California Resources Annual Report 2016

← All annual reports

FY2016 Annual Report · California Resources

Loading PDF…

CALIFORNIA
RESOURCES
CORPORATION
2016 ANNUAL REPORT

FINANCIAL AND OPERA
HIGHLIGHTS

TIONAL

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

Financial Highlights

EPS – Basic and Diluted(b)(c)
Adjusted EPS – Basic and Diluted(a)(b)(c)

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

Revenues
Income (Loss) Before Income Taxes
Net Income (Loss)
Adjusted Net (Loss) Income(a)

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

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

6
1
0
2

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

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

Acreage (in thousands):
Net Developed
Net Undeveloped
Total

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

Organic Reserve Replacement(a)
PV-10(a)

Operational Highlights

Closing Share Price(c)

2016

$ 1,547
201
$
279
$
)
(317
$

$
$

$
$
$

6.76
)
(7.85

130
(75
)
)
(69

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

40.4
42.5

2016

91
16
197
140

$ 42.01
$ 39.72
$ 22.39
2.28
$

409
55
626
568

2015

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

$ (92.79
)
)
(8.12
$

$
$
$

403
)
(401
352

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

38.3
38.8

2014

$ 4,173
$ (2,421
$ (1,434
650
$

)
)

$ (37.54
$ 16.73

)

$ 2,371
$ (2,089
(45
$

)
)

$ 12,429
$ 6,360
$
(68
$ 2,611

)

38.2
38.6

2015

2014

104
18
229
160

$ 49.19
$ 47.15
$ 19.62
2.66
$

466
59
715
644

99
19
246
159

$ 92.30
$ 92.30
$ 47.84
4.39
$

551
85
790
768

%
71
$2.8 billion

%
140
$5.1 billion

%
203
$16.1 billion

717
1,614
2,331

736
1,653
2,389

716
1,691
2,407

$ 21.29

$ 23.30

$ 55.10

(a) For discussion of or reconciliation to the most closely-related GAAP measure, see “Properties – Our Reserves and Production Information” in our Form 10-K for 2014, 2015 and 2016, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Financial and Operating
Results” in our Form 10-K for 2016. (b) On November 30, 2014, Occidental Petroleum Corporation distributed 38.1 million shares (on a post-split basis) of our common stock to its stockholders and retained 18.5% of such shares. Occidental distributed the retained shares to its stockholders in March 2016.
For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed the outstanding shares as of November 30, 2014 were outstanding for the prior period. Adjusted EPS - Basic and Diluted for each year is Adjusted Net (Loss) Income divided
by the weighted average shares outstanding for each respective year. (c) Share and per-share amounts are presented on post-split basis.

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 constraints, natural disasters, labor
difﬁculties, cyber-attacks, and other catastrophic events • other risk factors as discussed in our Annual Report on Form 10-K. Forward-looking statements speak only as of the date on which made and we undertake no obligation to correct or update such statements, except as required by applicable law.

A MESSAGE TO OUR SHAREHOLDERS

Dear Shareholder,

We believe California Resources Corporation (CRC) is at an inflection point, very well positioned

to move from defense to offense as crude markets normalize. 2016 marked year two of a supply-driven
commodity price decline during which CRC continued focusing on delivering value. Throughout this
challenging period, we made significant progress on our vision of providing Californians with needed
ample, affordable and reliable energy produced exclusively in California — while we diligently focused
on shareholder value and setting the stage for meaningful growth. In short, we did what we said we
would do on items in our control, and as a result we believe we enter 2017 stronger and well positioned
to create value and grow.

Our actions were rooted in the strategic logic of our spin-off in late 2014: creating a company with

a singular focus on California’s world-class oil and natural gas resources. We launched CRC with a
value-creation purpose and a commitment to live within our means. To implement these principles
across our leading acreage position in California, we have created an exceptionally flexible business
model. We have replaced the culture of our multinational former parent to become an increasingly
agile, nimble independent. Our energized team is focused on creating value and our entrepreneurial
spirit is already generating fresh ideas as well as new and expanded opportunities.

During the first two months of 2016, crude oil prices sank to their lowest point of the downturn. In

view of the challenging pricing environment and the debt we inherited from the spin-off, our primary
goal for the year was to preserve value and strengthen our balance sheet by taking advantage of the
liability management opportunities afforded us. We made significant progress, reducing our debt by
nearly $1.5 billion since the post-spin peak. We also executed on three key operational priorities:
protecting our base, defending our margins and building actionable inventory, all with an unwavering
dedication to safe operations and protecting California’s unique environment. I am proud of the
commitment and execution of each of our team members as they enhanced CRC’s resource base and
ability to create shareholder value.

The 2016 deleveraging efforts began with open-market purchases of our subordinated bonds in

February. We took advantage of several dislocations during the year between the debt and equity
markets, including favorable equity-for-debt swaps and a series of transactions that allowed CRC to
buy back unsecured bonds at a discount. We worked closely with our bank group to gain the
necessary flexibility to execute these transactions. Our bank group has shown a deep understanding of
our assets and operational decision-making. Despite lower prices and activity, we believe CRC stands
apart from its peers in its generation of free cash flow during the downturn, some of which we utilized
to reduce debt. This is an especially important accomplishment given the depth of this commodity cycle
trough which had not been seen in 30 years. We believe our cumulative reduction of debt by
$1.5 billion, including from operating cash flow, and our disciplined approach to potential joint ventures
will benefit shareholders for years to come.

We are ultimately targeting a leverage ratio between 2x - 3x on a mid-cycle basis. We believe
investing in our rich inventory of projects to delever organically, while maximizing the value of our
capital investments, provides the fastest route towards this target ratio. However, we will evaluate all
opportunities to accelerate this deleveraging and act on them as long as they are accretive to
shareholder value.

While strengthening our balance sheet, we also set a stronger foundation for growth by applying

our value creation index, or VCI metric, to guide project selection and development decisions. This
metric measures the value of discounted cash flows generated over the life of a project against the
discounted investment required. In conjunction with our principle of living within cash flow, this formula

serves as the touchstone for our capital allocation decisions. Allocation of resources, whether financial
or human capital, is one of the most important responsibilities of our management team. Applying a 1.3
VCI hurdle for new projects positions us for at least a 30 percent return over the life of a project, even
after accounting for a 10 percent cost of capital — and sets a threshold against which projects eligible
for capital are vetted.

We apply this rigorous discipline to our extensive resource base, which is complemented by our

integrated infrastructure that is rarely found among independents. This integrated business model
amplifies the power of our VCI metric. California is fortunate to have five of the 12 billion-plus barrel
fields that have been discovered in the lower 48 states. As the largest private mineral holder in the
state with over 2.3 million net mineral acres, CRC operates in four of these billion-plus barrel fields.
Unlike other basins in the United States, California has not been fully explored or developed, and has
great untapped potential. While major oil companies invested actively in California into the 1980s, new
development halted as ownership transferred to fewer players and the majors turned their attention to
international opportunities. With an estimate of over 40 billion barrels of original oil in place1 in the
Golden State, we believe that we can more than double CRC’s resources from our existing portfolio by
applying modern technology and the proper focus. Our geological and engineering teams have had
encouraging success uncovering significant opportunities for development and we believe our talented
workforce and value-focused approach will continue to drive shareholder value.

Notably, CRC has a distinctly low-decline reserves base characterized by multiple drive

mechanisms. We estimated that CRC’s base production decline rate would be between 10-15 percent
per year, depending on downtime. From the fourth quarter of 2015, we witnessed a decline of just
10 percent, excluding the impact of Production Sharing Contracts (PSC) in our Wilmington field, or
under 13 percent with the PSC impact. This modest decline contrasts quite favorably with decline rates
of 25-35 percent that are more typical of peer producers in other markets. It is even more remarkable
in light of the limited capital of $75 million we invested in 2016, the majority of which was directed to
mechanical integrity and ensuring safe operations. We directed only $31 million toward drilling and
development projects. By way of comparison, we invested $401 million in 2015. Our teams did an
excellent job of safely reducing our downtime through proactive maintenance and detailed well
surveillance to protect our base production.

Today, CRC has over 8,800 producing wells and an additional 3,000 injectors and monitoring wells

which we manage to maximize our production. We have a state-of-the-art consolidated control facility
at our Elk Hills field which monitors each well stroke of the 5,800 wells in the area. This advanced
surveillance system has minimized downtime, aided preventative maintenance, enhanced safety and
environmental performance and reduced costs. Our teams have decreased operating costs
significantly at Elk Hills and our adjacent fields to about $10 per barrel, which yields favorable field-
level margins well below the current Brent oil price. Our company applied a fresh, margin-driven
perspective post-spin to benefit from California’s Brent-correlated pricing on our crude sales and to
sustain our cash margins during the downturn.

Another highlight of 2016 was the increase in our actionable inventory. Our teams challenged
geological assumptions, improved mapping, reduced costs and collaboratively altered designs, which
resulted in a doubling of our drillable inventory that meets our 1.3 VCI benchmark at $55 Brent. We
have also materially increased identified resources above that price level. This exercise has built real
value for CRC, attracting joint venture partner interest and registering significant increases in the 3P1
(Proved, Probable and Possible) value of our reserves. Currently, we estimate the mid-cycle value of
our 3P Reserves at $12 billion, almost double our current enterprise value.

With stabilizing prices, CRC’s disciplined capital allocation and our flexible business model, we
believe that CRC is at a critical inflection point as we enter 2017. Looking forward, we plan to increase
our capital investments in the business for the first time since the spin. This follows two years of taking
the largest percentage budget cuts in the sector. Importantly for CRC shareholders, our high degree of
operational control and our resilient, low-decline assets allowed us to curtail drilling and development

capital, and even suspend it entirely for the first half of 2016, without a material decrease in our
underlying reserves base. Our bank group also recognized the low capital intensity and low decline
rate of our assets as one of the attributes that sets CRC apart from many of our peers.

With our current investment plan, and additional available capital from our recent $250 million
Joint Venture with Benefit Street Partners, we expect our crude production to begin increasing in the
second half of 2017. As we have since the spin-off, we expect once again to meet our tenet of living
within cash flow in 2017. We will monitor crude oil prices and utilize our VCI metric to direct capital to
our best opportunities, whether back in the ground or applied to further debt reduction.

To prepare for this anticipated growth, we have built alliances with key stakeholders, including
organized labor and agriculture, who recognize the importance of affordable, reliable and local energy
production to sustain California’s economy, society and environment for the coming decades. We are
proud to work with the California Building and Construction Trades to champion good-paying
construction and industrial jobs in California’s oil and natural gas fields that provide a path to the
middle class for working families across the state. To support California’s farmers and ranchers, CRC
supplied nearly four billion gallons of treated water to agricultural water districts in 2016, and we
continue to explore projects to help meet the Central Valley’s needs. In addition, CRC’s operations
again delivered exceptional safety and environmental performance, receiving recognition from the
National Safety Council and the Wildlife Habitat Council. This is validation of our commitment to serve
as the operator of choice in California.

The steepest and longest price downturn in a generation set the backdrop for our strategy and

actions in 2016. Importantly, we made the hard decisions and took disciplined measures to preserve
and create value that will only strengthen CRC as we advance through 2017. We determined the best
value decision was to preserve capital for a more opportune pricing environment. We recognized
CRC’s operational leverage to crude oil and safeguarded our exposure, while positioning CRC for
future growth. Our entrepreneurial team, world-class assets and flexible business model were all
critical factors as we continued to strengthen CRC’s balance sheet in 2016 — without selling any
significant assets at the bottom of the cycle or significantly diluting shareholders.

Your management team, the Board and our employees are fellow shareholders, and we took
numerous steps in 2016 to increase shareholder value. We believe we have a unique investment
proposition at CRC. We are primed to create value and drive smart, sustainable growth that will benefit
our shareholders, our partners and all Californians.

Regards,

Todd Stevens
President and CEO

In this letter, we use the term “oil in place” and provide internally generated estimates for aggregated proved, probable and
possible reserves as of December 31, 2016 to describe estimates of potentially recoverable hydrocarbons in the applicable
reservoir. For full cautionary statements, refer to slide 3 of our 2017 Goldman Sachs slides on CRC’s website in the Investor
Relations section at http://www.crc.com/images/documents/IR/Financials/160105_Goldman_Sachs_Presentation.pdf

[THIS PAGE INTENTIONALLY LEFT BLANK]

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K
Í ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

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

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

Large Accelerated Filer ‘ Accelerated Filer
Non-Accelerated Filer

Í
‘ Smaller Reporting Company ‘

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 $496 million, computed by reference to the closing price on the New York Stock Exchange composite
tape of $12.20 per share of Common Stock on June 30, 2016. 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, 2017, there were 42,542,637 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 2017 Annual Meeting of Stockholders, are incorporated by reference into Part III of
this Form 10-K.

LIST OF OPERATING SUBSIDIARIES

The following is a list of our subsidiaries at December 31, 2016 other than certain subsidiaries that

did not in the aggregate constitute a significant subsidiary.

Name

Jurisdiction of Formation

California Heavy Oil, Inc.
California Resources Coles Levee, LLC
California Resources Coles Levee, L.P.
California Resources Elk Hills, LLC
California Resources Long Beach, Inc.
California Resources Petroleum Corporation
California Resources Production Corporation
California Resources Tidelands, Inc.
California Resources Wilmington, LLC
CRC Construction Services, LLC
CRC Marketing, Inc.
CRC Services, LLC
Elk Hills Power, LLC
Socal Holding, LLC
Southern San Joaquin Production, Inc.
Thums Long Beach Company
Tidelands Oil Production Company

Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Texas

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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Business Strategy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Key Characteristics of our Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Portfolio Management and 2017 Capital Budget
. . . . . . . . . . . . . . . . . . . . . . . . . .
Reserves and Production Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marketing Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulation of the Oil and Natural Gas Industry . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UNRESOLVED STAFF COMMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Our Reserves and Production Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Determination of Identified Drilling Locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Production, Price and Cost History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Productive Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Participation in Exploratory and Development Wells Being Drilled . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
The Separation and Spin-off
Basis of Presentation and Certain Factors Affecting Comparability . . . . . . . . . . .
Business Environment and Industry Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Seasonality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial and Operating Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheet Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statement of Operations Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash Flow Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisitions and Divestitures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 Capital Program and 2017 Capital Budget
. . . . . . . . . . . . . . . . . . . . . . . . . .
Off-Balance-Sheet Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lawsuits, Claims, Contingencies and Commitments . . . . . . . . . . . . . . . . . . . . . . .
Critical Accounting Policies and Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Significant Accounting and Disclosure Changes . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

5
5
5
8
10
12
13
13
15
19
20
20
30
31
31
36
42
45
49
49
50
51
52
53
53
54

55
58

59
59
59
60
62
62
63
64
67
68
72
78
80
80
81
82
83
86

Item 7A

Item 8

Item 9

Item 9A
Item 9B

Part III

Item 10
Item 11
Item 12

Item 13

Item 14

Part IV

87
88
90

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK . . .
FORWARD-LOOKING STATEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . . . . . . . . . . . . . .
Report of Independent Registered Public Accounting Firm on Consolidated and
Combined Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Report of Independent Registered Public Accounting Firm on Internal Control
Over Financial Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
91
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
92
Consolidated and Combined Statements of Operations . . . . . . . . . . . . . . . . . . . . .
93
Consolidated and Combined Statements of Comprehensive Income . . . . . . . . . .
94
Consolidated and Combined Statements of Equity . . . . . . . . . . . . . . . . . . . . . . . . .
95
Consolidated and Combined Statements of Cash Flows . . . . . . . . . . . . . . . . . . . .
96
Notes to Consolidated and Combined Financial Statements . . . . . . . . . . . . . . . . .
97
Quarterly Financial Data (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 128
Supplemental Oil and Gas Information (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . 129
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS . . . . . . . . . . . . . . . . 140
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141
CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141
OTHER INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE . . . . . 142
EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . 142
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143
PRINCIPAL ACCOUNTANT FEES AND SERVICES . . . . . . . . . . . . . . . . . . . . . . . . . 143

Item 15

EXHIBITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

PART I

Item 1

BUSINESS

In this report, 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 assumed in connection with the spin-off from Occidental on November 30,
2014 (the Spin-off), and (3) all references to ‘‘Occidental’’ refer to Occidental Petroleum Corporation,
our former parent, and its subsidiaries.

General

We are an independent oil and natural gas exploration and production company operating
properties within the state of California. 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. As of November 30, 2014, all material existing assets, operations and liabilities of
Occidental’s California business were consolidated under us. On November 30, 2014, Occidental
distributed shares of our common stock on a pro rata basis to Occidental stockholders and we became
an independent, publicly traded company (the Spin-off). Occidental initially retained approximately
18.5% of our outstanding shares of common stock, which it distributed to Occidental stockholders on
March 24, 2016. 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.

Business Operations

Our Business

Our business is focused on conventional and unconventional assets in 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 acres
spanning the state’s four major oil and gas basins. We produced approximately 140 thousand barrels
of oil equivalent per day (MBoe/d) for the year ended December 31, 2016. As of December 31, 2016,
we had net proved reserves of 568 million barrels of oil equivalent (MMBoe), of which approximately
71% was categorized as proved developed reserves. Oil represented 72% of our proved reserves.

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 which are high return projects throughout the price cycle. Our acreage
position contains numerous development and growth opportunities due to its varied geologic
characteristics and multiple stacked pay reservoirs which, in many cases, are 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 with approximately 70% of our proved reserves associated with conventional
opportunities. Conventional reservoirs are capable of natural flow using primary, steamflood and
waterflood recovery methods. We also have a significant portfolio of unconventional growth
opportunities in lower permeability reservoirs that typically utilize established well stimulation
techniques. We have approximately 3,400 net identified drilling locations targeting unconventional
reservoirs primarily in the San Joaquin basin. Prior to the severe price declines, we were focused on
higher-value unconventional production from seven discrete stacked pay horizons within the Monterey
formation, primarily within the upper Monterey. 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.

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

activities (as of December 31, 2016, acres and dollars in millions, unless otherwise stated):

Acreage

Gross

Net

1.8
<0.1
0.3
0.6

2.8

1.5
<0.1
0.3
0.5

2.3

Average
Net
Acreage
Held in Fee
(%)

Producing
Wells,
gross

Net
Revenue
Interest
(%)

64%
52%
72%
37%

58%

6,246
1,315
567
709

8,837

79%
78%
84%
76%

79%

Identified Drilling
Locations(1)

Gross

Net

23,900
2,150
2,950
1,900

16,650
2,050
2,750
1,400

30,900

22,850

San Joaquin Basin
Los Angeles Basin(2)
Ventura Basin
Sacramento Basin

Total

(1) Our total identified drilling locations exclude approximately 6,400 gross (5,300 net) prospective resource drilling

locations. Our total identified drilling locations include approximately 2,350 gross (2,150 net) locations associated with
proved undeveloped reserves as of December 31, 2016. Our total identified drilling locations also include approximately
2,300 gross (2,100 net) injection well locations. Please see “Item 2—Properties—Our Reserves and Production
Information” for more information regarding the processes and criteria through which we identified our drilling locations.

