidated

subsidiaries

Other assets

TOTAL ASSETS

13 $

464 $

(in millions)
12 $

5,580

5,105
—

606
27

—
1

(6) $

483

—

5,696

(5,711)
—

$ 5,142 $

6,677 $

105 $

(5,717) $

Total current liabilities
Long-term debt - principal amount
Deferred gain and issuance costs,

net

Other long-term liabilities
Amounts due to (from) affiliates
Total equity

122
5,306

287
154
87
(814)

613
—

—
445
(87)
5,706

3
—

—
3
—
99

(6)
—

—
—
—
(5,711)

TOTAL LIABILITIES AND EQUITY $ 5,142 $

6,677 $

105 $

(5,717) $

6,207

As of December 31, 2016
Total current assets
Total property, plant and equipment,

net

Investments in consolidated

subsidiaries

Other assets

TOTAL ASSETS

7 $

418 $

— $

425

5,856

5,713
—

537
44

—
—

(6,250)
—

—

5,885

$ 5,745 $

6,855 $

4 $

(6,250) $

Total current liabilities
Long-term debt - principal amount
Deferred gain and issuance costs,

net

Other long-term liabilities
Amounts due to (from) affiliates
Total equity

221
5,168

397
132
384
(557)

505
—

—
487
(384)
6,247

—
—

—
1
—
3

—
—

—
—
—
(6,250)

TOTAL LIABILITIES AND EQUITY $ 5,745 $

6,855 $

4 $

(6,250) $

6,354

122

—
28

6,207

732
5,306

287
602
—
(720)

—
44

6,354

726
5,168

397
620
—
(557)

Condensed Consolidating Statements of Operations

For the year ended December 31, 2017
Total revenues and other
Total costs and other
Non-operating (loss) income
Income tax benefit

NET (LOSS) INCOME

Net income attributable to noncontrolling

interest

NET (LOSS) INCOME ATTRIBUTABLE

42 $

230
(349)
—

(537)

—

Combined
Guarantor
Subsidiaries

Parent

Combined
Non-Guarantor

Subsidiaries Eliminations Consolidated

(in millions)

1,947 $
1,700
24
—

271

—

17 $
13
—
—

(4)

— $
—
—
—

—

2,006
1,943
(325)
—

(262)

(4)

TO COMMON STOCK

$ (537) $

271 $

— $

(266)

For the year ended December 31, 2016
Total revenues and other
Total costs and other
Non-operating income
Income tax benefit

— $

205
475
78

1,543 $
1,644
32
—

NET (LOSS) INCOME ATTRIBUTABLE

TO COMMON STOCK

For the year ended December 31, 2015
Total revenues and other
Total costs and other
Non-operating (loss) income
Income tax benefit

NET (LOSS) INCOME ATTRIBUTABLE

348 $

(69) $

— $

302
(343)
1,922

2,400 $
7,236
9
—

TO COMMON STOCK

$ 1,277 $

(4,827) $

4 $
4
—
—

— $

3 $
7
—
—

(4) $

— $
—
—
—

— $

— $
—
—
—

1,547
1,853
507
78

279

2,403
7,545
(334)
1,922

— $

(3,554)

123

Condensed Consolidating Statements of Cash Flows

Combined
Guarantor
Subsidiaries

Parent

Combined
Non-Guarantor

Subsidiaries Eliminations Consolidated

(in millions)

For the year ended December 31, 2017
Net cash (used) provided by

operating activities

$ (481) $

Net cash used in investing activities
Net cash provided (used) by

financing activities

Increase (decrease) in cash and

cash equivalents

Cash and cash equivalents—

beginning of period

Cash and cash equivalents—end

(4)

492

—

718 $
(212)

(510)

(4)

11 $
(97)

— $
—

248
(313)

—

of period

7 $

8 $

5 $

— $

For the year ended December 31, 2016
Net cash (used) provided by

operating activities

$ (598) $

Net cash used in investing activities
Net cash provided (used) by

financing activities

Increase in cash and cash

equivalents

Cash and cash equivalents—

beginning of period

Cash and cash equivalents— end

(1)