(2) We currently hold approximately 42,600 gross (34,400 net) acres in the Los Angeles basin. Our Los Angeles basin

operations are concentrated with pad drilling.

We develop our capital investment programs 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 portfolio of opportunities. 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 investment hurdle
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
portfolio of drilling opportunities.

Over the past decade, we have also built a 3D seismic library that covers approximately 4,800

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.

Business Environment

Much of the global exploration and production industry has been challenged at recent price levels,
putting pressure on the industry’s ability to generate positive cash flow and access capital. The decline
in average oil prices that began in the last half of 2014 continued into the first quarter of 2016. While

global oil prices improved modestly through the end of 2016 and began to trade in a narrower range,
daily average prices were still lower for the full year of 2016 compared to 2015.

Consistent with our strategy to invest within our cash flow, we initially budgeted $50 million for our

2016 capital program, primarily to maintain the mechanical integrity of our facilities and systems and
operate them safely. In the first half of the year, we further reduced the pace of our capital program to
below our initial budget. In response to commodity price improvements in the second half of the year,
we gradually increased our capital investment to $75 million for the full year. Our slowdown of drilling
activity from late 2015 through the first half of 2016, coupled with the selective deferral of expense and
capital workover activity, led to a decline in our production in 2016. However, we accomplished our
operational tenet of minimizing our base decline with nominal capital investment.

At the time of our Spin-off, we had over 2,000 employees. In the third quarter of 2015 and early

2016, we implemented a voluntary retirement program and other employee actions to align our
workforce with our view of the commodity price environment. We ended 2016 with approximately 1,450
employees, representing a nearly 30% reduction mainly through attrition and the 2015 and 2016
employee actions. We have also taken a number of other steps which better align our cost structure
with the current environment. As a result of these steps, our 2016 production costs and general and
administrative expenses were below 2015 levels. These measures helped offset some of the cash flow
effects of the low commodity prices. We also pursued a number of alternatives to strengthen our
balance sheet and better align our capital structure with the recent market conditions as described in
more detail in “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of
Operation—Liquidity and Capital Resources.”

With significant operating control of our properties, we have the ability to adjust our drilling and
workover rig count based on commodity prices and monitor market conditions to increase or decrease
our program accordingly. We reactivated our drilling program in the third quarter of 2016 with one
drilling rig located in the San Joaquin basin primarily targeting steamflood activities. By the end of the
year, we operated two drilling rigs, one each in the San Joaquin and Los Angeles basins. We drilled 42
development wells with 37 wells in the San Joaquin basin and 5 in the Los Angeles basin. These
included 34 steamflood and 8 waterflood wells. In 2016, we also increased our workover rig count from
26 at the beginning of the year to 41 at the end of the year to focus on projects that meet our
investment criteria. In total, we performed 133 capital workover projects during 2016.

Compared to 2015, our 2016 production declined 12.5%, with only $31 million of drilling and
workover capital employed for the year. Excluding the effect of our production-sharing contracts
(PSCs) in Long Beach, our decline rate would have been under 12%. This performance reflects the
resilience of our asset base and the better than expected flattening of our base production decline. We
expect to direct virtually all of our capital investments toward oil-weighted opportunities in 2017 to the
extent the oil-to-gas price relationship remains favorable, which should improve our overall margins.
For example, our steamflood projects provide some of the highest returns in our portfolio when the oil-
to-gas price ratio exceeds five to one. As of December 31, 2016, the ratio was approximately 19 to
one.

The flattening of our production decline rate that started in the second half of 2016 as a result of
higher activity levels has continued into the first quarter of 2017. 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 brought us to an inflection point where we can increase our activity level. We intend
to fund our capital investment program by reinvesting substantially all of our operating cash flow,
while considering additional potential deleveraging opportunities. We expect to drive organic
deleveraging by drilling our extensive inventory of oil-heavy, low-decline assets. Our high level of
operational control provides flexibility to adjust the level of our capital investments as circumstances

warrant. As a result, we have created dynamic budgets that can be adjusted to align investments
with projected cash flows. In the event of improved and more consistent prices and cash flow, we
may choose to deploy additional capital based on our VCI investment metric, while abiding by our
financial covenants.

Prior to the Spin-off, while we were a subsidiary of Occidental, we did not have a hedging

program. Given the volatile oil price environment, we instituted a program immediately after the Spin-
off to protect our cash flows, margins and capital investment programs and to improve our ability to
comply with our credit facility covenants in case of price deterioration.

Our Business Strategy

Near-Term Strategy

In mid-2016, global oil prices began to recover from the apparent low point of this commodity

cycle. The recovery further strengthened following the production cuts announced at the November
2016 meeting of the Organization of the Petroleum Exporting Countries (OPEC). In light of these
developments, we began to increase our activity level in the second half of 2016 and have continued
to do so in early 2017. While we began 2017 with two rigs running, by the end of the first quarter of
2017, we anticipate having four rigs running (three in the San Joaquin basin and one in the Los
Angeles basin). We also plan to add an additional rig in the Ventura basin by the third quarter of
2017. Our 2017 development program will focus primarily on our core fields: Elk Hills; Wilmington;
Kern Front; Buena Vista; and the delineation of Kettleman North Dome. Based on then-current
market conditions, we increased our 2017 planned capital program to $300 million from the $75
million invested in 2016. We have developed a dynamic plan which can be scaled up or down
depending on the price environment. For 2017, we have action plans that can reduce our capital
investment plan to under $100 million or increase it to as high as $500 million based on conditions
during the year. For highlights of our 2017 program, see “Portfolio Management and 2017 Capital
Budget” section below.

Our approach to our 2017 drilling program is consistent with our stated strategy to remain

financially disciplined and fund projects through internally generated cash flow. This approach is
intended to maintain our liquidity and further strengthen our balance sheet. We are prepared to
significantly increase our drilling activity if prices continue to improve during 2017. We will also
evaluate the use of excess cash for other opportunities to further strengthen our capital structure. Our
plan is to deploy capital to projects that help stabilize our production and return to a growth profile in
the second half of the year. 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.

Long-Term Strategy

We plan to drive long-term stockholder value by applying modern technology 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 steamfloods, waterfloods and other enhanced recovery mechanisms. In the
recent price and constrained capital environment, we have remained financially disciplined and
prudent with our capital investments to maintain liquidity. We are cautiously optimistic that the prices
at the end of 2016 are at a turning point and moving towards a more stabilized and relatively higher
commodity price environment. In a sustained higher price environment, we intend to direct any
additional available capital to oil projects that provide long-term value, high returns, growing cash
flows and low production declines. Higher activity should ultimately lead to more production which

further increases our cash flows, allowing us to strengthen our balance sheet through growth. The
principal elements of our long-term business strategy include the following:

(cid:129)

Focus on high-margin crude oil projects to generate sufficient cash flows to internally
fund our growth capital needs. We expect the percentage of our oil production to continue
to increase over time and favorably impact our overall margins as we anticipate directing
virtually all of our capital investments towards oil-weighted opportunities to the extent the oil-
to-gas price relationship remains favorable and capital is available. Approximately 95% of our
identified drilling inventory is associated with oil-rich projects. Currently, 65% of our production
is oil while 72% of our reserves are oil. Over time, we expect our share of oil production to
approach the share of oil reserves.

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

manage production declines and lower 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. At current price levels, we
intend to focus a greater portion of our capital investments on such projects, which we expect
will lower our production decline rates. Over time, we expect that this strategy will reduce the
capital required to maintain flat crude oil production. We have significant additional lower-risk
conventional opportunities with approximately 27,150 gross (19,450 net) identified drilling
locations, 54% of which are associated with Improved Oil Recovery (IOR) and Enhanced Oil
Recovery (EOR) projects. The remaining 46% are associated with primary recovery methods,
many of which we expect will develop into IOR and EOR projects in the future.

(cid:129)

Proactive and collaborative approach to safety, environmental protection, and
community relations. We are committed to managing our assets in a manner that
safeguards people and protects the environment, and we seek to proactively engage with
regulatory agencies, communities and other stakeholders to pursue mutually beneficial
outcomes. As a California company, helping our state meet its water needs is a key strategic
focus. Through our investments in water conservation and in recycling of produced water from
oil and gas reservoirs, we are a net water supplier to agriculture. In 2016, our operations
supplied more than 3.9 billion gallons of reclaimed water to agricultural water districts, a 49%
increase from 2015. This water supply to agriculture set a company record and again
exceeded the volume of fresh water we purchased for our operations statewide. We continue
to evaluate measures to further decrease our fresh water use and to expand the beneficial
use of our produced water over the coming years.

Continue to pursue joint venture development opportunities. We continuously evaluate
opportunities to accelerate future development through joint ventures. We would pursue these
projects to the extent we believe they would increase stockholder value. We are actively
discussing both development and exploration project opportunities. In addition to pursuing
growth through joint ventures, we expect substantially all our cash flow to be directed to our
capital program while considering other deleveraging opportunities as appropriate.

Continue to identify high-growth unconventional drilling opportunities. Over the longer
term and in a higher oil-price environment, we believe we can generate significant production
growth from unconventional reservoirs such as tight sandstones and shales. In such an
environment, we would expect to generate sufficient cash flow from our conventional projects
to fund numerous unconventional opportunities in our portfolio. We hold mineral interests in
approximately 1.3 million net acres with unconventional potential and have identified
approximately 3,750 gross (3,400 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 unconventional 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 of our increased understanding of these
reservoirs, 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.

Apply proven modern technologies 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, or
investments in other assets within their global portfolios. As an independent company focused
on California, we intend to use proven modern technologies in drilling and completing wells,
as well as production methods, which we expect will substantially increase both our
production and cost efficiency over time. We have developed an extensive 3D seismic library
covering almost 4,800 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.

Continued focus on our successful exploration program. As prices improve and sufficient
additional capital becomes available, we intend to significantly increase our investment in
exploration, focusing on both unconventional and conventional opportunities, primarily in
areas that we believe can be quickly developed, such as those adjacent to our existing
properties. In addition, we plan to explore and test new unconventional resource areas, which,
if successful, could result in significant longer-term production growth. In addition, we are also
actively pursuing joint venture partnership opportunities, which may give us the opportunity to
implement some of our exploration projects even in the current environment.

(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 over various
commodity price ranges and preserves future value and growth potential in a higher
price environment. 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, of which approximately
60% is held in fee, 15% is held by production and 25% are term leases, allows us to choose
among multiple recovery mechanisms, including primary conventional, steamflood,
waterflood and unconventional, and to develop various products, including oil, natural gas
and natural gas liquids (NGLs). 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

(cid:129)

minimal investment. We believe our low base decline positions us well to achieve oil
production growth in the current price environment while living within our means.

Relatively favorable margins driven by California’s deficit energy market. We currently
sell all of our crude oil into the California refining markets, which we believe have offered
favorable pricing for comparable grades relative to other U.S. regions. California is heavily
reliant on imported sources of energy, with approximately 65% of oil and 90% of natural gas
consumed in recent years 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 country to California will
continue contributing to higher realizations than most other United States oil markets for
comparable grades. In addition, we own fee mineral interests on approximately 60% of our
net acreage position. The returns on fee mineral acreage are enhanced because we do not
pay royalties and other lease payments. To further improve our margins, we are
opportunistically pursuing newly opened export markets for our crude oil production.

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 acres. California is one of the most prolific oil and natural gas
producing regions in the world and is the third largest oil producing state in the nation. It has
four of the 12 largest fields in the lower 48 states based on proved reserves as of 2013, and
our portfolio includes interests in each of these four fields. 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,
2016 consisted of approximately 30,900 gross identified well locations, including
approximately 27,150 gross (19,450 net) conventional drilling locations and approximately
3,750 gross (3,400 net) unconventional drilling locations. Our drilling inventory count
increased by about 30% from the prior year as a result of our technical teams’ continued
efforts. We also have approximately 1,000 workover projects that can deliver high returns. At
about $55 Brent, we estimate that we have been able to increase investment opportunities
that meet our 1.3 VCI hurdle sufficiently to double the drilling and workover capital we could
deploy. In the process, our inventory of lower-risk conventional development opportunities
with attractive returns has increased, even more than our unconventional opportunities. In a
more favorable, sustained 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 joint venture partnership
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’ experience in the oil and natural gas industry, with an
average of over 15 years focused on our California oil and gas operations through multiple
pricing cycles. Our operational management team and technical staff have a proven track

record of applying modern technologies and operating methods to develop our assets and
improve their operating efficiencies. For example, our teams have successfully reduced field
operating costs on a per unit basis by approximately 22% since the Spin-off.

Portfolio Management and 2017 Capital Budget

In 2016, we invested approximately $13 million for drilling wells, $18 million for capital workovers,

$23 million for facilities and compression expansion (including $19 million for a major turnaround of our
power plant), $15 million for maintenance and occupational health, safety and environmental projects
and the rest for other items. Virtually all of our 2016 development capital was directed towards oil-
weighted production consistent with 2015 and 2014.

In mid-2016, global oil prices began to recover from the apparent low point of this commodity

cycle. The recovery further strengthened following the production cuts announced at the November
2016 meeting of the OPEC. In light of these developments, we began to increase our activity level in
the second half of 2016 and have continued to do so in early 2017. While we began 2017 with two rigs
running, by the end of the first quarter 2017, we anticipate having four rigs running (three in the San
Joaquin and one in the Los Angeles basin). We also plan to add an additional rig in the Ventura basin
by the third quarter of 2017. Our 2017 development program will focus primarily on our core fields: Elk
Hills; Wilmington; Kern Front; Buena Vista; and the delineation of Kettleman North Dome. Based on
the current market conditions, we increased our 2017 planned capital program to $300 million from the
$75 million invested in 2016. We have developed a dynamic plan which can be scaled up or down
depending on the price environment. For 2017, we have action plans that can reduce the capital
program to below $100 million or increase it as high as $500 million based on conditions during the
year while remaining within our operating cash flows.

Based on our current 2017 plan, we expect to use approximately half of our capital to drill over 100

wells. Our drilling program utilizes all four of our recovery mechanisms: primary conventional,
steamflood, waterflood and unconventional. The depth of our primary conventional wells is expected to
range from 2,000-14,000 feet.

With the significant reduction in our drilling costs since the Spin-off, many of our deep conventional

and unconventional programs have become more competitive. We intend to drill approximately 20
unconventional wells in the Elk Hills, Buena Vista and Kettleman areas. We expect to focus our
conventional program of approximately 90 wells primarily on Mount Poso, Elk Hills, Pleito Ranch, Kern
Front and Wilmington, which will largely consist of steam and waterfloods. We recently entered into a
joint venture that will invest up to $250 million in the development of certain of our properties. The joint
venture will allow us to change the mix and nature of our drilling program as the year progresses.

We also plan to use over 15% of our capital 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 2017 program is intended for development facilities at our newer

projects, including pipeline and gathering line interconnections, gas compression and water
management systems, and about 10% each is intended to be used for exploration and to maintain the
mechanical integrity, safety and environmental performance of our operations.

As a result of higher activity levels, our production decline rate began to flatten in the second half
of 2016 and continues to improve in 2017. 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 brought us
to an inflection point where we can increase our activity level.

In addition, we will continue to build our inventory of available projects, which will position us to

take advantage of future higher prices.

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, 2016 in each of California’s four major oil and gas basins:

Proved Reserves as of December 31, 2016

Average Net Daily
Production for the
Year Ended
December 31, 2016

Oil
(MMBbl)

NGLs
(MMBbl)

Natural
Gas
(Bcf)

Total
(MMBoe)

Oil
(%)

Proved
Developed
(%)

(MBoe/d)

Oil
(%)

R/P Ratio
(Years)(1)

San Joaquin Basin
Los Angeles Basin
Ventura Basin
Sacramento Basin

Total operations

287
98
24
—

409

53
—
2
—

536
7
15
68

626

67%
99%
83%

429
99
29
11 —

568

72%

67%
84%
86%
100%

71%

59%
97
97%
30
7
71%
6 —%

140

65%

12.1
9.0
11.3
5.0

11.1

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.
Calculated as total proved reserves as of December 31, 2016 divided by annualized Average Net Daily Production for
the year ended December 31, 2016.

(1)

Marketing Arrangements

We market our crude oil, natural gas, NGLs and electricity in accordance with standard energy

industry practices.

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 in place. California is heavily reliant on imported sources of energy,
with approximately 65% of the oil consumed in recent years imported from outside the state. A vast
majority of the imported oil arrives via supertanker, mostly from foreign locations. 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. A vast majority of the imported oil 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, none of our index-based crude
oil sales contracts have terms extending past one year and a substantial majority have 60- or 90-day
terms. Beginning in late 2015, the U.S. federal government allowed the export of crude oil.

Prior to the Spin-off, while we were a subsidiary of Occidental, we did not have a hedging
program. Given the volatile oil price environment, as well as our leverage, we began a hedging
program immediately after the Spin-off to protect our cash flows, margins and capital investment
program and improve our ability to comply with the covenants under our credit facilities in case of
further price deterioration. 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. As part of our hedging program, we currently have the following
Brent-based crude oil contracts as of December 31, 2016:

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2-Q4 2018

Crude Oil
Calls:

Barrels per day
Weighted-average price per

12,100

5,000

10,000

15,000

15,600

15,000

barrel

$ 56.37 $ 55.05 $ 56.15 $ 56.12 $ 58.77

$ 58.83

Puts:

Barrels per day
Weighted-average price per

22,100

20,000

17,000

10,000

—

barrel

$ 49.10 $ 50.25 $ 50.88 $ 48.00 $

— $

Swaps:

Barrels per day
Weighted-average price per

20,000

—

barrel

$ 53.98 $ 53.98 $ 53.98 $ 53.98 $

— $

—

Natural Gas. California imports approximately 90% of the natural gas consumed in the state. We

have firm transportation capacity contracts to access markets where necessary. These contracts are
required 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 process substantially all of our NGLs through our processing plants, which facilitates

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.

Electricity. We provide part of the electrical output of our Elk Hills power plant to reduce Elk Hills

field operating costs and increase reliability. We sell the excess to the grid and to others under
contract.

Our Principal Customers

We sell our crude oil, natural gas and NGLs production to marketers, California refineries and
other purchasers that have access to transportation and storage facilities. Our marketing of crude oil,
natural gas and NGLs can be affected by factors that are beyond our control, and which cannot be
accurately predicted.