599

—

727 $
(60)

(667)

—

1 $
—

— $
—

(1)

—

of period

$ — $

12 $

— $

For the year ended December 31, 2015
Net cash (used) provided by operating

activities

Net cash used in investing activities
Net cash provided (used) by

$ (1,676) $
(24)

2,086 $
(733)

(7) $
—

— $
—

financing activities

1,700

(1,355)

Decrease in cash and cash

equivalents

Cash and cash equivalents—

beginning of period

Cash and cash equivalents—end

—

(2)

—

of period

$ — $

12 $

— $

124

130
(61)

(69)

—

403
(757)

352

(2)

Quarterly Financial Data (Unaudited)

Quarter

First

Second

Third

Fourth

First

Second

Third

Fourth

2017

2016

Revenues(a)

Operating income

(loss)

Net income (loss)
attributable to
common stock(b) $

590 $

516 $

(in millions, except per share amounts)
445 $

455 $

322 $

317 $

456 $

452

111 $

39 $

(47) $

(40) $

(143) $

(141) $

(19) $

(3)

53 $

(48) $

(133) $ (138) $

(50) $

(140) $

546 $

(77)

Earnings (loss)
per share
attributable to
common stock:
Basic

$ 1.23 $ (1.13) $ (3.11) $ 3.23 $ (1.30) $ (3.51) $ 13.04 $ (1.83)

Diluted

$ 1.22 $ (1.13) $ (3.11) $ 3.23 $ (1.30) $ (3.51) $ 13.04 $ (1.83)

(a) Revenues include net derivative gains (losses).
(b) Net income (loss) attributable to common stock included the following unusual, out-of-period and infrequent items:

Non-cash derivative (gains) losses,
excluding noncontrolling interest

Early retirement, severance and

2017

2016

First Second Third Fourth First Second Third Fourth
(in millions)

$(75)

$(35)

$72

$116

$ 81

$137

$ 25

$ 40

other costs

$ 3

$ —

$ 1

$ 14

$ 4

$ 1

Net gains on early extinguishment of

debt

Gains on asset divestitures
Other
Deferred debt issuance costs

write-off

Reversal of valuation allowance for

$ (4)
$(21)
$ 1

$ —
$ —
$ 5

$ — $ — $(89)
$ (44)
$ — $ — $ — $ (31)
$ 2
$ 8

$ 7

$(660)
$(12)
$ — $ 1
$(27)
$

$ — $ —

$ — $ — $ — $ — $ 12

$ —

deferred tax assets

$ — $ —

$ — $ — $ 63

$ — $ — $ —

125

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), natural gas liquids (NGLs) and
natural gas and changes in such quantities. Estimated reserves include our economic interests under
arrangements similar to production-sharing contracts (PSCs) relating to the Wilmington field in Long
Beach. All of our proved reserves are located within the state of California. See Item 2—Properties—
Our Reserves for a discussion of the changes in proved reserves.

PROVED DEVELOPED AND UNDEVELOPED RESERVES

Oil
(MMBbl)(a)

NGLs
(MMBbl)

Natural Gas
(Bcf)

Total
(MMBoe)(b)

Balance at December 31, 2014

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

Balance at December 31, 2015

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

Balance at December 31, 2016

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

Balance at December 31, 2017

PROVED DEVELOPED RESERVES

December 31, 2014

December 31, 2015

December 31, 2016

December 31, 2017(c)

PROVED UNDEVELOPED RESERVES

December 31, 2014

December 31, 2015

December 31, 2016

December 31, 2017

551
(80)
3
25
4
—
(37)

466
(40)
3
14
—
(1)
(33)

409
47
—
24
—
(8)
(30)

442

387

338

279

304

164

128

130

138

85
(23)
—
2
1
—
(6)

59
—
—
2
—
—
(6)

55
7
—
2
—
—
(6)

790
(33)
—
34
8
—
(84)

715
(42)
—
25
—
—
(72)

626
104
—
45
—
(3)
(66)

706

607

575

500

543

183

140

126

163

768
(108)
3
33
6
—
(58)

644
(47)
3
20
—
(1)
(51)

568
71
—
34
—
(8)
(47)

618

552

481

406

440

216

163

162

178

(a)

Includes proved reserves related to economic arrangements similar to PSCs of 108 MMBbl, 85 MMBbl, 103 MMBbl and 116
MMBbl at December 31, 2017, 2016, 2015 and 2014, respectively.

(b) Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas

and one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence.

natural gas reserves and, overall, 19% of total proved developed reserves are non-producing. A majority of our non-producing
reserves relate to steamfloods and waterfloods where full peak production response has not yet occurred due to the nature of
such projects.

126

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

2016

(in millions)
$ 19,664 $ 19,325
1,111

1,111

20,775
(15,391)

20,436
(14,891)

$ 5,384 $ 5,545

(a)
(b)

Includes acquisition costs, development costs and asset retirement obligations.
Includes accumulated valuation allowance for total unproved properties of $819 million at December 31, 2017, 2016 and 2015.

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,
2016
(in millions)

2015

2017

Property acquisition costs

Proved properties
Unproved properties

Exploration costs
Development costs(a)

Costs incurred

$ — $ — $

—
25
357

—
21
102

382 $

123 $

77
65
43
290

475

(a) Total development costs include a $5 million decrease, a $49 million increase and a $62 million decrease in asset retirement

obligations in 2017, 2016 and 2015, respectively.

127

RESULTS OF OPERATIONS

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

overhead, were as follows:

For the years ended December 31,
2016

2017

2015

($/Boe)(a)

(millions)
($/Boe)(a)
$ 1,931 $ 41.09 $ 1,700 $ 33.17 $ 2,222 $ 38.07
16.30

($/Boe)(a)

(millions)

15.61

18.64

800

951

876

Revenues(b)
Production costs(c)
Adjusted general and

administrative expenses(d)

Adjusted other operating

expenses(e)

Depreciation, depletion and

amortization

Taxes other than on income
Asset impairments(f)
Exploration expenses

510
110
—
22

0.72

0.56

10.85
2.34
—
0.47

527
121
—
23

158
(64)

0.72

0.67

10.28
2.36
—
0.45

976
156
4,852
36

1.00

0.36

16.72
2.67
83.14
0.62

3.08
(1.25)

(4,828)
1,968

(82.74)
33.72

Pretax income (loss)
Income tax (expense) benefit(g)

353
(115)

7.51
(2.45)

Results of operations

238 $

5.06 $

94 $

1.83 $ (2,860) $ (49.02)

(a) Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas

and one Bbl of oil.

(b) Revenues are net of royalty payments.
(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 $17.48, $14.69 and $15.58 for 2017, 2016 and 2015, respectively.

(d) Amounts exclude unusual and infrequent charges related to severance and early retirement costs associated with field

personnel totaling $5 million ($0.10 per Boe), $6 million ($0.12 per Boe) and $18 million ($0.31 per Boe) for 2017, 2016 and
2015, respectively.

(e) For 2017, the amount excludes 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 amount excludes net unusual and infrequent gains of $18 million ($0.35 per Boe) that include refunds
partially offset by plant turnaround charges and other items. For 2015, the amount excludes charges related to the write-down
of certain assets and rig termination charges of $82 million ($1.42 per Boe).

(f) At year-end 2015, we recorded pre-tax asset impairment charges of $4.9 billion on certain proved and unproved properties in

the San Joaquin, Los Angeles, Ventura and Sacramento basins
Income taxes are calculated on the basis of a stand-alone tax filing entity. The 2017 amount reflects the benefit of tax credits.