For the year ended December 31, 2016, Phillips 66 Company, 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. For the
year ended December 31, 2014, ConocoPhillips/Phillips 66 Company and Tesoro Refining & Marketing
Company LLC each accounted for at least 10%, and, collectively, 45% of our revenue.

Title to Properties

As is customary in the oil and natural gas industry, 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 our properties.
Such 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, our properties have been pledged
as collateral to secure a portion of our debt.

Competition

We have many competitors (including international competitors exporting to California), some of

which are larger and better funded, may be willing to accept greater risks or have special
competencies. We compete for 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.
Over the longer term, competition for reserves can increase costs for, or delay, reserves replacement.
We compete on the basis of costs, our inventory of drilling opportunities, access to capital, efficiency of
capital allocation and other factors.

Regulation of the Oil and Natural Gas Industry

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, the production,
transportation, marketing and sale of our products, and the services we provide.

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 or density on private and state lands;

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

(cid:129)

abandoning wells;
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;

(cid:129)

(cid:129)
(cid:129)

(cid:129)

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.

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

is the state’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. In addition, specific aspects of our operations, such as
occupational health, safety, air and water quality, labor, marketing and taxation, are regulated by other
federal, state or local agencies. 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.

In 2013 California adopted Senate Bill 4 (SB 4), which increased regulation of certain well
stimulation techniques, including, as defined, 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 regulate
certain drilling activities in general and well stimulation or completion activities in particular, or ban such
activities outright. The most onerous of these local measures was adopted by Monterey County in
November 2016, where we own mineral interests but do not have production. The measure, which is
currently stayed during a legal challenge, would prohibit drilling of new oil and gas wells, hydraulic
fracturing and other well stimulation and phase out water injection.

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, but are not limited to,
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. California imposes additional laws that are
analogous to, and often more stringent than, such federal laws. The foregoing laws and regulations:

(cid:129)

establish air, soil and water quality standards for a given region, such as the San Joaquin
Valley, and attainment plans to meet those regional standards, which may include significant
restrictions on development, economic activity and transportation in such region;

(cid:129)

require various permits and approvals 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;
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;
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 or transportation 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 closure, abandonment, cleanup or restoration of former
operations, such as plugging and abandonment of wells and decommissioning of facilities;
impose substantial liabilities for unauthorized releases or discharges of regulated materials
into the environment with respect to our current or former properties and operations and other
locations where such materials generated by us or our predecessors were released or
discharged;
require comprehensive environmental analyses, recordkeeping and reports with respect to
operations affecting federal, state and private lands or leases;
impose taxes or fees with respect to the foregoing matters;

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

groups or others; and

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

Due to the severe drought in California over the last several years, water districts and the state
government are implementing 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 re–use 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, and we 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, and those deadlines are
currently being challenged in court. Since the state and the EPA did not complete their review before
the state’s deadlines, the state has announced that it will not rescind permits or enforce the deadlines
with respect to many of the formations pending completion of the review, but plans to apply 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. To date, such restrictions have not affected our oil and
natural gas production in any material way. Separately, the state began a review in 2015 of permitted
surface discharge of produced water and the use of reclaimed water for agricultural irrigation.
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 and regional efforts seek to prevent or mitigate the effects

of climate change or to track or 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:

(cid:129)

(cid:129)
(cid:129)

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:

(cid:129)

established a “cap-and-trade” program for GHG emissions that sets a statewide maximum
limit on total GHG emissions, and this cap declines annually to reach 1990 levels by 2020, 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, for which
allowances we incurred costs of approximately $33 million in 2016;
require refiners to reduce the carbon content of transportation fuels they market in California
by 10% by 2020;
impose a more stringent state goal of reducing GHG emissions to 40% below 1990 levels by
2030 by reducing industrial source emissions, even if the cap-and-trade program is not
extended;
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 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 and announced its intent to propose controls on methane emissions from existing
sources. CARB has also proposed regulations to require monitoring, leak detection, repair and
reporting of methane emissions from oil and gas production operations beginning in 2018 and
additional controls such as vapor recovery to capture methane emissions in subsequent years.

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:

(cid:129)

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

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

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

(cid:129)

The federal and state agencies overseeing these regulations have substantial rate-setting and
enforcement authority, and violation of the foregoing regulations could expose us to litigation with other
government authorities, counterparties, special interest groups and others.

Employees

Our future success will depend partially on our ability to attract, retain and motivate qualified
employees. 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. Approximately 75 of our employees are represented by labor
unions. We have not experienced any strikes or work stoppages by our employees in the past 36 years
or longer.

At the time of our Spin-off, we had over 2,000 employees. In the third quarter of 2015 and early

Effective January 1, 2015, we adopted the California Resources Corporation 2014 Employee
Stock Purchase Plan (ESPP). 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 fiscal quarter, whichever amount is less. At January 1, 2017, over one quarter
of our employees had elected to participate in the plan.

Available Information

We make the following information available free of charge on our website at www.crc.com:

(cid:129)

(cid:129)
(cid:129)

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; and
Corporate governance information, including our corporate governance guidelines, board-
committee charters and code of business conduct (see Part III, Item 10, of this report for
further information).

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.

Risks Related to Our Business and Industry

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

Our financial results, financial condition, cash flow and ability to grow correlate closely to the

prices we obtain for our products. Compared to the 2014 average, global energy commodity prices
have declined significantly. For example, Brent crude prices declined from over $110 per barrel in June
2014 to below $30 per barrel in January 2016. While prices remain lower than the 2014 and 2015
averages, they have improved modestly since early 2016. 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:

(cid:129)

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

(cid:129)

(cid:129)
(cid:129)

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 such as we experienced in 2014 and 2015;
reduced borrowing base capacity under our first-out 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;
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 our
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 and regional
market conditions; transportation capacity, bottlenecks and costs in producing areas; alternative
energy sources; 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 protection for a significant
portion of our 2017 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 reserves-based first-lien first-out credit facilities is limited by

the size of our lenders’ commitments, our ability to comply with their covenants, our borrowing base
and a minimum monthly liquidity requirement. At January 31, 2017, the lenders’ commitments under
our first-out facilities were $2.05 billion, and we had approximately $486 million in availability, subject to
the minimum liquidity requirement. We may need to depend on our revolving credit facility for a portion
of our future capital or operating needs.

The financial covenants that we must satisfy under our first-out facilities include quarterly first-out

leverage and interest expense coverage ratios, as well as a semi-annual first-lien asset coverage ratio.
The first-out facilities also restrict our ability to monetize assets and issue or purchase debt as a means
of complying with our financial covenants. Our borrowing base under our first-out facilities, which
currently exceeds lender commitments, 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 first-out credit facilities are further described in “Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit
Facilities.”

If we were to breach any of the covenants under our first-out facilities, our lenders would be
permitted to accelerate the principal amount due under the first-out facilities and foreclose against the
assets securing them. If payment were accelerated, or we failed to make certain payments, under our
first-out facilities, it would result in a default under our second-out credit facility and outstanding notes
and permit acceleration and foreclosure against the assets securing the second-out credit facility and
the secured 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 which 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 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 default under our credit facilities or notes. 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 attributes or dilution of equity. For example, our repurchases of unsecured
notes in 2016 resulted in the elimination of federal net operating losses. In 2016, we incurred debt
under a second-out credit facility that, together with our 2015 exchange, increased our annual interest
expense.

We have significant indebtedness and may incur more debt. Higher levels of indebtedness
could make us more vulnerable to economic downturns and adverse developments in our
business or otherwise limit our operational flexibility.

As of December 31, 2016, we had $5.3 billion of consolidated indebtedness comprised of senior

unsecured notes, second lien secured notes and first-out and second-out secured credit facility
borrowings.

Our credit facilities and the indentures governing our outstanding notes permit us to incur
significant additional indebtedness as well as certain defined obligations unrestricted by debt
incurrence or lien covenants, or that do not constitute indebtedness. To the extent we need to incur
indebtedness above amounts permitted by our credit facilities, we may seek amendments or waivers.

Indebtedness outstanding under our first-out and second-out facilities bears interest at variable
rates, therefore a rise in interest rates will generate greater interest expense to the extent we do not
purchase interest rate hedges.

Our level of indebtedness may have several important consequences, including, without limitation:

(cid:129)
(cid:129)

(cid:129)

jeopardizing our ability to execute our business plans;
increasing our vulnerability to adverse changes in our business and in economic and industry
conditions generally, and 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 additional financing for working capital, capital investments and
general corporate and other purposes or increasing the cost of that capital; and
limiting our flexibility to operate our business, compete for capital, react to competitive
pressures, address adverse regulatory changes and engage in certain transactions that might
otherwise be beneficial to us.

The terms of the credit facilities and note indentures may limit, among other things:

incurrence of additional indebtedness;
investments;
amounts and types of joint ventures;
restricted payments;
creation of liens on our assets;
sales of assets that constitute collateral;
application of the full proceeds of asset sales other than to pay down debt;

(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129)
(cid:129) mergers or acquisitions; and
(cid:129)

release of collateral.

These limitations are further described in “Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities; 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 or our ability to further reduce our debt, which will be affected 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 sell 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 continue to make substantial

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: (i) commodity prices and market
access; (ii) regulatory and third-party approvals; (iii) our ability to timely drill, complete and stimulate
wells due to technical factors and contract terms; (iv) the availability of, and our ability to compete for,
capital, equipment, services and personnel; (v) drilling and completion costs and results and (vi) our
ability to compete for acquisitions or otherwise match the prices offered by our competitors. Capital
availability may be reduced (i) by our lenders, (ii) due to joint venture partners’ perceptions of the
quality of our assets or credit risk or (iii) as a result of capital market constraints or poor stock price
performance. Because of these and other potential variables, we may be unable to deploy capital in
the manner planned, which may constrain our development or acquisition activities.

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.

The Brent oil price used for reserve calculations decreased from $55.57 per barrel for 2015 to
$42.90 per barrel for 2016. As a result, we experienced negative price-related revisions to our proved
reserves at December 31, 2016 of 60 MMBoe. 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 2016 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:

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

historical production from the area compared with production from similar areas;
the quality, quantity and interpretation of available relevant data;
commodity prices;

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

production and operating costs;
ad valorem, excise and income taxes;
development costs;
the effects of government regulations; and
future workover and asset retirement costs.

Misunderstanding of these variables, inaccurate assumptions, changed circumstances or new

information could require us to make significant negative reserves revisions.

We currently expect improved recovery, extensions and discoveries to be our main sources for

reserves additions. However, 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. Any material inaccuracies in our reserves estimates
could materially affect the net present value of our reserves, which could adversely affect our
borrowing base and liquidity under our reserves-based first-out credit facilities, as well as our results of
operations.

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

Our disposition activities, including joint ventures, carry risks that we may (i) not be able to realize
reasonable prices or rates of return for assets we sell or contribute to joint ventures; (ii) be required to
retain liabilities that are greater than desired or anticipated; (iii) lose synergies among elements of our
business and (iv) the revenue lost or costs to replace the services from assets sold could reduce our
borrowing base and cash flows. 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.

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.

Unless we replace crude oil and natural gas reserves, our future reserves and production will
decline.

Unless we conduct successful development and exploration activities or acquire properties

containing proved reserves, our proved reserves will decline as those reserves are produced. Reduced
capital investment may result in a decline in our reserves. 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.

Our business is highly regulated and governmental authorities can delay or deny permits and
approvals or change legal requirements governing our operations, including hydraulic
fracturing and other well stimulation, 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. 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.

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, 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 limiting our 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 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, and preclude us from drilling,
completing or stimulating wells, 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.”

Drilling for and producing oil and natural gas carry significant operational and financial risk and
uncertainty. We may not drill our identified sites at the times we scheduled or at all, and sites
we decide to drill may not yield crude oil or natural gas in economically producible quantities.

Our decisions to explore, develop, purchase or otherwise exploit prospects or properties will
depend in part on the evaluation of geophysical, geologic, engineering, production and other technical
data and processes; the analysis of which is often inconclusive or subject to varying interpretations.
Our decisions and ultimate profitability are also affected by crude oil and natural gas prices, the
availability of capital, regulatory approvals, available transportation capacity, political resistance and
other factors. Our cost of drilling, completing, stimulating, equipping, operating, maintaining and
abandoning wells is also often uncertain. Our production cost per barrel are 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.

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 prospective 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 20% of our total net undeveloped acreage at December 31,
2016.

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 and prospective drilling locations is higher than for other
locations because we have less geologic and production data and drilling history, in particular for our
prospective resource locations, which are in unproven geologic plays. 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. 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 our ability, the timing or the cost 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 following occur:

(cid:129)
(cid:129)

(cid:129)

a change in price basis differentials;
the counterparties to our hedging or other price-risk management contracts fail to perform
under those arrangements; and
an event materially impacts oil and natural gas prices in the opposite direction of our
derivative positions.

Tax law changes may adversely 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. The imposition of such taxes could significantly reduce our profit
margins and cash flow and could ultimately result in lower oil and natural gas production, which may
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
and transportation 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 CFTC 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. While many Dodd-Frank Act regulations are
already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the
adopted rules and regulations and any future rules and regulations on our business remains uncertain.

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. 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
California and the EPA have adopted laws, and policies that seek to reduce GHG emissions as
discussed in “Business – Regulation of the Oil and Natural Gas Industry.” In 2016, we incurred costs of
approximately $33 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.

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
and electricity generation, impose additional taxes and costs on producers and consumers of
petroleum products and require or subsidize the use of renewable energy.

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, despite achieving significant emissions
reductions, 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.

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,
including well drilling, completion, stimulation, maintenance and abandonment activities, are subject to
oil and gas operational risks such as fires, explosions, releases, discharges, equipment failures and
industrial accidents. Other catastrophic events such as earthquakes, floods, mudslides, fires, droughts,
terrorist attacks and other events that cause operations to cease or be curtailed may adversely affect
our business 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.

Risks Related to the Spin-off

In connection with our separation from Occidental, we agreed to indemnify Occidental for
certain liabilities, including those related to the operation of our business while it was still
owned by Occidental, and Occidental agreed to indemnify us for certain liabilities, which
indemnities may not be adequate.

Pursuant to agreements with Occidental, Occidental agreed to indemnify us for certain liabilities,

and we agreed to indemnify Occidental for certain liabilities, in each case for uncapped amounts.
Indemnity payments that we may be required to provide Occidental may be significant and could
adversely impact our business, particularly indemnity payments relating to our actions that could
impact the tax-free nature of the Spin-off. Third parties could also seek to hold us responsible for
liabilities that Occidental has agreed to retain. Further, there can be no assurance that the indemnity
from Occidental will be sufficient or timely to protect us against the full effect of such liabilities.

Our Tax Sharing Agreement with Occidental may limit our ability to take certain actions,
including strategic transactions, and may require us to indemnify Occidental for significant tax
liabilities.

Under a tax sharing agreement with Occidental we agreed to take, or refrain from, certain actions

to ensure that the Spin-off and certain related transactions qualify for tax-free treatment. The
agreement restricts our ability to sell assets outside the ordinary course of business, to issue or sell
additional common stock or other securities, or to enter into certain other corporate transactions. For
example, for a period of two years after March 24, 2016, the date of Occidental’s final disposition of our
common stock that it had retained, we may not enter into any transaction that would be reasonably
likely to cause us to undergo either a 30% or greater change in the ownership of our voting stock or a
30% or greater change in the ownership (measured by vote or value) of all classes of our stock absent
approval of Occidental.

We could have significant tax liabilities for periods during which Occidental operated our
business.

We or one or more of our subsidiaries were included in the combined, consolidated or unitary tax

returns of Occidental or one or more of its subsidiaries for periods prior to the Spin-off. We will be
responsible for any increase in Occidental’s federal or state tax liability for any period in which we or
any of our subsidiaries were combined or consolidated with Occidental if such increase results from
audit adjustments attributable to our business. Further, if the Spin-off were determined to be taxable for
U.S. federal income tax purposes, we could incur significant tax liabilities under the Tax Sharing
Agreement between Occidental and us.

The agreements between us and Occidental were not made on an arm’s-length basis.

The agreements we entered into with Occidental in connection with the Spin-off, were negotiated
while we were still a wholly owned subsidiary of Occidental and did not have an independent board of
directors or a management team independent of Occidental. The terms of those agreements may be
unfavorable and may not reflect terms that would have resulted from arm’s-length negotiations
between unaffiliated third parties. The terms relate to, among other things, the allocation of assets,
liabilities, rights and other obligations between Occidental and us.

ITEM 1B UNRESOLVED STAFF COMMENTS

We have no unresolved SEC staff comments at December 31, 2016.

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 the third
largest oil producing state in the nation. According to DOGGR, 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 10 trillion cubic
feet (Tcf) of natural gas 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. California is heavily reliant on
imported sources of energy, with approximately 65% of oil and 90% of natural gas consumed in recent
years 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. Because of limited crude transportation infrastructure from other parts of the
country to California, the California market is generally isolated from the rest of the nation, which we believe
has offered relatively favorable pricing compared to other U.S. regions for similar grades. The favorable
pricing, coupled with the high percentage of oil in our total production, provides us with attractive cash
operating margins. Our operations include 135 fields with 8,837 gross active wellbores as of December 31,
2016. We believe we are the largest private oil and natural gas mineral acreage holder in California, with
interests in approximately 2.3 million net acres. Approximately 60% of our total net mineral interest position
is held in fee. 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 2016 we produced 51 million barrels of oil equivalent (MMBoe). Our capital program, along with

positive performance-related revisions of 13 MMBoe, added 36 MMBoe of proved reserves in 2016
representing a 71% organic reserves replacement ratio. This was accomplished with $31 million of
drilling and workover capital. For further information on our reserves replacement ratio, see “Our
Reserves and Production Information—PV-10, Standardized Measure and Reserves Replacement
Ratio” section below.

San Joaquin Basin

We actively operate and are developing 45 fields in this inland basin in the southern part of

California’s central valley, which consists of conventional primary, IOR, EOR and unconventional
project types with approximately 1.5 million net acres, approximately 64% of which we hold in fee.
Approximately 76% of our estimated proved reserves as of December 31, 2016 were located in, and
69% of our average daily net production for the year ended December 31, 2016 came from, the San
Joaquin basin.

According to DOGGR, approximately 75% of California’s daily oil production for 2015 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 over 2.0 BBoe to date. During the year ended December 31, 2016, we produced
52 MBoe/d on average from our Elk Hills properties, or approximately 37% of our total average daily
production. Of our total Elk Hills production, 65% is liquids. We also operate efficient natural gas
processing facilities, including a state-of-the-art cryogenic gas plant, with a combined capacity of over
590 MMcf/d. Additionally, we generate sufficient electricity to operate the field and sell excess power to
the grid and to others through contractual agreements. A portion of our excess power is subject to a
five-year contract with a local utility, which includes a minimum capacity payment, thereby providing us
with rates that are generally better than we could receive 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.

Los Angeles Basin

We actively operate and are developing 8 fields in this urban, coastal basin which consists of
conventional primary, IOR, EOR and unconventional project types, approximately half of which we hold
in fee. Approximately 17% of our estimated proved reserves as of December 31, 2016 were located in,
and 21% of our average daily net production for the year ended December 31, 2016 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 Oil Field

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

produced over 3.0 BBoe to date. During the year ended December 31, 2016, we produced
approximately 33 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 2016 of approximately 25 MBoe/d equated to approximately 18% of our
total average daily production. Most of our Wilmington production is covered under 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. The field is
developed by applying waterflood methods of oil recovery. 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 29 fields in this central California coastal basin which

consists of primary conventional, IOR, EOR and unconventional project types. We currently hold
approximately 0.3 million net acres in the Ventura basin, approximately 72% of which we hold in fee.
Approximately 5% of our estimated proved reserves as of December 31, 2016 were located in, and
approximately 5% of our average daily net production for the year ended December 31, 2016 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 play 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 acres in the Sacramento basin, approximately 37% of which we hold in fee. 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. Approximately 2% of our

estimated proved reserves as of December 31, 2016 were located in, and approximately 4% of our
average daily net production for the year ended December 31, 2016 came from, the Sacramento basin.

The Sacramento basin is a deep, thick sequence of sedimentary deposits within an elongated
northwest-trending structural feature covering about 7.7 million acres. Exploration and development in
the basin began in 1918.

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 where they have 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 Potential

We believe our undeveloped unconventional acreage has the potential to provide significant long-

term production growth. In total, we hold mineral interests in approximately 1.3 million net acres with
unconventional potential and have identified over 3,750 gross (3,400 net) unconventional drilling
locations on this acreage. As a result of focusing more on these reservoirs over the past few years,
approximately 32% of our 2016 production was from unconventional reservoirs, an increase of
approximately 95% since the acquisition of our Elk Hills field properties in 1998. As of December 31,
2016, we had proved reserves of approximately 170 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, 2016, we produced approximately 48 MBoe/d on
average from upper Monterey. The lower Monterey is recognized as a world-class source rock
generating the majority of the hydrocarbons produced from fields across California.

In a higher price environment, we plan to apply the knowledge acquired from our successes in the
upper Monterey to other unconventional reservoirs in the San Joaquin basin such as the Kreyenhagen
and Moreno formations. The Kreyenhagen and Moreno formations are hydrocarbon source rocks that
have generated oil and gas, and we believe they offer similar development opportunities to the upper
Monterey and other resource play onshore U.S. reservoirs. The lower Monterey 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 in the lower
Monterey as well.

Exploration Program

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 270 identified reservoir
intervals in both structural and stratigraphic trap configurations. Historic industry activity has focused
on the primary and secondary development of known hydrocarbon accumulations, many of which were
discovered over one century ago. The hydrocarbon basins where we have significant land positions
remain underexplored.

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

which discoveries have been quickly developed into producing fields as demonstrated by our past
success rates, which have been approximately double the worldwide industry average over the last
decade. We believe our experienced technical staff, proprietary geological models, leading acreage
position and extensive 3D seismic library give us a strong competitive advantage.

The underexplored nature of the California basins and the unique competitive advantage provided

by our extensive technical knowledge, land position and proprietary data have resulted in a large
inventory of low-risk conventional exploration projects in proven play trends. We took advantage of our

recent lower activity levels to create a ranked near-field portfolio of over 150 exploration prospects
across the San Joaquin, Sacramento and Ventura basins. As of December 31, 2016, our project
inventory increased to approximately 12,100 gross (5,650 net) conventional exploration drilling
locations in proven reservoirs. The majority of these locations are located near and are analogous to
existing producing fields or our recent exploration discoveries.

We continue to develop our understanding and knowledge of the significant prospective resources

in the exploration shale reservoirs. In 2016, we completed the data processing of approximately 200
square miles of proprietary 3D seismic data around the Kettleman North Dome field that aids reservoir
characterization and fracture analysis. In addition, we undertook reservoir analysis incorporating
proprietary log and core data to further advance our understanding of exploration shale reservoirs. We
have identified approximately 6,400 gross (5,300 net) prospective resource drilling locations in the
lower Moneterey, Kreyenhagen and Moreno unconventional reservoirs.

Our Reserves and Production Information

Reserves Data

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

accordance with the rules and regulations of the SEC.

Reserves Presentation

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 posted benchmark prices and adjusted for price differentials to account for gravity,
quality and transportation costs. For the 2016 disclosures, the calculated average Brent oil price was
$42.90 per barrel and the average NYMEX gas price was $2.48 per Million British Thermal Units
(MMBtu). The average realized prices used for the 2016 disclosures were $39.83 per barrel for oil,
$21.54 per barrel for NGLs and $2.28 per Mcf for natural gas.

The following tables summarize our estimated proved reserves at December 31, 2016. Reserves

are stated net of applicable royalties. Estimated reserves include our economic interests under
arrangements similar to production-sharing contracts relating to the 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

177
42
410

287

110
11
126

142

287
53
536

429

As of December 31, 2016
Ventura
Basin

Los Angeles
Basin

Sacramento
Basin

82
—
7

16
—
—

98
—
7

20
2
15

4
—
—

24
2
15

—
—
68

—
—
—

—

—
—
68

Total

279
44
500

406

130
11
126

162

409
55
626

568

(a) As of December 31, 2016, approximately 20% of proved developed oil reserves, 11% of proved developed NGLs

reserves, 14% of proved developed natural gas reserves and, overall, 17% 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. The price of natural gas
on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been
similarly lower for a number of years. For example, in 2016, the average prices of Brent oil and NYMEX natural gas
were $45.04 per Bbl and $2.42 per MMBtu, respectively, resulting in an oil-to-gas price ratio of approximately 19 to 1.

Proved Reserves Additions

In 2016, we added 23 MMBoe of proved reserves resulting from our capital program and 13 MMBoe
due to positive performance revisions. These additions were offset by negative price-related revisions of
60 MMBoe. The price revisions incorporated the positive effect of lower operating costs also caused by
the lower commodity price environment. In a higher price environment, many of the volumes that became
uneconomic this year could again become economic and be added back to the reserves base though
possible operating cost increases may dampen the volume increase. The components of the changes to
our proved reserves during the year ended December 31, 2016 were as follows:

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total

Improved recovery:

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

Total (MMBoe)

Extensions and discoveries:

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

Total (MMBoe)

Total reserves additions from capital

program

Revisions related to performance

(MMBoe):

Revisions related to price changes

(MMBoe):

Divestitures (MMBoe):

3
—
—

11
2
20

—
—
—

—

1
—
—

—

—
—
—

—

2
—
3

(17)

—

(23)

(1)

(20)

—

—
—
—

—

—
—
2

—

(1)

—

3
—
—

14
2
25

(60)

(1)

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

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

Improved Recovery

In 2016, we added proved reserves of 3 MMBoe from improved recovery through proven IOR and

EOR methods. The improved recovery additions in 2016 were associated with the continued
development of steamflood and waterflood properties in the San Joaquin basin. The types of
conventional IOR and EOR development methods we use can be applied through existing wells,
though additional drilling is frequently required to fully optimize the development configuration.

Extensions and Discoveries

In 2016, we added 20 MMBoe of proved reserves from extensions and discoveries, which
generally result from exploration, exploitation and development programs. The extensions and
discovery additions were associated with the continued successful but limited drilling primarily in the
San Joaquin, Los Angeles, and Ventura basins.

Revisions of Previous Estimates

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
geologic, production decline or operating performance data. 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.

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

For example, higher prices generally increase the economically recoverable reserves in all of our
operations, because the extra margin extends their expected lives and renders more projects
economic. Partially offsetting this effect, higher prices decrease our share of proved cost recovery
reserves under arrangements similar to production-sharing contracts at our Long Beach operations
because less oil is required to recover costs. Conversely, when prices drop, we experience the
opposite effects. Total net negative price revisions in 2016 were 60 MMBoe. The price revisions
incorporated the positive effect of lower operating costs also caused by the lower commodity price
environment.

During the course of 2016 we experienced further price declines compared to 2015, resulting in

the average SEC price for Brent oil decreasing from $55.57 per barrel for 2015 to $42.90 for 2016. As
a result, we experienced negative price related revisions to our proved reserves at December 31, 2016
of 60 MMBoe. Generally, lower prices adversely impact the quantity of our reserves as those reserves
may no longer meet the economic producibility criteria under the rules or may be removed due to a
lower amount of capital available to develop these projects within the SEC-mandated five-year limit.
However, our production-sharing contracts in Long Beach tend to partially offset these effects because
our share of production and reserves from these contracts increases as prices decline. Further, during
the course of the year we implemented significant cost reduction and efficiency steps, which reduced
our production costs by approximately 16% and drilling costs by approximately 23%. These cost
reductions, as well as other efficiency efforts, offset a portion of the price-related loss of reserves
quantities as some of the barrels that would have become uneconomic in later years remain economic,
a portion of the proved undeveloped reserves that would otherwise be removed from the reserves
quantities become economic and we expect to drill more wells with the same amount of capital.

Proved Undeveloped Reserves

In 2016, we had proved undeveloped reserves additions of 12 MMBoe from extensions and
discoveries primarily in the San Joaquin and Los Angeles basins and 20 MMBoe from performance-
related revisions, offset by 29 MMBoe of negative revisions due to lower prices. We transferred 4
MMBoe of proved undeveloped reserves to the proved developed category as a result of the 2016
development program, all of which was in the San Joaquin and Los Angeles basins. As a result, we
converted approximately 2% of our beginning-of-year proved undeveloped reserves to proved
developed reserves during the year, investing approximately $13 million of capital. The total changes
to our proved undeveloped reserves during the year ended December 31, 2016 were as follows:

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total

Improved recovery (MMBoe):

Extensions and discoveries:

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

Total (MMBoe)

Revisions related to performance

(MMBoe):

Revisions related to price changes

(MMBoe):

Transfers to proved developed reserves:

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

Total (MMBoe)

—

8
1
12

(8)

(3)
—
(1)

(3)

—

1
—
—

—

—
—
—

—

(13)

(8)

(1)
—
—

(1)

—
—
—

—

—
—
2

—

—
—
—

—

9
1
14

(29)

(4)
—
(1)

(4)

Our year-end development plans and associated proved undeveloped reserves are consistent with
SEC guidelines for development within five years. Our conclusion is based on $65 average Brent price
over the next five years. Prices that are significantly below this level 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 current levels, we would need to remove approximately 45 MMBoe from our
proved undeveloped reserves.

PV-10, Standardized Measure and Reserves Replacement Ratio

As of December 31, 2016, our standardized measure of discounted future net cash flows

(Standardized Measure) was $2.7 billion and PV-10 was over $2.8 billion. In addition, we organically
replaced 71% of our proved reserves in 2016.

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. PV-10 and Standardized Measure are used by the industry and by our management as an
asset value measure to compare against our past reserves bases and the reserves bases of other

business entities because the pricing, cost environment and discount assumptions are prescribed by
the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not
dependent on the tax-paying status of the entity.

PV-10 of proved reserves
Present value of future income taxes discounted at 10%

Standardized measure of discounted future net cash flows

Organic reserves replacement ratio(1)

As of December 31,
2016
($ in millions)
2,848
(181)

2,667

71%

(1) 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 fully or
partially outside management’s control, including commodity prices, availability of capital and the underlying geology
affect reserves additions. Management uses this measure to gauge the results of its capital allocation. 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 future net cash flows as of December 31, 2016

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 15 years of experience as an
energy sector engineer including as a Senior Reservoir Engineer with Ryder Scott Company, L.P.
(Ryder Scott). She is a member of the Society of Petroleum Engineers (SPE) for which she served as
past chair of the U.S. Registration Committee. She holds a Master of Business Administration from the
Massachusetts Institute of Technology, a Master of Engineering in Petroleum Engineering from the
University of Houston and a Bachelor of Science from the University of Florida. She is also a registered
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 2016. 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 2016 and 2015 reserves
estimates for fields that in each year comprised at least 80% of our total proved reserves. Until year
end 2014, Ryder Scott conducted process reviews of our properties on behalf of our former parent.
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 2016 reserves audit included a detailed review of 83% of our total proved reserves. For 2016
and 2015 combined, Ryder Scott audited 94% 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, 2016. Ryder Scott’s report is attached as an exhibit to
this Form 10-K.

Determination of Identified Drilling Locations

Proven Drilling Locations

Based on our reserves report as of December 31, 2016, we have approximately 2,350 gross
(2,150 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 16,450 gross (15,050 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

Our portfolio of prospective drilling locations contains approximately 12,100 gross (5,650 net)

unrisked exploration drilling locations in proven 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.

Prospective Resource Drilling Locations

In addition, 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 (i.e., 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 and our
prospective resource 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, 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. A small portion of the unproven drilling locations may be uneconomic at
current prices. For a discussion of the risks associated with our drilling program, see “Risk Factors—
Risks Related to Our Business and Industry.”

The table below sets forth our total gross identified drilling locations as of December 31, 2016,

excluding our prospective drilling locations from new resource plays.

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

200
1,050
100
250

1,600

—
—
250
—

250

—
—
50
—

—

—
250
50
—

300

—
—
100
—

100

—
—
50
—

—

Total Identified Drilling Locations

1,900

450

9,000
7,550
2,100
3,750

22,400

—
—
1,600
—

1,600

1,600
350
750
—

2,700

1,900

28,600

—
450
1,050
—

1,500

—
—
550
—

550

—
—
250
—

250

—

2,300

Production, Price and Cost History

Oil, NGLs and natural gas are commodities; therefore, 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
and refining disruptions, currency exchange rates, worldwide drilling and exploration activities, the
effects of conservation, weather, geophysical and technical limitations, refining and processing
disruptions, transportation bottlenecks and other matters affecting the supply and demand dynamics
for our products, technological advances and regional market conditions; transportation capacity and
costs in producing areas; 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 protect our
cash flow and capital investment program and improve our ability to comply with the covenants under
our credit facilities in case of price deterioration.

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 production, realized and benchmark prices,
and costs for oil and gas producing activities for the years ended December 31, 2016, 2015 and 2014.
For additional information on price calculations, see information set forth in “Management’s Discussion
and Analysis of Financial Condition and Results of Operations.”

Year Ended December 31,
2015

2014

2016

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

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

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

Average costs per Boe:(b)
Production costs
General and administrative expense, as adjusted(c)
Other operating expenses, as adjusted(d)
Depreciation, depletion and amortization
Taxes other than on income

91
16
197
140
51

104
18
229
160
58

$
$
$
$

$
$
$

$
$
$
$
$

42.01 $
39.72 $
22.39 $
2.28 $

49.19 $
47.15 $
19.62 $
2.66 $

45.04 $
43.32 $
2.42 $

53.64 $
48.80 $
2.75 $

15.61 $
0.72 $
0.67 $
10.28 $
2.36 $

16.30 $
1.00 $
0.36 $
16.72 $
2.67 $

99
19
246
159
58

92.30
92.30
47.84
4.39

99.51
93.00
4.34

18.23
1.47
0.55
20.40
3.50

(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 and 2014, the amount excludes asset impairment charges of $4.9 billion and $3.4 billion, respectively.
(c) For 2016, the amount excludes unusual and infrequent charges related to severance and early retirement costs

associated with field personnel totaling $0.12 per Boe. For 2015, the amount excludes charges of $0.31 per Boe related
to early retirement and severance costs. For 2014, the amount excludes charges of $0.10 per Boe related to Spin-off
and transition-related costs.

(d) For 2016, the amount excludes net unusual and infrequent gains of $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 $1.42 per Boe. For 2014, the amount excludes charges related to rig termination
charges and Spin-off and transition-related charges of $0.97 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, 2016, 2015
and 2014:

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

Oil (MBbl/d)
NGLs (MBbl/d)
Natural gas (MMcf/d)(a)
Production costs per Boe(c)

2016

Elk Hills
2015

2014

2016

Wilmington
2015

2014

21
13
106

24
15
123

25
16
136

25
—
—

28
—
1

25
—
—

$ 44.50 $ 52.78 $ 97.27 $ 37.98 $ 45.50 $ 90.37
—
$ 23.03 $ 20.12 $ 48.68 $
$
—
4.47 $
$ 10.48 $ 11.11 $ 14.31 $ 22.27 $ 21.87 $ 28.98

— $
2.05 $

— $
1.83 $

2.27 $

2.67 $

(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) Excludes the effect of hedges.
(c) Production costs per Boe for Wilmington are higher than the actual cost to run the field due to the effect of PSCs. The
reported production cost per Boe is calculated as total production cost for the entire field over our share of production.
Using the total field production, the production costs per Boe would be $17.21, $17.74 and $19.94 for 2016, 2015 and
2014 respectively, which more accurately represent the actual cost of operating this field.

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, 2016

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

14%
12%
34%
40%

429

—
100%
—
—

28%
72%
—
—

100%

568

68%
79%
100%
34%

67%

100%
99%
—
—

99%

76%
86%
—
—

83%

—

72%

15
8
29
45

—
30
—
—

3
4
—
—

140

Includes reserves and production from gas injection of 14% and 8%, 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. As of December 31, 2016, we had a
total of 8,837 gross (7,737 net) producing wells, approximately 90% of which were oil wells. Our
average working interest in our producing wells is approximately 88%. 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, 2016, excluding wells that have been idle for more than five years:

As of December 31, 2016

Productive Oil Wells
Net(b)
Gross(a)

Productive Gas Wells

Gross(a)

Net(b)

San Joaquin Basin
Los Angeles Basin
Ventura Basin
Sacramento Basin

Total(c)

8,035
1,699
1,204
—

10,938

6,848
1,641
1,197
—

9,686

184
—
—
909

1,093

Multiple completion wells included above

153
—
—
832

985

(a) The total number of wells in which interests are owned.
(b) Sum of fractional interests.
(c) This total represents both producing and capable of producing wells. As of December 31, 2016, we had 2,957 gross
(2,726 net) oil wells and 237 gross (208 net) gas wells that are capable of production but currently not producing.

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, 2016, 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)

418
380

1,382
1,133

25
20

17
14

71
69

229
192

268
248

357
275

782
717

1,985
1,614

(a) Acres spaced or assigned to productive wells.
(b) Total acres in which we hold an interest.
(c) Sum of fractional interests owned 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 business
basis 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
20% of our total net undeveloped acreage at December 31, 2016 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.