(g)

128

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, 2017, 2016 and
2015, respectively. The realized prices used to calculate future cash flows vary by producing area and
market conditions. Future operating and capital costs were determined using the current cost
environment applied to expectations of future operating and development activities. Future income tax
expense was computed by applying, generally, year-end statutory tax rates (adjusted for permanent
differences and tax credits) to the estimated net future pre-tax cash flows, after allowing for the
deductions for intangible drilling costs and tax DD&A. The cash flows were discounted using a 10%
discount factor. The calculations assumed the continuation of existing economic, operating and
contractual conditions at December 31, 2017, 2016 and 2015. 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

2017

At December 31,
2016
(in millions)
$ 26,685 $ 18,831 $ 26,477

2015

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

7,264
(3,499)

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

5,023
(2,356)

(13,458)
(3,502)
(1,858)

7,659
(3,635)

Standardized measure of discounted future net cash flows

$ 3,765 $ 2,667 $ 4,024

(a)
(b)

Includes general and administrative expenses and taxes other than on income.
Includes asset retirement costs.

129

Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved
Reserves Quantities

For the years ended
December 31,
2016
(in millions)
$ 2,667 $ 4,024 $ 10,828

2015

2017

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

1,098

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

(1,038)
(12,362)
394
792
292
(872)
1,474
4,228
45
243

(1,357)

(6,804)

$ 3,765 $ 2,667 $ 4,024

Beginning of year

Sales of oil and natural gas, net of production and other operating

costs

Changes in price, net of production and other operating costs
Previously estimated development costs incurred
Change in estimated future development costs
Extensions, discoveries and improved recovery, net of costs
Revisions of previous quantity estimates(a)
Accretion of discount
Net change in income taxes
Purchases and sales of reserves in place
Changes in production rates and other

Net change

End of year

(a)

Includes revisions related to performance and price changes.

130

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

(in millions)

2017

Balance at
Beginning
of Period

Charged
(Credited) to
Costs and
Expenses

Charged
to Other
Accounts Deductions(a)

Balance at End
of Period

Deferred tax valuation

allowance

Other asset valuation allowance $

Environmental reserves

2016

Deferred tax valuation

allowance

Other asset valuation allowance $

Environmental reserves

2015

Deferred tax valuation

allowance(b)

Other asset valuation allowance $

Environmental reserves

780

382

(78) $

(12) $

398

(12) $

— $

294

— $

(4) $

— $

(1) $

— $

(1) $

706

780

382

(a) Consists of payments.
(b) Our 2015 deferred tax liabilities were net of $88 million, which represented the federal benefit for the state-related

portion of the deferred tax valuation allowance.

131

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.

We have assessed the effectiveness of our internal control system as of December 31, 2017
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, 2017, 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, 2017, 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.

132

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) identified in management’s evaluation pursuant to Rules
13a-15(d) or 15d-15(d) of the Exchange Act during our fourth fiscal quarter that 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.

PART III

ITEM 10 DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated by reference to our Proxy Statement for the

2018 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission (SEC)
within 120 days of the fiscal year ended December 31, 2017 (Proxy Statement) where it will appear in
the (i) Corporate Governance section under General Overview and Our Board of Directors, (ii) Board
Leadership Structure and Committees—Committees of the Board, (iii) Stock Ownership Information—
Section 16(a) Beneficial Ownership Reporting Compliance and (iv) Stockholder Proposals and Other
Company Information section under Stockholder Proposals and Director Nominations. 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 to our Proxy Statement where it

appears in the Compensation Discussion and Analysis and Compensation Committee Interlocks and
Insider Participation sections. 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 to our Proxy Statement where it

appears under the Stock Ownership Information—Security Ownership of Directors, Management and
Certain Beneficial Holders section. 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.

133

ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR

INDEPENDENCE

The information required by this item is incorporated by reference to our Proxy Statement where it
appears in the Certain Relationships and Related Transactions section (except under the subheading
Policies and Procedures) and Director Independence Determinations section.