Participation in Exploratory and Development Wells Being Drilled

The following table sets forth our participation in exploratory and development wells being drilled

as of December 31, 2016.

San Joaquin
Basin

Los Angeles
Basin

Ventura
Basin

Sacramento
Basin

Total

Exploratory and development wells

Gross
Net

4
4

1
1

—
—

5
5

At December 31, 2016, we were developing two steamfloods and three waterfloods. The
steamflood projects were located in the San Joaquin basin. Two waterflood projects were located in
the San Joaquin basin and one in the Los Angeles basin.

Drilling Activity

The following table describes our drilling activity of net wells for the periods indicated, which
represents 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

2016
Oil

Exploratory
Development

Natural Gas

Exploratory
Development

Dry

Exploratory
Development

2015
Oil

Exploratory
Development

Natural Gas

Exploratory
Development

Dry

Exploratory
Development

2014
Oil

Exploratory
Development

Natural Gas

Exploratory
Development

Dry

Exploratory
Development

—
37.0

—
—

3.0
254.0

—
—

—
5.4

—
—

—
29.1

—
—

2.0
775.2

—
170.2

—
—

8.0
2.3

—
—

—
0.9

—
—

1.7
20.3

—
—

2.0
—

—
—

—
3.0

1.0
—

—
42.4

—
—

3.0
283.1

—
—

3.7
965.7

—
3.0

11.0
3.2

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, 2016, we had 30- to 90-day oil delivery commitments ranging from
21 MBbls/d to 48 MBbls/d, gas contracts for 2 Bcf of natural gas under 30-day contracts and NGL
commitments for 2 MMBbls of NGLs through March 2017. 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 the 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 a wide network of fully owned infrastructure helps
connect to third party transportation pipelines, provide competitive advantage and reduce our operating
costs. Following is a description of our infrastructure:

Description

Quantity

Unit

San Joaquin
Basin

Capacity
Other
Basins Total

Gas Plants
Power Plants/Co-generation
Steam Generators/Plants
Compressors
Water Disposal Systems
Water Softeners
Oil and NGL Storage
Gathering Systems

Gas Processing

9
3
>50
400

MMcf/d
MW
Mb/d
MHP
Mbw/d
Mbw/d
Mbbls
Miles

590
600
220
300
2,400
265
580

50
50
—
20

640
650
220
320
2,100 4,500
265
1,240
>20,000

—
660

We believe we own the largest gas processing system in the state of California. In the San

Joaquin basin, our Elk Hills cryogenic gas plant has a capacity of 200 MMcf/d of wellhead gas bringing
our total processing capacity in the basin to over 590 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 certain North American NGL markets. In
addition, we have truck rack facilities coupled with a battery of pressurized storage tanks at our Elk
Hills natural gas processing facility for NGL sales to third parties.

Electricity

We generate all of our electricity needs for our Elk Hills and contiguous operations in the San

Joaquin basin, which utilize approximately a third of the capacity of our wholly owned 550 megawatt
combined-cycle power plant located adjacent to our Elk Hills processing facilities, and sell the excess.
Our Elk Hills power plant also provides primary steam supply to our cryogenic gas plant. We also
operate 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 the 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 lines 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 the flexibility to store crude oil and NGLs
in the event of third-party pipeline maintenance or disruptions. Our network of tank batteries allows us
to continue production and avoid or delay any field shutdowns.

ITEM 3

LEGAL PROCEEDINGS

For information regarding legal proceedings, see the information under the caption, “Lawsuits,

Claims, Commitments and Contingencies” in the MD&A section of this report and in Note 7 of our
Financial Statements.

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 24, 2017

Name

Todd A. Stevens

Marshall D. Smith

Robert A. Barnes

Shawn M. Kerns

Roy Pineci

President, Chief Executive Officer and Director since 2014;
Occidental Vice President—Corporate Development 2012 to
2014; Oxy Oil & Gas Vice President—California Operations
2008 to 2012; Occidental Vice President—Acquisitions and
Corporate Finance 2004 to 2012.

Senior Executive Vice President and Chief Financial Officer
since 2014; Ultra Petroleum Corp. Chief Financial Officer 2005
to 2014; Ultra Petroleum Corp. Senior Vice President 2011 to
2014.

Executive Vice President—Operations since 2016; Executive
Vice President—Northern Operations 2014 to 2016; Occidental
of Elk Hills President and General Manager 2012 to 2014; Oxy
Permian CO2 Operations Manager 2011 to 2012, Occidental
Argentina Deputy General Manager and Senior Vice President,
Operations 2010 to 2011; Occidental Argentina Vice President,
Operations 2007 to 2010.

Executive Vice President—Corporate Development since 2014;
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—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—Exploration since 2014; 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

2016

2015

High

Low

High

Low

$
$
$
$

23.30 $
25.50 $
15.18 $
21.97 $

2.81 $
9.20 $
8.79 $
9.84 $

78.68 $
98.65 $
60.50 $
51.50 $

37.50
55.90
22.60
17.60

Our common stock was held by over 22,100 stockholders of record at December 31, 2016.

Dividend Policy

In 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 the “Item 7—Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities” section below
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 sole stockholder prior to the Spin-off.
A description of the plans can be found in Note 10 of our Financial Statements. 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 3.4 million had been
issued through December 31, 2016.

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

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

b) Weighted-average exercise price of

c) Number of securities remaining

outstanding options, warrants and
rights

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

2,240,479

$69.89

2,288,027(2)

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

Includes 503,348 shares available under our 2014 Employee Stock Purchase Plan (ESPP) 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 group (with reinvestment of all dividends). The graph assumes $100 was
invested on December 1, 2014, the date our common stock began trading on the NYSE, 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 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, Noble Energy, Inc., Oasis Petroleum Corporation, Parsley
Energy, Inc., Pioneer Natural Resources Company, QEP Resources, Inc., Range Resources
Corporation, SM Energy Company, Whiting Petroleum Corporation and WPX Energy, Inc.

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

$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

California Resources Corp

S&P 500

Dow Jones US Exploration & Production

Peer Group

California Resources Corp $ 100 $

12/1/14 12/31/14 3/31/15 6/30/15 9/30/15 12/31/15 3/31/16 6/30/16 9/30/16 12/31/16
29

75 $ 103 $

82 $ 35

32 $

17 $

14 $

17 $

S&P 500

100

101

Dow Jones US
Exploration & Production

Peer Group

100

102

101

102

105

109

113

* 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 the California

business of Occidental. 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,
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 data for the years ended
December 31, 2013 and 2012 consists entirely of the combined results of the California business.

The selected balance sheet data at December 31, 2016, 2015 and 2014 consists of our
stand-alone consolidated balances, while the selected balance sheet data at December 31,
2013 and 2012 consists of the combined balances of the California business.

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

Statement of Operations Data
Revenues
Income (loss) before income taxes
Net income (loss)

Per common share

Basic
Diluted

Statement of Cash Flows Data
Net cash provided by operating activities
Capital investments
Acquisitions
Net (repayments) borrowings and related costs
Spin-off related dividends to Occidental
(Distributions to) contributions from 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

2016

Year Ended December 31,
2013
2014
(in millions, except for per share data)

2015

2012

$ 1,547 $
$
$

4,173 $
2,403 $
201 $ (5,476) $ (2,421) $
279 $ (3,554) $ (1,434) $

4,284 $
1,447 $
869 $

4,073
1,181
699

$
$

$
$
$
$
$
$

6.76 $ (92.79) $ (37.54) $
6.76 $ (92.79) $ (37.54) $

22.38 $
22.38 $

18.01
18.01

130 $
(75) $
— $
(73) $
— $
— $

2,476 $

2,371 $

2,223
403 $
(401) $ (2,089) $ (1,669) $ (2,331)
(427)
(141) $
—
356 $
—
532

(288) $
6,290 $
— $ (6,000) $
(335) $
— $

(48) $
— $
— $
(763) $

— $

0.30 $

— $

—

As of December 31,

2016

2015

2014

2013

2012

(in millions)

701 $

438 $

254 $

425 $

100 $
726 $

$
245
$ 5,885 $ 6,312 $ 11,685 $ 14,008 $ 13,499
$ 6,354 $ 7,053 $ 12,429 $ 14,297 $ 13,764
—
100 $
$
551
$
605 $
—
$ 5,168 $ 6,043 $
—
491 $
$
511
830 $
$
9,860
(916) $
$

— $
922 $
6,360 $
(68) $
549 $
2,611 $

— $
689 $
— $
— $
497 $
9,989 $

397 $
620 $
(557) $

The selected financial data presented above should be read in conjunction with “Item 7 – Management’s

Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated and
combined 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

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.

The Separation and Spin-off

We are an independent oil and natural gas exploration and production company operating
properties within the state of 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. Prior to November 30, 2014, all material
existing assets, operations and liabilities of Occidental’s California business were consolidated under
us. On November 30, 2014, Occidental distributed shares of our common stock on a pro-rata basis to
Occidental stockholders and we became an independent, publicly traded company (the Spin-off).
Occidental initially retained approximately 18.5% of our outstanding shares of common stock, which it
distributed to Occidental stockholders on March 24, 2016.

Basis of Presentation and Certain Factors Affecting Comparability

Until the Spin-off, the accompanying financial statements were derived from the consolidated
financial statements and accounting records of Occidental and were presented on a combined basis
for the pre-Spin-off periods. These financial statements reflect the historical results of operations,
financial position and cash flows of the California business. All financial information presented after the
Spin-off consists of our stand-alone consolidated results of operations, financial position and cash
flows. 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.

The statements of operations for periods prior to the Spin-off include expense allocations for
certain corporate functions and centrally-located activities historically performed by Occidental. These
functions include executive oversight, accounting, treasury, tax, financial reporting, finance, internal
audit, legal, risk management, information technology, government relations, public relations, investor
relations, human resources, procurement, engineering, drilling, exploration, marketing, ethics and
compliance, and certain other shared services. These allocations were based primarily on specific
identification of time or activities associated with us, employee headcount or our relative size compared
to Occidental. Our management believes the assumptions underlying the financial statements,
including the assumptions regarding allocating expenses from Occidental, are reasonable. However,
the financial statements for the pre-Spin-off periods may not include all of the actual expenses that
would have been incurred, may include duplicative costs and may not reflect our results of operations,
financial position and cash flows had we operated as a stand-alone public company during the periods
presented. Actual costs that would have been incurred if we had been a stand-alone company prior to
the Spin-off would depend on multiple factors, including organizational structure and strategic and
operating decisions.

Prior to the Spin-off, we participated in Occidental’s centralized treasury management program
and did not incur any debt. Excess cash generated by our business was distributed to Occidental, and
likewise our cash needs were provided by Occidental in the form of contributions.

Had we been a stand-alone company for the full year 2014, and had the same level of debt
throughout the year as we did on December 31, 2014, of approximately $6.4 billion, we would have
incurred $314 million of interest expense, on a pro-forma basis, for the year ended December 31,
2014, compared to the $72 million pre-tax interest expense reported in our statement of operations for
the year then ended.

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 for all periods presented to reflect this stock split.

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 changes in supply and demand and other market-related variables. These and other factors make it
impossible to predict realized prices reliably. Much of the global exploration and production industry
has been challenged at recent price levels, putting pressure on the industry’s ability to generate
positive cash flow and access capital. Average oil prices continued the decline that began in the last
half of 2014 into the first quarter of 2016. In mid-2016, global oil prices began to recover from the
apparent low point of this commodity cycle. The recovery further strengthened following the production
cuts announced at the November 2016 meeting of the Organization of the Petroleum Exporting
Countries (OPEC). While global oil prices improved modestly through the end of 2016 and began to
trade in a narrower range, daily average prices were still lower for the full year of 2016 compared to
2015.

Natural gas liquids (NGLs) prices improved relative to crude oil prices throughout 2016 due to

tighter supplies, the strength of industry exports and higher contract prices on natural gasoline.

Full year average natural gas prices were lower in 2016 than in 2015. However, prices rebounded
modestly in the second half of the year due to lower production, higher demand and warmer weather.
California natural gas differentials for the second half of the year also improved due to reduced storage
in the state following a third-party facility incident that occurred in late 2015.

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

the years ended December 31, 2016, 2015 and 2014:

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

2016

2015

2014

$
$
$

45.04 $
43.32 $
2.42 $

53.64 $
48.80 $
2.75 $

99.51
93.00
4.34

Oil prices and differentials will continue to be affected by a variety of factors, including

consumption patterns, inventory levels, global and local economic conditions, the actions of OPEC and
other significant producers and governments, actual or threatened production and refining disruptions,
currency exchange rates, worldwide drilling and exploration activities, the effects of conservation,
weather, geophysical and technical limitations, refining and processing disruptions, transportation
bottlenecks and other matters affecting the supply and demand dynamics for oil, technological
advances, regional market conditions, transportation capacity and costs in producing areas and the
effect of changes in these variables on market perceptions.

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 65% of the oil consumed in recent
years 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 country to California will continue to contribute to higher realizations than most
other U.S. oil markets for comparable grades. We also opportunistically consider foreign markets to
improve our margins.

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 parts of the U.S. As a result, we typically
enjoy favorable pricing since we can deliver our gas for much lower transportation costs. Due to much
lower levels of natural gas production compared to our oil production, the changes in natural gas prices
have a smaller impact on our operating results.

Higher natural gas prices have a net positive effect 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 prices is partially offset by higher operating costs. Conversely, lower natural gas prices
generally have a net negative effect on our operations, but lower the cost of our steamflood projects
and power generation.

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

We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to
pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas
stream affects our operating results. Additionally, we provide part of the electricity from our Elk Hills
power plant to reduce operating costs to Elk Hills and nearby fields and increase reliability. The remaining
electricity is sold to the grid and a utility under a contract that includes a capacity charge. The price we
obtain for our excess power impacts our earnings but generally by an insignificant amount.

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

capital investment programs from the cyclical nature of commodity prices and to improve our ability to
comply with the covenants under our credit facilities. 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 size 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 over the past two years negatively impacted
our production levels. Sustained low-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 quarterly earnings during the year.

Income Taxes

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

Pre-tax income (loss)
Income tax benefit

Net income (loss)

For the years ended
December 31,

2016

2015

2014

(in millions)

201 $
78

279 $

(5,476) $
1,922

(3,554) $

(2,421)
987

(1,434)

We did not make United States federal and state income tax payments in 2016 and 2015 due to
the taxable losses we incurred. Until the Spin-off, our share of Occidental’s tax payments or refunds
were paid or received, as applicable, by Occidental. During the year ended December 31, 2014,
Occidental paid approximately $165 million on our behalf.

The following reconciliation of the United States federal statutory income tax rate to our effective

tax rate is stated as a percentage of pre-tax income or loss:

United States federal statutory tax rate
State income taxes, net of federal
Valuation allowance
Cancellation of debt income
Stock-based compensation
Federal effect of state taxes on above items
Other

Effective tax rate

Federal and state valuation allowance

For the years ended
December 31,

2016

2015

2014

35 %
6
199
(288)
3
5
1

(39)%

35%
5
(7)
—
—
2
—

35%

35%
6
—
—
—
—
—

41%

In the first quarter of 2016, we reduced our valuation allowance against net deferred tax assets by

$82 million. During the course of the year, we also increased the valuation allowance by $480 million.
The resulting $398 million increase in the valuation allowance had the effect of increasing our effective
tax rate by 199%.

The first quarter 2016 reduction in the valuation allowance resulted from our evaluation in early
2016 of our assets and liabilities at the time of our fourth quarter 2015 debt exchange, which generated
$1.4 billion of cancellation of debt income (CODI) for tax purposes. At that date, 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 assets caused an $82 million reduction in the
valuation allowance.

During the course of the year, based on prevailing product prices, we concluded that we could not

realize, on a more-likely-than-not basis, any of the deferred tax assets being generated through
operating losses. Accordingly, we provided full allowances against such assets generated during the
year by the amount of $480 million.

We evaluate our deferred tax assets to determine if a valuation allowance is required to reduce
our gross deferred tax assets to an amount expected to be realized. We expect to realize $375 million
of our gross deferred tax assets through reversals of taxable temporary differences. We have
maintained a full valuation allowance on our deferred tax assets above this amount as there is not
sufficient evidence to support the reversal of 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.

Federal and state cancellation of debt income

As a result of our 2015 and 2016 debt transactions and modifications, we generated CODI of $1.4

billion and $1.3 billion, respectively ($2.7 billion in the aggregate), for both U.S. federal and California
state tax purposes. These respective amounts were excluded from taxable income in those years
because we determined that our liabilities exceeded the value of our assets for tax purposes
immediately prior to each of the transactions. In exchange for this exclusion, tax rules require us to
reduce the tax basis of our assets. Accordingly, we reduced our net operating losses and the basis of
property, plant and equipment by $1.2 billion for U.S. federal and $1.9 billion for California. 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. As a result, we recorded a benefit of $577 million for this permanent reduction of
tax liability, which reduced our effective tax rate by 288%.

Operations

We conduct our operations, in large part, through fee interests, land 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 acres, approximately 60% of which we hold in
fee. 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, a power plant and other related assets, 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:
(1) to recover our partners’ share of capital and production costs that we incur on their behalf, (2) for
our share of contractually defined base production and (3) for our share of production in excess of
contractually defined base production for each period. We realize our share of capital and production
costs, and generate returns, through our defined share of production from (2) and (3) 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 slightly less than 20% of our production for
the year ended December 31, 2016. In September 2016, the PSC representing the majority of the field
production adjusted to eliminate the base production sharing split. Our share of the base production
was smaller than our share of excess production. Accordingly, we now receive a modestly larger share
of total field production after cost recovery.

Financial and Operating Results

2016 compared to 2015

(cid:129)

(cid:129)
(cid:129)

(cid:129)

Realized crude oil prices, including the effect of cash received from settled hedges,
decreased 15% from $49.19 to $42.01 per barrel.
Reduced capital investment by 81% from $401 million in 2015 to $75 million in 2016.
Average daily oil and gas production volumes decreased 12.5% from 160,000 to
140,000 Boe.
Production costs decreased 16% from $951 million to $800 million.
General and administrative expenses decreased 30% from $354 million to $248 million, and
adjusted general and administrative expenses decreased 20%.
In 2016, net income of $279 million included a net gain of $805 million on early
extinguishment of debt and $283 million of non-cash derivative losses.
Adjusted net loss increased 2% from $311 million to $317 million.

2015 compared to 2014

(cid:129)

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

(cid:129)
(cid:129)

Realized crude oil prices, including the effect of cash received from settled hedges,
decreased 47% from $92.30 to $49.19 per barrel.
Reduced capital investment by 81% from $2,089 million in 2014 to $401 million in 2015.
Average daily oil and gas production volumes increased 1% from 159,000 to 160,000 Boe.
Production costs decreased 10% from $1,057 million to $951 million.
General and administrative expenses increased 17% from $302 million to $354 million, and
adjusted general and administrative expenses decreased 2%.
In 2015, net loss of $3.6 billion included after-tax asset impairments of $2.9 billion.
Adjusted net income decreased from income of $650 million to a loss of $311 million.

The table below reconciles net income (loss) to adjusted net income (loss) and presents net and

adjusted net income (loss) per diluted share:

Net income (loss)
Unusual and infrequent items:

Non-cash derivative losses (gains)
Severance, early retirement and other costs
Net gains on early extinguishment of debt
Gain from asset divestitures
Refunds, plant turnaround charges and other
Debt issuance costs
Asset impairments
Write-down of certain assets
Spin-off and transition-related costs

Adjusted income (loss) items before interest and taxes

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

Total

Adjusted net (loss) income

Net income (loss) per diluted share
Adjusted net (loss) income per diluted share

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

2014
2015
2016
(in millions, except share data)

279 $ (3,554) $ (1,434)

283
20
(805)
(30)
(13)
—
—
—
—

(545)
12
(63)
—

(596)

(52)
67
(20)
—
11
28
4,852
71
—

4,957
—
294
(2,008)

3,243

—
—
—
—
52
—
3,402
—
55

3,509
—
—
(1,425)

2,084

$
$

(317) $

(311) $

650

6.76 $ (92.79) $ (37.54)
16.73
(8.12) $
(7.85) $

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

Non-cash derivative losses (gains)
Net (proceeds) payments from settled derivatives

Net derivative losses (gains)

2016

2015
(in millions)

2014

283 $
(77)

206 $

(52) $
(81)

(133) $

3
2

The following table presents the reconciliation of our company-wide general and administrative

expenses to adjusted general and administrative expenses:

General and administrative expenses
Severance, early retirement and other costs

Adjusted general and administrative expenses

2016

2015
(in millions)

2014

248 $
(20)

228 $

354 $
(67)

287 $

302
(10)

292

Our results of operations can include the effects of unusual 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 income (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 income

(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).

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

Oil prices with hedge ($ per Bbl)

Oil prices without hedge ($ per Bbl)
NGLs prices ($ per Bbl)
Gas prices with hedge ($ per Mcf)

2016

2015

2014

$ 42.01 $ 49.19 $ 92.30

$ 39.72 $ 47.15 $ 92.30
$ 22.39 $ 19.62 $ 47.84
4.39
$

2.66 $

2.28 $

The following table presents our average realized prices as a percentage of Brent, WTI and

NYMEX for each of the three years in the period ended December 31, 2016:

Oil with hedge as a percentage of Brent

Oil without hedge as a percentage of Brent
Oil without hedge as a percentage of WTI
Gas with hedge as a percentage of NYMEX

2016

2015

2014

93%

88%
92%
94%

92%

88%
97%
97%

93%

93%
99%
101%

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

for each of the three years in the period ended December 31, 2016:

2016

2015

2014

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)

57
29
5
—

15
—
1
—

150
3
8
36

197

140

64
34
6
—

104

17
—
1
—

172
2
11
44

229

160

64
29
6
—

18
—
1
—

180
1
11
54

246

159

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

thousands of barrels of oil equivalent per day.

(a) 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 price of
natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has
been similarly lower for a number of years. For example, for the year ended December 31, 2016, the average prices of
Brent oil and NYMEX natural gas were $45.04 per barrel and $2.42 per MMBtu, respectively, resulting in an oil-to-gas
price ratio of approximately 19 to 1.

Balance Sheet Analysis

The changes in our balance sheet as of December 31, 2016 and 2015, are discussed below:

Cash and cash equivalents
Trade receivables, net
Inventories
Other current assets
Property, plant and equipment, net
Other assets
Current maturities of long-term debt
Accounts payable
Accrued liabilities
Current income taxes
Long-term debt—principal amount
Deferred gain and financing costs, net
Other long-term liabilities
Equity

2016

2015

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

12
200
58
168
6,312
303
100
257
222
26
6,043
491
830
(916)

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

See “Liquidity and Capital Resources” for discussion of changes in our cash and cash equivalents.

The increase in trade receivables was largely the result of higher year-end prices partially offset by
lower production volumes in 2016 compared to 2015. The decrease in other current assets was mainly
due to a reduction in the net value of our derivative assets. The decrease in property, plant and
equipment reflected depreciation, depletion and amortization (DD&A) for the period and a small non-
core asset sale, partially offset by capital investments. The decrease in other assets was primarily due
to the changes in deferred taxes in the first quarter of 2016 as previously discussed in the “Income
Taxes” section above.

The decrease in accounts payable reflected lower capital investments towards the end of 2016

compared to 2015. The increase in accrued liabilities was primarily due to higher greenhouse gas
liabilities as well as the higher fair value of outstanding derivatives. Current income taxes and other
long-term liabilities as of December 31, 2015 included $336 million in tax liabilities that have
subsequently been reclassified to deferred taxes. The other long-term liabilities also reflected higher
derivative liabilities, primarily due to non-cash mark-to-market effects and higher asset retirement
obligations. The decrease in long-term debt reflected the notes tender offer, repurchases and
exchanges of a portion of our unsecured notes and prepayment of part of our first-lien, first-out term
loan, partially offset by the issuance of a first-lien, second-out term loan credit facility. The decrease in
deferred gain and issuance costs, net, reflected the amortization of deferred gains and additional
deferred debt issuance costs on the new term loan, partially offset by the amortization and write-off of
existing deferred issuance costs. The increase in equity primarily reflected the net income for the
period, as well as the issuances of equity in exchange for debt and the amortization of employee stock
awards.

Statement of Operations Analysis

The following table presents the results of our operations, including the unusual and infrequent

items discussed in the “Financial and Operating Results” section above:

Oil and gas net sales(a)
Net derivative (losses) gains(b)
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
Other non-operating income (expense)
Income tax benefit

Net income (loss)

Adjusted net (loss) income(c)
Adjusted EBITDAX(d)

Effective tax rate

2016

$ 1,621
(206)
132
(800)
(248)
(559)
—
(144)
(23)
(79)
(328)
805
30
78

2015
(in millions)
$ 2,134
133
136
(951)
(354)
(1,004)
(4,852)
(180)
(36)
(168)
(326)
20
(28)
1,922

2014

$ 4,064
(5)
114
(1,057)
(302)
(1,198)
(3,402)
(217)
(139)
(207)
(72)
—
—
987

$
$

279

$ (3,554)

$ (1,434)

(317)
616

$
$

(311)
906

$
650
$ 2,548

(39)%

35%

41%

Includes related-party sales for 2014.

(a)
(b) Amounts are net of (proceeds) payments from settled derivatives of $(77) million, $(81) million and $2 million, in 2016,

2015 and 2014, respectively.

(c) See “Financial and Operating Results” above for our Non-GAAP reconciliation.
(d) We define adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and

amortization; exploration expense; and other unusual and infrequent items. Our management believes 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 first-lien, first-out credit facilities 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 income (loss) to the non-GAAP financial
measure of adjusted EBITDAX:

Net income (loss)
Interest and debt expense
Income tax benefit
Depreciation, depletion and amortization
Exploration expense
Adjusted income items before interest and taxes(a)
Other non-cash items

Adjusted EBITDAX

2016

279
328
(78)
559
23
(545)
50

2015
(in millions)
$

(3,554) $
326
(1,922)
1,004
36
4,957
59

2014

(1,434)
72
(987)
1,198
139
3,509
51

616

906

2,548

(a) See “Financial and Operating Results” for a table which includes items reconciling net income (loss) to adjusted net

income (loss).

The following represents key metrics of our oil and gas operations, excluding certain corporate

items and asset impairments, on a per Boe basis for the years ended December 31, 2016, 2015 and
2014:

Production costs
General and administrative expense, as adjusted(a)
Other operating expenses, as adjusted(b)
Depreciation, depletion and amortization
Taxes other than on income

2016

2015

2014

$
$
$
$
$

15.61
0.72
0.67
10.28
2.36

$
$
$
$
$

16.30
1.00
0.36
16.72
2.67

$
$
$
$
$

18.23
1.47
0.55
20.40
3.50

(a) For 2016, the amount excludes unusual and infrequent charges related to severance and early retirement costs

(b) 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. For 2014, the amount excludes charges related to rig termination charges
and Spin-off and transition-related charges of $0.97 per Boe.

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. Our realized oil prices in 2016 and
2015 also included $77 million and $78 million of cash generated from our hedging program,
respectively. 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
are 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.

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.

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.

Net gains on early extinguishment of debt of $805 million in 2016 resulted from the August tender

as well as other note repurchases and exchanges, net of related expenses. Net gains on early
extinguishment of debt of $20 million in 2015 resulted from note repurchases, net of related expenses.

Other non-operating income (expense) consisted of approximately $30 million of gains from non-

core asset divestitures in 2016 and $28 million 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.

Year Ended December 31, 2015 vs. 2014

Oil and natural gas net sales decreased 47%, or $1.9 billion, in 2015 compared to 2014, primarily
due to an approximately $1.6 billion negative impact from lower oil prices, $190 million from lower NGL
prices and volumes and $180 million from lower natural gas prices and volumes. The lower oil prices
resulted from a significant decrease in benchmark prices generally, as well as higher differentials to
those benchmark prices in 2015, mainly caused by local refinery and pipeline events. The decrease
was partially offset by an approximately $70 million positive effect of higher oil volumes. Average oil
production increased by 5% or 5,000 barrels per day to 104,000 barrels per day in the year ended
December 31, 2015 compared to the prior year. NGL production decreased by 5% to 18,000 barrels
per day and natural gas production decreased by 7% to 229 MMcf per day.

Derivative gains were $133 million in 2015, compared to losses of $5 million in 2014. The change

was largely due to volume and non-cash valuation changes in our outstanding derivative positions of
$138 million.

Other revenue in 2015 increased 19%, or $22 million, due to increased marketing revenue partially

offset by lower prices for power sold by our Elk Hills power plant.

Production costs decreased 10%, or $106 million, to $16.30 per Boe in 2015, compared to $18.23
per Boe in 2014, an 11% reduction on a Boe basis. The decrease was driven by cost reductions across
the board, particularly in well maintenance and workovers, well servicing efficiency, surface operations,
reduced energy use through efficiencies and employee reductions, including early retirements, and
was aided by lower natural gas and electricity prices.

Adjusted general and administrative expenses, which excludes voluntary retirement and employee

reduction costs, decreased 2%, or $5 million, in 2015 compared to 2014, largely due to our cost
reduction efforts and lower stock-based compensation costs resulting from a lower year-end stock
price. The non-cash portion of adjusted G&A, comprising equity compensation and pension costs, was
approximately $30 million for each of 2015 and 2014.

DD&A expense decreased 16%, or $194 million, in 2015 compared to 2014, almost all of which
was due to a lower DD&A rate resulting from the 2014 impairment charges, partially offset by higher
2015 production.

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. As a result, in the
fourth quarter of 2015, we recorded pre-tax asset impairment charges of $4.9 billion on proved and
unproved properties throughout our asset base. The impairment charge was related to certain
properties in the San Joaquin, Los Angeles and Ventura basins, as well as our gas properties in the
Sacramento basin. Approximately $100 million of the charge was related to unproved acreage. We
evaluate 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 current environment. To the
extent prices recover to levels above the year-end forward price curves, we would expect a substantial
portion of these assets would ultimately become economic in an improved price environment.

Taxes other than on income decreased 17%, or $37 million, in 2015 compared to 2014, reflecting

lower property taxes assessed in the lower price environment prevailing during the period and a
decrease in greenhouse gas emissions costs.

Exploration expense decreased 74%, or $103 million, in 2015 compared to 2014, consistent with

our reduced exploration activity.

Other expenses, net decreased 19%, or $39 million, in 2015 compared to 2014, reflecting lower

natural gas costs for our Elk Hills power plant and lower rig termination costs.

The increase in interest and debt expense, net, of $254 million in 2015 compared to 2014, resulted

from the debt incurred in connection with the Spin-off in the fourth quarter of 2014.

Net gains on early extinguishment of debt of $20 million in 2015 resulted from note repurchases,

net of related expenses.

Provision for income taxes showed a benefit of $1.9 billion in 2015, which reflected a pre-tax loss
of approximately $5.5 billion, compared to a benefit of $987 million in 2014, which reflected a pre-tax
loss of approximately $2.4 billion. The 2015 benefit was net of a $294 million charge related to a
valuation allowance, which resulted in a lower effective tax rate in 2015.

Liquidity and Capital Resources

The primary source of liquidity and capital resources to fund our capital program and other

obligations for 2016 was cash flow from operations. Operating cash flows are largely dependent on oil
and natural gas prices, sales volumes and costs. Average oil prices continued the decline that began in
the last half of 2014 into the first quarter of 2016. While global oil prices improved modestly through the
end of 2016 and began to trade in a narrower range, daily average prices were still lower for the full
year of 2016 compared to 2015. These lower commodity prices have negatively impacted our
revenues, earnings and cash flows. If oil and natural gas prices were to drop again meaningfully from
current levels, this could have a material and adverse effect on our liquidity position.

Much of the global exploration and production industry has been challenged at recent price levels,

which put pressure on the industry’s ability to generate positive cash flow and access capital. If
commodity prices were to prevail through 2017 at about current levels, we would expect to be able to
fund our operations and capital budget with our operating cash flows and would not anticipate a net
draw down on our credit facilities. Our ability to borrow funds under our reserves-based first-lien first-
out credit facilities is limited by the size of our lenders’ commitments, our ability to comply with their
covenants, our borrowing base and a minimum monthly liquidity requirement. Effective November 1,
2016, the borrowing base under our existing first-lien first-out credit facilities was reaffirmed at $2.3
billion. However, the lenders’ commitments under our first-lien first-out credit facilities are limited to
$2.05 billion. As of January 31, 2017, we had approximately $486 million of available borrowing
capacity under our revolving credit facility, subject to the minimum liquidity requirement.

If product prices currently projected in the forward price curves materialize, we expect to be in

compliance with our covenants under our first-lien first-out credit facilities for the next twelve months
and possibly beyond. If we were to breach any of the covenants under our first-out facilities, our
lenders would be permitted to accelerate the principal amount due under the first-out facilities and
foreclose against the assets securing them. If payment were accelerated, or we failed to make certain
payments, under our first-out facilities, it would result in a default under our second-out credit facility
and outstanding notes and permit acceleration and foreclosure against the assets securing the second-
out credit facility and the secured notes.

Our 2017 base capital budget is approximately $300 million. We have developed a dynamic plan

that can be adjusted down to below $100 million or up to $500 million based on commodity prices
during the year in order to remain within our cash flows. Our liquidity position, along with internally
generated cash flows from operations and settlements from our derivative contracts in a lower price
environment, is expected to provide continued financial flexibility as we actively manage the pace of
our development activities.

At the beginning of the year, in response to commodity price declines, we budgeted $50 million for
our 2016 capital program, compared to our 2015 capital investments of $401 million. In the first half of
2016, we further reduced the pace of our capital program to below our initial budget. Since then and in
response to recent commodity price improvements, we modestly increased our 2016 capital
investments in the second half of the year, ending the year with $75 million. Our slowdown of drilling
activity from late 2015 through the first half of 2016, coupled with the selective deferral of expense and
capital workover activity, led to a decline in production in 2016. However, we began increasing activity
levels gradually towards the end of the second quarter, which continued into the third and fourth
quarters of 2016. We reactivated our drilling program in August, and we saw production benefits that
reduced the base production decline rate. We began experiencing the positive impact of the increased
activity towards the end of the third quarter, and expect to see further production benefits that should
reduce the base production decline rate further. We believe our overall annual base decline rate
ranges from 10% to 15%. With minimal capital in 2016, our production declined 12.5% compared to
2015. We cannot guarantee our planned increase in investments will result in a rapid reversal of, or a
significant increase in, production trends. Over the long term, if commodity prices fall again or remain
at depressed levels, we may experience continued declines in our production and reserves, which
could reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash
flow from operations, the value of our assets and our borrowing base.

We focus on creating value and are committed to internally fund our capital budget with operating

cash flows. Our low decline assets plus our high level of operational control give us the flexibility to
adjust the level of our capital investments as circumstances warrant. We create dynamic budgets that
can be adjusted to align investments with projected cash flows. We are also focusing our capital on oil
projects, which provide higher margins and low decline rates that we believe will generate growing
cash flow year after year and fund increasing capital budgets to grow production assuming stable or
increasing product pricing and modest service cost inflation. In this scenario we expect to be able to
strengthen our balance sheet organically.

We have taken a number of other steps to reduce our cost structure with the current price
environment, including a reduction of our workforce to below 1,500 employees as of December 31,
2016. As a result of these steps, in 2016 we have seen a reduction in our production costs and general
and administrative expenses below 2015 levels. These measures have helped offset some of the cash
flow effects of prolonged low commodity prices.

We reduced outstanding debt by approximately $900 million in 2016. In January and February
2016, we repurchased over $100 million in aggregate principal amount of our senior unsecured notes
for under $13 million in cash. In May 2016, we entered into privately negotiated exchange agreements
with a holder of our 6% Senior Notes due 2024 (the 2024 notes) and our 5 1⁄ 2% Senior Notes due 2021
(the 2021 notes) to exchange a total of approximately 2.1 million shares of our common stock on a
post-split basis for notes in the aggregate principal amount of $80 million. In August 2016, we issued a
new $1 billion first-lien, second-out term loan credit facility (2016 Second-Out Credit Agreement) to
prepay a portion of our existing term loans and reduce outstanding revolving loans under our first-lien,
first-out credit facilities (2014 First-Out Credit Facilities). Further, we used the availability from 2014
First–Out Credit Facilities to repurchase approximately $1.4 billion of our unsecured senior notes. In
October 2016, we entered into privately negotiated exchange agreements with certain holders of our

2024 notes and 2021 notes to exchange a total of 1.3 million shares of our common stock for notes in
the aggregate principal amount of $22 million. In the fourth quarter of 2016, we repurchased $11
million in aggregate principal amount of our 2024 and 2021 notes for $6 million in cash.

Our 2014 First-Out Credit Facilities mature at the earlier of November 2019 and the 182nd day
prior to the maturity of our 5% Senior Notes due 2020 (the 2020 notes) to the extent that more than
$100 million of such notes remain outstanding at such date and 2016 Second-Out Credit Agreement
matures at the earlier of December 2021 and the 91st day prior to maturity of the 2020 notes and 2021
notes if the outstanding principal amount of such notes exceeds $100 million prior to their respective
maturity dates.