ITEM 14 PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated by reference to our Proxy Statement where it

appears in the Proposals Requiring Your Vote—Proposal 2: Ratification of the Appointment of the
Independent Registered Public Accounting Firm section.

134

PART IV

ITEM 15 EXHIBITS

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

(cid:129)

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

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

(cid:129) may apply standards of materiality in a way that is different from the way investors may view

materiality; and

(cid:129) were made only as of the date of the applicable agreement or such other date or dates as

may be specified in the agreement and are subject to more recent developments.

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

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

listed.

(a) (3). Exhibits

Exhibit
Number

Exhibit Description

2.1

3.1

3.2

4.1

4.2

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).

135

Exhibit
Number

4.3

4.4

4.5

4.6

4.7

4.8

4.9

4.10

4.11

4.12

10.1

Exhibit Description

Guarantor Supplemental Indenture dated as of March 5, 2015, among California
Resources Corporation, certain guarantors named therein and Wells Fargo Bank,
National Association (filed as Exhibit 4.2 to Registrant’s Registration Statement on Form
S-4 filed March 12, 2015 and incorporated herein by reference).

Guarantor Supplemental Indenture dated as of March 4, 2016, among California
Resources Corporation, certain guarantors named therein and The Bank of New York
Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to Registrant’s Quarterly
Report on Form 10-Q filed August 4, 2016 and incorporated herein by reference).

Guarantor Supplement Indenture dated as of March 4, 2016, among California Resources
Corporation, certain guarantors named therein and The Bank of New York Mellon Trust
Company, N.A., as trustee (filed as Exhibit 4.2 to Registrant’s Quarterly Report on Form
10-Q filed August 4, 2016 and incorporated herein by reference).

Guarantor Supplemental Indenture No. 2, dated as of April 29, 2016, among California
Resources Corporation, certain guarantors named therein and Wilmington Trust, National
Association, as trustee (filed as Exhibit 10.4 to Registrant’s Quarterly Report on Form
10-Q filed August 4, 2016 and incorporated herein by reference).

Assumption Agreement dated as of March 6, 2015, among CRC Construction Services,
LLC and JP Morgan Chase Bank, N.A., as Administrative Agent for lenders (filed as
Exhibit 10.31 to Registrant’s Registration Statement on Form S-4 filed March 12, 2015
and incorporated herein by reference).

Registration Rights Agreement, dated October 1, 2014, by and among California
Resources Corporation, the Guarantors and the Initial Purchasers (filed as Exhibit 4.3 to
Amendment No. 4 to the Registrant’s Information Statement on Form 10 filed October 8,
2014 and incorporated herein by reference).

Form of 5% Senior Note due 2020 (included in Exhibit 4.2 to Amendment No. 4 to the
Registrant’s Information Statement on Form 10 filed October 8, 2014 and incorporated
herein by reference).
Form of 5 1⁄ 2% Senior Note due 2021 (included in Exhibit 4.2 to Amendment No. 4 to the
Registrant’s Information Statement on Form 10 filed October 8, 2014 and incorporated
herein by reference).

Form of 6% Senior Note due 2024 (included in Exhibit 4.2 to Amendment No. 4 to the
Registrant’s Information Statement on Form 10 filed October 8, 2014 and incorporated
herein by reference).

Form of 8% Senior Secured Second Lien Note due 2022 (included in Exhibit 4.1 to
Registrant’s Current Report on Form 8-K filed December 18, 2015 and incorporated
herein by reference).

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).

136

Exhibit
Number

10.2

10.3

10.4

10.5

10.6

10.7

10.8

10.9

Exhibit Description

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).

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
Registration’s Current Report on Form 8-K filed August 17, 2016 and incorporated herein
by reference).

137

Exhibit
Number

10.10

10.11

10.12

10.13

10.14

10.15

10.16

10.17

10.18

10.19

Exhibit Description

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).

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).

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).