We will continue to evaluate opportunities to strengthen our balance sheet to competitively

position the company for the longer term. We expect our main source of deleveraging, as measured by
a lower leverage ratio, will come from our future production growth through reinvesting substantially all
of our operating cash flow into our business. However, we may also from time to time seek to further
reduce our outstanding debt using cash from asset sales, other monetizations or other sources. Such
activities, if any, will depend on available funds, prevailing market conditions, our liquidity
requirements, contractual restrictions in our credit facilities, perceived credit risk by counterparties and
other factors. The amounts involved may be material. However, we can give no assurances that any of
these efforts will be successful.

Our strategy for protecting our cash flows and liquidity also includes our hedging program. We

currently have the following Brent-based crude oil contracts:

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2-Q4 2018

Crude Oil
Calls:

Barrels per day
Weighted-average price per

12,100

5,000

10,000

15,000

15,600

15,000

barrel

$ 56.37 $ 55.05 $ 56.15 $ 56.12 $ 58.77

$ 58.83

Puts:

Barrels per day
Weighted-average price per

22,100

20,000

17,000

10,000

—

barrel

$ 49.10 $ 50.25 $ 50.88 $ 48.00 $

— $

Swaps:

Barrels per day
Weighted-average price per

20,000

—

barrel

$ 53.98 $ 53.98 $ 53.98 $ 53.98 $

— $

—

Some of our second through fourth quarter 2017 crude oil swaps grant our counterparty a
quarterly option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-
average Brent price of $55.46. Our counterparty also has an option to increase volumes by up to
5,000 barrels per day for the second half of 2017 at a weighted-average Brent price of $61.43. During
2016, we purchased derivative assets that partially reduced our 2017 and 2018 call exposure for which
we paid $86 million and deferred payment of $15 million.

Credit Facilities

2014 First-Out Credit Facilities

The 2014 First-Out Credit Facilities comprise (i) a $650 million senior term loan facility (the Term
Loan Facility) and (ii) a $1.4 billion senior revolving loan facility (the Revolving Credit Facility). We are
permitted to increase the size of the Revolving Credit Facility by up to $250 million if we obtain

additional commitments from new or existing lenders. The Revolving Credit Facility includes a sub-limit
of $400 million for the issuance of letters of credit. Our credit limit under our 2014 First-Out Credit
Facilities is $2.05 billion. Borrowings under these facilities are also subject to a borrowing base, which
was reaffirmed at $2.3 billion as of November 1, 2016.

As of December 31, 2016 and 2015, we had outstanding borrowings of $847 million and

$739 million under our Revolving Credit Facility and $650 million and $1 billion under the Term Loan
Facility, respectively. At December 31, 2016, we had $1 billion outstanding under the 2016 Second-Out
Credit Agreement. We made payments on the Term Loan Facility during each of the four quarters in
2016 totaling $100 million and a $250 million prepayment from proceeds of the 2016 Second-Out
Credit Agreement.

As of February 2016, we amended the 2014 First-Out Credit Facilities to change certain of our
financial and other covenants. We again amended this agreement in April 2016 to facilitate certain
types of deleveraging transactions, in August 2016 to further change certain of our covenants, grant
additional collateral to our lenders and permit the incurrence of debt under the 2016 Second-Out Credit
Agreement and in February 2017 to facilitate additional joint venture transactions and note
repurchases, eliminate our capital expenditure restriction and adopt a minimum liquidity covenant.

We have granted the lenders under the 2014 First-Out Credit Facilities a first-priority lien in a
substantial majority of our assets, including our Elk Hills power plant and midstream assets. We also
granted a lien in the same assets to the lenders under our 2016 Second-Out Credit Agreement and the
holders of our 8% senior secured second-lien notes due in 2022 (2022 notes).

Borrowings under the 2014 First-Out Credit Facilities bear interest, at our election, at either a
LIBOR rate or an alternate base rate (ABR) (equal to the greatest of (i) the administrative agent’s prime
rate, (ii) the one-month LIBOR rate plus 1.00% and (iii) the federal funds effective rate plus 0.50%), in
each case plus an applicable margin. This applicable margin is based, while our total leverage ratio
exceeds 3.00:1.00, on our borrowing base utilization and will vary from (a) in the case of LIBOR loans,
2.50% to 3.50% and (b) in the case of ABR loans, 1.50% to 2.50%. The unused portion of the
Revolving Credit Facility commitments is subject to a commitment fee equal to 0.50% per annum. We
also pay customary fees and expenses under the 2014 First-Out Credit Facilities. 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.

Our financial performance covenants under the 2014 First-Out Credit Facilities require that (i) the

ratio of our first-lien, first-out secured debt to trailing four quarter EBITDAX (the First-Lien First-Out
Leverage Ratio) not exceed 3.50 to 1.00 at any quarter end through the quarter ending June 30, 2017
and 3.25 to 1.00 for the quarters ending September 30 and December 31, 2017 and (ii) the total
interest expense coverage ratio at each quarter end not be less than 1.20 to 1.00 at any quarter end
through the quarter ending December 31, 2017. Beginning with the end of the first quarter of 2018, the
First-Lien First-Out Leverage Ratio may not exceed 2.25 to 1.00 and the total interest expense
coverage ratio may not be less than 2.00 to 1.00. The covenants also include a requirement that the
first-lien asset coverage ratio must be at least 1.20 to 1.00 as of any June 30 and December 31
beginning December 31, 2016 and a requirement that minimum monthly liquidity be not less than
$250 million. As of January 31, 2017, we had approximately $486 million of liquidity, subject to the
minimum liquidity requirement.

We must apply 100% of the proceeds from asset sales to repay loans outstanding under the 2014
First-Out Credit Facilities, except that we are permitted to (i) use up to 50% (or, if our leverage ratio is
less than 4:00 to 1:00, 60%) of proceeds from non-borrowing base asset sales or monetizations to
repurchase our notes to the extent available at a significant minimum discount to par, as specified in

the facilities and (ii) purchase up to $140 million of certain of our unsecured notes at a discount. The
2014 First-Out Credit Facilities also permit us to incur up to an additional $50 million of non-facility
indebtedness, which may be secured by non-borrowing base assets, subject to compliance with our
financial covenants and indentures, the proceeds of which must be applied to repay the Term Loan
Facility. We must apply cash on hand in excess of $150 million daily to repay amounts outstanding
under our Revolving Credit Facility. Further, we are restricted from paying dividends or making other
distributions to common stockholders.

Our borrowing base under the 2014 First-Out Credit Facilities is redetermined each May 1 and
November 1. The borrowing base will be based upon a number of factors, including commodity prices
and reserves. Increases in our borrowing base require approval of at least 80% of our revolving
lenders, as measured by exposure, while decreases or affirmations require a two-thirds approval. We
and the lenders (requiring a request from the lenders holding two-thirds of the revolving commitments
and outstanding loans) 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.

2016 Second-Out Credit Agreement

The net borrowings under the 2016 Second-Out Credit Agreement were used to (i) prepay

$250 million of the Term Loan Facility and (ii) reduce our Revolving Credit Facility by $740 million. The
proceeds received were net of a $10 million original issue discount. The loan under the 2016 Second-
Out Credit Agreement bears interest at a floating rate per annum equal to 10.375% plus LIBOR,
subject to a 1.00% LIBOR floor, determined for the applicable interest period (or ABR rates in certain
circumstances). 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.

The 2016 Second-Out Credit Agreement is secured by a security interest in the same collateral
used to secure the 2014 First-Out Credit Facilities, but, under intercreditor arrangements with our 2014
First-Out Credit Facilities lenders, are second in collateral recovery behind such lenders. Prepayment
of the 2016 Second-Out Credit Agreement is subject to a make-whole premium prior to the third
anniversary of closing and a premium to par equal to 50% of coupon between the third anniversary and
the fourth anniversary. Following the fourth anniversary, we may redeem at par. The 2016 Second-Out
Credit Agreement matures on December 31, 2021, but if the aggregate principal amount outstanding of
either our 2020 Notes or our 2021 Notes exceeds $100 million 91 days prior to their respective maturity
dates, the maturity date of the term loans will accelerate to such prior 91st day. As of December 31,
2016, we had $193 million and $135 million in aggregate principal amount of outstanding 2020 notes
and 2021 notes, respectively.

The 2016 Second-Out Credit Agreement provides for customary covenants and events of default
consistent with, or generally less restrictive than, the covenants in our 2014 First-Out Credit Facilities,
including limitations on additional indebtedness, liens, asset dispositions, investments, restricted
payments and other negative covenants, in each case subject to certain limitations and exceptions.
Additionally, the 2016 Second-Out Credit Agreement requires us to maintain a first-lien asset coverage
ratio of 1.20 to 1.00 as of any June 30 and December 31 beginning December 31, 2016, consistent
with the 2014 First-Out Credit Facilities.

Senior Notes

In October 2014, we issued $5.00 billion in aggregate principal amount of our senior unsecured

notes, including $1.00 billion of 2020 notes, $1.75 billion of 2021 notes and $2.25 billion of 2024 notes
(collectively, the unsecured notes). We used the net proceeds from the issuance of the unsecured
notes to make a $4.95 billion cash distribution to Occidental in October 2014.

In December 2015, we exchanged $534 million, $921 million and $1,358 million in aggregate
principal amount of the 2020 notes, the 2021 notes, and the 2024 notes, respectively, for $2.25 billion
in aggregate principal amount of the newly issued 2022 notes. We recorded a deferred gain of
approximately $560 million on the debt exchange, which will be amortized using the effective interest
rate method over the term of the 2022 notes. Our 2022 notes are secured on a second-priority basis,
subject to the terms of an intercreditor agreement and collateral trust agreement, by a lien on the same
collateral used to secure our obligations under our 2014 First-Out Credit Facilities and 2016 Second-
Out Credit Agreement (the Credit Facilities).

In January and February 2016, we repurchased over $100 million in aggregate principal amount of

our unsecured notes for under $13 million in cash, for a pre-tax gain of $87 million, net of related
expenses. In May 2016, we entered into privately negotiated exchange agreements with a holder of
our 2024 notes and our 2021 notes to exchange a total of approximately 2.1 million shares of our
common stock on a post-split basis for notes in the aggregate principal amount of $80 million, resulting
in a $44 million pre-tax gain, net of related expenses.

In August 2016, we repurchased $197 million, $605 million and $613 million in aggregate principal

amount of our 2020 notes, 2021 notes and 2024 notes, respectively, for $750 million using our
Revolving Credit Facility, resulting in a $660 million pre-tax gain, net of related expenses.

In October 2016, we entered into privately negotiated exchange agreements with certain holders

of our 2024 notes and 2021 notes to exchange a total of 1.3 million shares of our common stock for
notes in the aggregate principal amount of $22 million, resulting in a $8 million pre-tax gain, net of
related expenses.

In the fourth quarter of 2016, we repurchased $11 million in aggregate principal amount of our

2024 and 2021 notes for $6 million, resulting in a $4 million pre-tax gain, net of related expenses.

We will pay interest semiannually in cash in arrears on January 15 and July 15 for the 2020 notes,

on March 15 and September 15 for the 2021 notes, on June 15 and December 15 for the 2022 notes
and on May 15 and November 15 for the 2024 notes.

The indentures governing the unsecured notes and the 2022 notes each include covenants that,

among other things, limit our and our subsidiaries’ ability to incur debt secured by liens. The indentures
also restrict our ability to merge or consolidate with, or transfer all or substantially all of our assets to,
another entity. These covenants are subject to a number of important qualifications and limitations that
are set forth in the indenture. 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 indentures) with respect to a series of notes, we will be required, unless we have exercised our
right to redeem the notes of such series, to offer to purchase the notes of such series at a purchase
price equal to 101% of their principal amount, plus accrued and unpaid interest. The indenture
governing our second lien secured notes also restricts our ability to sell certain assets and to release
collateral from liens securing the second lien secured notes, unless the collateral is released in
compliance with our Credit Facilities.

Other

All obligations under the Credit Facilities and the notes are guaranteed jointly and severally by all

of our material wholly owned subsidiaries. The assets and liabilities of subsidiaries not guaranteeing
the debt are de minimis.

At December 31, 2016, we were in compliance with all the financial and other covenants under our

Credit Facilities.

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

Facilities on December 31, 2016, would result in a $3 million change in annual interest expense.

As of December 31, 2016, we had letters of credit of approximately $130 million under the

Revolving Credit Facility. As of December 31, 2015, we had letters of credit in the aggregate amount of
$70 million (including $49 million under the Revolving Credit Facility). These letters of credit were
issued to support ordinary course marketing, insurance, regulatory and other matters.

Spin-off Related Distributions to Occidental

We used the net proceeds from the private placement of our unsecured notes in 2014 to make a

$4.95 billion cash distribution to Occidental in October 2014. See “—Senior Notes” for more details
regarding the terms of our senior notes. On November 25, 2014, we borrowed $1.0 billion under our
Term Loan Facility and $50 million under a Revolving Credit Facility to make a $1.05 billion cash
distribution to Occidental on November 26, 2014.

Cash Flow Analysis

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

2016

2015
(in millions)

2014

$
$
$
$

130 $
(61) $
(69) $
616 $

403 $
(757) $
352 $
906 $

2,371
(2,312)
(45)
2,548

(a) We define adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and

The following table sets forth a reconciliation of the GAAP measure of net cash provided by operating activities to the non-
GAAP financial measure of adjusted EBITDAX:

Net cash provided by operating activities
Cash interest
Cash income taxes
Exploration expenditures
Other changes in operating assets and liabilities
Other

Adjusted EBITDAX

Year Ended December 31, 2016 vs. 2015

2016

2015
(in millions)

2014

130 $
384
—
20
95
(13)

616 $

403 $
359
—
27
106
11

2,371
3
165
38
(81)
52

906 $

2,548

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 flows used by 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 flow used by financing activities of $69 million in 2016 included approximately $990
million of proceeds from the issuance of the 2016 Second-Out Credit Agreement, $108 million of net
proceeds from the Revolving Credit Facility, $350 million of scheduled and early payments on the Term
Loan Facility and $821 million of debt repurchases and related costs. Our net cash flow provided by
financing activities of $352 million in 2015 primarily included approximately $379 million of net
proceeds on the Revolving Credit Facility, partially offset by 2015 debt repurchase and amendment
costs of $23 million and $12 million in cash dividends paid.

Year Ended December 31, 2015 vs. 2014

Our net cash provided by operating activities in 2015 decreased by $2.0 billion from $2.4 billion in
2014 to $403 million in 2015. The decrease reflected approximately $1.8 billion in lower sales primarily
due to lower oil prices and lower NGL and natural gas prices and volumes and $360 million of higher
interest payments, partially offset by lower operating costs. Additionally, changes in working capital
resulted in an approximate $290 million reduction in operating cash due to lower operating costs
resulting in lower year-end 2015 payables and lower accruals for payroll and bonuses in line with our
reduced workforce, partially offset by lower receivables from customers due to lower year-end 2015
product prices. Further, the 2014 positive working capital reflected the effect of higher operating,
general and administrative and other costs and related higher accruals from the previous year-end, in
line with a higher level of activity.

Our net cash flows used by investing activities decreased by approximately $1.6 billion from $2.3

billion in 2014 to $757 million in 2015. The decrease reflected reduced capital investments of $1.7
billion and lower acquisition costs of approximately $140 million, partially offset by approximately $200
million in 2014 capital investments paid in 2015.

Our net cash flow used by financing activities changed from $45 million used in 2014 to $352

million provided in 2015. The change is primarily due to 2015 net proceeds from the revolving credit
facility of $379 million, largely to fund the working capital uses to pay for the fourth quarter 2014 capital
investments and $8 million from the issuance of common stock, partially offset by 2015 debt
repurchase and amendment costs of $23 million and $12 million in cash dividends paid.

Acquisitions and Divestitures

In February 2017, we divested non-core assets resulting in $32 million of proceeds. Additionally,
we entered into a joint venture with a third party that is committed to invest $50 million initially and up
to an additional $200 million subject to agreement of the parties. The funds will be used to develop
certain of our oil and gas properties in exchange for a contribution of a net profits interest in such
properties. After the investor achieves its targeted rate of return, the interests revert back to us.

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

proceeds.

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.

During the year ended December 31, 2014, we paid approximately $290 million to acquire certain

producing and non-producing oil and gas properties, including oil and gas properties in the Ventura
Basin purchased for approximately $200 million in the fourth quarter of 2014.

2016 Capital Program and 2017 Capital Budget

In 2016, we invested approximately $75 million of capital, predominantly targeting projects in the
San Joaquin and Los Angeles basins, as compared to approximately $401 million in 2015. Virtually all
of our oil and gas 2016 capital was directed towards oil-weighted production consistent with 2015 and
2014. Of the total 2016 capital program, approximately $13 million was allocated to drilling wells, $18
million to capital workovers, $23 million to facilities and compression expansion (including $19 million
for a major turnaround of our power plant), $15 million to maintenance and occupational health, safety
and environmental projects and the rest to other items.

The table below sets forth our 2016 capital investments for the year ended December 31, 2016 (in

millions):

Basin:

San Joaquin
Los Angeles
Ventura
Sacramento

Basin Total

Other(a)

Total

Conventional

Primary Waterflood

Steamflood

Total

Unconventional
Primary

Other

Total Capital
Investments

6
—
7
3

—

5
8
1
—

—

4
7
—
—

—

15
15
8
3

—

12
—
—
—

—

— $
—
—
—

—

27
15
8
3

(a)

Includes $19 million for a major turnaround of our power plant.

We focused a substantial majority of our 2016 capital on our mature steamfloods, waterfloods and

capital workovers, all of which offer among the highest VCIs in our portfolio. We focus on creating
value and are committed to internally fund our capital budget with operating cash flows. Our low
decline assets plus our high level of operational control gives us the flexibility to adjust the level of such
capital investments as circumstances warrant. In mid-2016, global oil prices began to recover from the
apparent low point of this commodity cycle. The recovery further strengthened following the production
cuts announced at the November 2016 meeting of the OPEC. In light of these continuing results, we
began to increase our activity level beginning toward the end of the second half of 2016 and have
continued to do so in early 2017. We began 2017 with two rigs running (one each in the San Joaquin
and the Los Angeles basins). By the end of the first quarter of 2017, we anticipate having four rigs
running (three in the San Joaquin and one in the Los Angeles basin). We also plan to add an additional
rig in the Ventura basin by the third quarter of 2017. Our 2017 development program will focus
primarily on our core fields: Elk Hills; Wilmington; Kern Front; Buena Vista; and the delineation of
Kettleman North Dome. Based on the current market conditions, we increased our 2017 planned
capital program to $300 million from the $75 million invested in 2016. We have developed a dynamic
plan which can be scaled up or down depending on the price environment. For 2017, we have action
plans that can reduce our capital program to below $100 million or increase it as high as $500 million
based on conditions during the year.