138

Exhibit
Number

10.20

10.21

10.22

10.23

10.24

10.25

10.26

10.27

10.28

10.29

10.30

10.31

Exhibit Description

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).

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).

139

Exhibit
Number

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

10.45

Exhibit Description

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).

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).

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).

140

Exhibit
Number

10.46

10.47

10.48

10.49

12*

21*

23.1*

23.2*

31.1*

31.2*

32.1*

99.1*

Exhibit Description

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).

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).

Computation of Ratio of Earnings to Fixed Charges.

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, 2017.

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.

141

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 26, 2018

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/ Ronald L. Havner

Ronald L. Havner

/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/ Robert V. Sinnott

Robert V. Sinnott

Title

Date

President,
Chief Executive Officer and Director

February 26, 2018

Senior Executive Vice President and
Chief Financial Officer

February 26, 2018

Executive Vice President—Finance and
Principal Accounting Officer

February 26, 2018

Chairman of the Board

February 26, 2018

Director

142

February 26, 2018

EXHIBIT INDEX

EXHIBITS

23.1

23.2

31.1

31.2

32.1

99.1

Computation of Ratio of Earnings to Fixed Charges.

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, 2017.

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.

143

Annual Meeting

California Resources Corporation’s annual meeting of

stockholders will be held at 11:00 a.m. on May 9, 2018 at

the Bakersfield Marriott at the Convention Center located

Officers

Todd A. Stevens

President,

Board Of Directors

William E. Albrecht

Chairman of the Board, Former

Chief Executive Officer

Vice President, Occidental

and Director

Petroleum Corporation

at 801 Truxtun Avenue, Bakersfield, California 93301.

Marshall D. Smith

Justin A. Gannon

Investor Relations Contact

Company financial information, public disclosures and

other information are available through our website

Senior Executive Vice President

Former Regional Managing

and Chief Financial Officer

Partner, Grant Thornton LLP

Shawn M. Kerns

Ronald L. Havner, Jr.

Executive Vice President,

Chairman of the Board

Operations and Engineering

and Chief Executive Officer,

Public Storage

at www.crc.com. We will promptly deliver free of

Francisco Leon

charge, upon request, an annual report on Form 10-K

Executive Vice President,

Harold M. Korell

Corporate Development and

Lead Independent Director,

to any stockholder requesting a copy. Requests should

Strategic Planning

be directed to our Investor Relations team at our

Roy Pineci

Former Chairman of the Board,

Southwestern Energy Company

American Stock Transfer and Trust Company, LLC

Public Affairs

corporate headquarters address or sent to ir@crc.com.

Auditors

KPMG LLP, Los Angeles, California

Transfer Agent & Registrar

Shareholder Services

6201 15th Avenue, Brooklyn, New York 11219

(866) 659-2647

crc@amstock.com

www.amstock.com

Stock Exchange Listing

California Resources Corporation’s common stock

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

The symbol is CRC.

Executive Vice President,

Harry T. McMahon

Finance

Former Executive Vice

Chairman, Bank of America

Michael L. Preston

Merrill Lynch

Executive Vice President,

General Counsel and

Corporate Secretary

Charles F. Weiss

Executive Vice President,

Richard W. Moncrief

Chairman of the Board and

Chief Executive Officer,

Moncrief Oil International

Avedick B. Poladian

Former Executive Vice

Darren Williams

President and Chief Operating

Executive Vice President,

Officer, Lowe Enterprises

Operations and Geoscience

Anita M. Powers

Former Executive Vice

President of Worldwide

Exploration, Occidental Oil

and Gas Corporation and

Vice President, Occidental

Petroleum Corporation

Robert V. Sinnott

Co-Chairman,

Kayne Anderson Capital

Todd A. Stevens

President, Chief Executive

Officer and Director, California

Resources Corporation

This Annual Report is printed on Forest Stewardship
Council®-certified paper that contains wood from
well-managed forests and other responsible sources.

UFCW®

888

2017C

crc.com