Off-Balance-Sheet Arrangements

We have no 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 selling,
general and administrative expenses. For more information, see “Contractual Obligations.”

Contractual Obligations

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

2016. This summary indicates on- and off-balance-sheet obligations as of December 31, 2016.

Total

Payments Due by Year
2018 and
2019
(in millions)

2020 and
2021

2017

2022 and
thereafter

On-Balance Sheet
Long-term debt—principal amount
(Note 5)(a)
Other long-term liabilities(b)

Off-Balance Sheet
Operating leases
Purchase obligations(c)(d)

Total

5,268 $
159

100 $
12

1,397 $
19

1,754 $
15

2,017
113

112
340

16
74

30
219

16
16

50
31

5,879 $

202 $

1,665 $

1,801 $

2,211

(a) Excludes interest on the debt. As of December 31, 2016, interest on long-term debt totaling $2.0 billion is payable in the

following years: 2017—$380 million, 2018 and 2019—$743 million, 2020 and 2021—$627 million, 2022 and
thereafter—$206 million. The calculation of interest payable on the variable interest debt assumes the interest rate at
December 31, 2016 to be the applicable interest rate for the entire term. In performing the calculation, the Revolving
Credit Facility borrowings outstanding at December 31, 2016 of $847 million were assumed to be outstanding for the
entire term of the agreement.
Includes obligations under postretirement benefit and deferred compensation plans.

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

(d)

the normal course of business to secure pipeline capacity, drilling rigs and services.
Included in these obligations is a commitment to invest approximately $170 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 2017 capital program includes development plans for these properties,
and we expect to fulfill the minimum investment requirement.

Lawsuits, Claims, Contingencies and Commitments

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.

On April 21, 2016, a purported class action was filed against us in the United States District Court

for the Southern District of New York on behalf of all beneficial owners of our unsecured notes from
November 12, 2015 to the present. The complaint alleges that our December 2015 debt exchange
excluded non-qualified institutional holders in violation of the Trust Indenture Act of 1939 and related
law and, thereby, impaired their rights to receive principal and interest payments. The purported class
action seeks declaratory relief that the debt exchange and the liens securing the new notes are null
and void and that the debt exchange resulted in a default. The plaintiff also seeks monetary damages
and attorneys’ fees. We plan to vigorously defend against the claims made by the plaintiff.

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, 2016 and 2015 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, 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, 2016,
we are not aware of material indemnity claims pending or threatened against the Company.

Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with generally accepted accounting

principles requires management to select appropriate accounting policies and to make informed
estimates and judgments regarding certain items and transactions. Changes in facts and
circumstances or discovery of new information may result in revised estimates and judgments, and
actual results may differ from these estimates upon settlement. We consider the following to be our
most critical accounting policies and estimates that involve management’s judgment and that could
result in a material impact on the financial statements due to the levels of subjectivity and judgment.

Oil and Gas Properties

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 DD&A and any impairment charges. For assets acquired, initial PP&E cost is based on
fair values at the acquisition date.

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 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.

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

production method. We amortize acquisition costs over total proved reserves and capitalized
development and successful exploration costs over proved developed reserves.

Proved oil and gas reserves and production volumes are used as the basis for recording

depreciation and depletion of oil and gas producing properties. Proved reserves are those quantities of
oil and 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—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, we receive a share of
production from certain arrangements in the Wilmington field similar to production-sharing contracts to
recover costs and generally an additional share for profit. Our share of production and reserves from
these contracts decreases when product prices rise and increases when prices decline. Overall, our
net economic benefit from these contracts is greater at higher product prices. In other cases,

particularly with long-lived properties, lower product prices may lead to a situation where production of
a portion of proved reserves becomes uneconomic. For such properties, higher product prices typically
result in additional reserves becoming economic. 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.

Additionally, we perform impairment tests with respect to our 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. Apart from the effect of product prices, we believe our
approach to interpreting technical data regarding proved oil and gas reserves makes it more likely that
future proved reserves revisions will be positive rather than negative.

The most significant ongoing financial statement effect from a change in our oil and gas reserves
or impairment of the carrying value of our proved properties would be to the DD&A rate. For example,
a 5% increase or decrease in the amount of oil and gas reserves would change the DD&A rate by
approximately $1.00 per barrel, which would increase or decrease pre-tax income (loss) by
approximately $35 million annually based on production rates for the year ended December 31, 2016.

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

At December 31, 2016, the net capitalized costs attributable to unproved properties were
approximately $300 million. The unproved amounts are not subject to DD&A until they are classified as
proved properties. However, 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 timing of any write-downs of unproved
properties, if warranted, depends upon management’s plans, the nature, timing and extent of future
exploration and development activities and their results. We believe our current plans and exploration
and development efforts will allow us to realize the carrying value of our unproved property balance at
December 31, 2016.

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. 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.

At year-end 2014, we performed impairment tests with respect to our proved and unproved

properties as a result of significant declines in oil prices largely during the last half of 2014.
Consequently, in the fourth quarter of 2014, we recorded pre-tax asset impairment charges of $3.4
billion on certain proved and unproved properties throughout our asset base. Approximately $650
million of the charge was related to unproved properties.

In 2015 and 2014, 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. To the extent prices recover to levels above
those year-end forward price curves, we would expect a substantial portion of these assets would
ultimately become economic.

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 primarily apply the market approach for
recurring fair value measurement, maximize our use of observable inputs and minimize use of
unobservable inputs. We generally use an income approach to measure fair value when observable
inputs are unavailable. This approach utilizes management’s judgments regarding expectations of
projected cash flows and discounts those cash flows using a risk-adjusted discount rate.

The most significant items on our balance sheet that would be affected by recurring fair value
measurements are derivatives. 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 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. Based on
the $97 million net derivative liability as of December 31, 2016, a 10% increase or decrease in their fair
value would affect pre-tax earnings by approximately $10 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.

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. See ‘‘Item 7—Lawsuits, Claims, Contingencies and Commitments’’ for additional information.

Significant Accounting and Disclosure Changes

During 2016, the Financial Accounting Standards Board (FASB) issued rules clarifying the new
revenue recognition standard issued in 2014. Under the new standard, an entity will recognize revenue
when it transfers promised goods or services to customers in an amount that reflects the consideration
to which the entity expects to be entitled in exchange for those goods or services. The new standard
also requires more detailed disclosures related to the nature, timing, amount and uncertainty of
revenue and cash flows arising from contracts with its customers. We will adopt these rules when they
become effective for interim and annual reporting periods beginning with our first quarter of 2018. We
believe the implementation of these rules will not have a material impact on the timing or net amounts
of our commodity sales. However, we will enhance our disclosures to meet the new requirements.

In August 2016, the FASB issued rules that modify how certain cash receipts and cash payments

are presented and classified in the statement of cash flows. These rules are effective for fiscal years
beginning after December 15, 2017 and interim periods within those fiscal years, with earlier adoption
permitted. We are currently evaluating the impact of these rules on our financial statements.

In June 2016, the FASB issued rules that change how entities will measure credit losses for

certain financial assets and other instruments that are not measured at fair value. These rules are
effective for fiscal years beginning after December 15, 2019, including interim periods within those
fiscal years, with early adoption permitted. We are currently evaluating the impact of these rules on our
financial statements.

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 2016, the FASB issued rules that modify how entities measure equity investments and
present changes in the fair value of financial liabilities. Unless the investments qualify for a practicality
exception, the new rules require all equity investments to be measured at fair value with changes in the
fair value recognized through net income (other than those accounted for under the equity method of
accounting or those that result in consolidation of the investee). Entities will have to record changes in
instrument-specific credit risk for financial liabilities measured under the fair value option in other
comprehensive income. These new rules become effective for fiscal years beginning after
December 15, 2017 with no early adoption permitted. We do not expect the adoption of these rules to
have a significant impact on our financial statements.

ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

General

Our results are sensitive to fluctuations in oil, NGL and gas prices. We expect that in 2017 price
changes at current levels of production and prices, including the impact of existing hedges, will affect
our pre-tax annual income and cash flows consistent with the following table:

Pre-tax 2017 Price Sensitivities

$1 change in Brent index - Oil(a)
$1 change in Brent index - NGLs
$0.50 change in NYMEX - Gas

On Income

On Cash

$18.0 million
$2.8 million
$11.8 million

(a) Amounts reflect the sensitivity with respect to unhedged barrels at a Brent index price exceeding $56.00 a barrel and

include the effect of production sharing type contracts in our Wilmington field operations. At a Brent index price between
$50.00 and $56.00 the sensitivity is $21 million and below $50.00 the sensitivity is $16 million.

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, 2016, we had a net derivative liability of $97 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
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, 2016, the substantial majority of the credit exposures related to our business
was with investment grade counterparties. We believe exposure to credit-related losses related to our
business at December 31, 2016 was not material and losses associated with credit risk have been
insignificant for all years presented.

Concentration of Credit Risk

Through July 2014, substantially all of our products were sold through Occidental’s marketing

subsidiaries at market prices and were settled at the time of sale to those entities. Beginning August
2014, we began marketing our own products directly to third parties. For the year ended December 31,
2014, sales through Occidental subsidiaries accounted for approximately 65% of our net sales,
respectively. For the year ended December 31, 2016, Phillips 66 Company, 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 at least 10%, and collectively, 64% of our revenue. For the year
ended December 31, 2014, ConocoPhillips/Phillips 66 Company and Tesoro Refining & Marketing
Company LLC each accounted for at least 10%, and, collectively, 45% of our revenue.

Interest Rate Risk

As of December 31, 2016, we had borrowings of $1.5 billion outstanding under our 2014 First-Out

Credit Facilities and approximately $1 billion outstanding under our 2016 Second-Out Credit
Agreement, both 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, 2016 (in millions):

Year of Maturity

2017
2018
2019
2020
2021
Thereafter

Total

Weighted-average interest rate

Fair Value

FORWARD-LOOKING STATEMENTS

U.S. Dollar
Fixed-Rate
Debt

U.S. Dollar
Variable-
Rate Debt

— $
—
—
193
561
2,017

100
100
1,297
—
1,000
—

2,771

2,497

Total

100
100
1,297
193
1,561
2,017

5,268

7.53%

6.91%

7.24%

2,390

2,497

4,887

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

(cid:129)

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

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

(cid:129)

operations and operational results
including production, hedging, capital
investment and expected VCI
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)
(cid:129)

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,
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 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 should not be relied on unduly. 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 on Consolidated and Combined
Financial Statements

To the Board of Directors and Stockholders
California Resources Corporation:

We have audited the accompanying consolidated balance sheets of California Resources
Corporation and subsidiaries (the Company) as of December 31, 2016 and 2015, and the related
consolidated and combined statements of operations, comprehensive income, equity and cash flows
for each of the years in the three-year period ended December 31, 2016. These consolidated and
combined financial statements are the responsibility of the Company’s management. Our responsibility
is to express an opinion on these consolidated and combined financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated and combined financial statements referred to above present

fairly, in all material respects, the financial position of California Resources Corporation and
subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash
flows for each of the years in the three-year period ended December 31, 2016, in conformity with
U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting

Oversight Board (United States), California Resources Corporation’s internal control over financial
reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated
Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated February 24, 2017 expressed an unqualified opinion on the
effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Los Angeles, California
February 24, 2017

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial
Reporting

To the Board of Directors and Stockholders
California Resources Corporation:

We have audited California Resources Corporation’s (the Company) internal control over financial

reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated
Framework issued in 2013 by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). California Resources Corporation’s management is responsible 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 internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained
in all material respects. Our audit 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 audit also included
performing such other procedures as we considered necessary in the circumstances. We believe that
our audit provides a reasonable basis for our opinion.

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.

In our opinion, California Resources Corporation maintained, in all material respects, effective

internal control over financial reporting as of December 31, 2016, based on criteria established in
Internal Control—Integrated Framework issued in 2013 by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of California Resources Corporation
and subsidiaries as of December 31, 2016 and 2015, and the related consolidated and combined
statements of operations, comprehensive income, equity and cash flows for each of the years in the
three-year period ended December 31, 2016, and our report dated February 24, 2017 expressed an
unqualified opinion on those consolidated and combined financial statements.

Los Angeles, California
February 24, 2017

/s/ KPMG LLP

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
As of December 31, 2016 and 2015
(in millions, except share data)

CURRENT ASSETS

Cash and cash equivalents
Trade receivables, net
Inventories
Other current assets

Total current assets

PROPERTY, PLANT AND EQUIPMENT

Accumulated depreciation, depletion and amortization

Total property, plant, equipment

OTHER ASSETS

TOTAL ASSETS

CURRENT LIABILITIES

Current maturities of long-term debt
Accounts payable
Accrued liabilities
Current income taxes

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, 2016 or 2015

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

outstanding shares (2016—42,542,637 shares and 2015—38,818,048
shares)

Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss

Total equity

2016

2015

12 $

232
58
123

425

12
200
58
168

438

20,915
(15,030)

20,996
(14,684)

5,885

6,312

303

6,354 $

7,053

100 $
219
407
—

726

5,168

397

620

100
257
222
26

605

6,043

491

830

—

—
4,861
(5,404)
(14)

(557)

—
4,782
(5,683)
(15)

(916)

TOTAL LIABILITIES AND EQUITY

6,354 $

7,053

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated and Combined Statements of Operations
For the years ended December 31, 2016, 2015 and 2014
(in millions, except share data)

REVENUES AND OTHER
Oil and gas net sales
Oil and gas sales to related parties
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 LOSS

NON-OPERATING INCOME (LOSS)
Interest and debt expense, net
Net gains on early extinguishment of debt
Other non-operating income (expense)

INCOME (LOSS) BEFORE INCOME TAXES
Income tax benefit

NET INCOME (LOSS)

Net income (loss) per share of common stock
Basic
Diluted

Dividends per common share

2016

2015

2014

$ 1,621 $

—
(206)
132

2,134 $
—
133
136

1,547

2,403

800
248
559
—
144
23
79

1,853

951
354
1,004
4,852
180
36
168

7,545

1,447
2,617
(5)
114

4,173

1,057
302
1,198
3,402
217
139
207

6,522

(306)

(5,142)

(2,349)

(328)
805
30

201
78

(326)
20
(28)

(5,476)
1,922

(72)
—
—

(2,421)
987

279 $ (3,554) $

(1,434)

6.76 $ (92.79) $
6.76 $ (92.79) $

(37.54)
(37.54)

— $

0.30 $

—

$
$

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated and Combined Statements of Comprehensive Income
For the years ended December 31, 2016, 2015 and 2014
(in millions)

Net income (loss)
Other comprehensive income (loss) items:

Unrealized (losses) gains on derivatives(a)
Pension and postretirement (losses) gains(b)
Reclassification to income of realized losses (gains) on

derivatives(c)

Reclassification to income of realized losses (gains) on

pensions(d)

Other comprehensive income, net of tax

Comprehensive income (loss)

2016

2015

2014

279 $

(3,554) $

(1,434)

—
(9)

—

—
(2)

—

(2)
(1)

—

280 $

(3,545) $

(1,434)

(a) Net of tax of zero for 2016 and 2015, respectively, and $1 million for 2014.
(b) Net of tax of zero, $1 million and $1 million for 2016, 2015 and 2014, respectively. See Note 13, Retirement and

Postretirement Benefit Plans, for additional information.

(c) Net of tax of zero for 2016 and 2015, respectively, and $(2) million in 2014.
(d) Net of tax of zero, $(7) million and zero for 2016, 2015 and 2014, respectively. See Note 13, Retirement and

Postretirement Benefit Plans, for additional information.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated and Combined Statements of Equity
For the years ended December 31, 2016, 2015 and 2014
(in millions)

Common
Stock

Additional
Paid-in
Capital

Accumulated
Deficit

Accumulated
Other
Comprehensive
Income (Loss)

Net Parent
Company
Investment

Total
Equity/Net
Investment

$ — $

—

—
—

—

— $
—

— $

(2,117)

(24)
—

10,013 $
683

9,989
(1,434)

—
—

—

—
—

—

—
—

—

56
(6,000)

—

4,752

—

(4,752)

—

$ — $

—

$ — $

—

4,752 $
—

(2,117)
(3,554)

(24)
—

— $
—

2,611
(3,554)

—

(12)

—

(12)

4,782 $
—

(5,683)
279

(15)
—

— $
—

(916)
279

—

Balance, December 31,

2013
Net income (loss)(a)
Net contributions from

Occidental(b)

Dividend to Occidental
Issuance of common
stock at Spin-off
Reclassification of net
parent company
investment to
additional paid-in
capital

Balance, December 31,

2014
Net income (loss)
Other comprehensive
income, net of tax
Dividends on common

stock

Issuance of common

stock and other, net

Balance, December 31,

2015
Net income (loss)
Other comprehensive
income, net of tax
Dividends on common

stock

Issuance of common

stock and other, net

Balance, December 31,

2016

$ — $

4,861 $

(5,404)

(14)

— $

(557)

(a) Net income of $683 million related to operations from January 1, 2014 through the spin-off date of November 30, 2014
was included in Net Parent Company Investment. The net loss of $2,117 million for the month ended December 31,
2014 reflected our accumulated deficit as of that date as a stand-alone company.

(b) Net contributions from Occidental include non-cash contributions of approximately $400 million, predominantly trade

receivables, partially offset by $335 million in cash distributions to Occidental.

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES
Consolidated and Combined Statements of Cash Flows
For the years ended December 31, 2016, 2015 and 2014
(in millions)

CASH FLOW FROM OPERATING ACTIVITIES

Net income (loss)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization
Asset impairments
Deferred income tax benefit
Net derivative losses (gains)
Net proceeds (payments) on settled derivatives
Net gains on early extinguishment of debt
Deferred gain and issuance costs amortization
Other non-cash tax provision
Other non-cash losses in income, net
Dry hole expenses

Changes in operating assets and liabilities, net:

(Increase) decrease in receivables, net
(Increase) decrease in inventories
(Increase) decrease in other current assets
Increase (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 by investing activities

CASH FLOW FROM FINANCING ACTIVITIES

Proceeds from revolving credit facility
Repayments of revolving credit facility
Issuance of senior notes
Issuance of term loans
Debt repurchases
Payments on first-lien first-out term loan
Debt transaction costs
Issuance of common stock
Cash dividends paid
Distributions to Occidental, net
Dividends to Occidental

Net cash provided (used) by financing activities

(Decrease) increase in cash and cash equivalents
Cash and cash equivalents—beginning of year

2016

2015

2014

279 $

(3,554) $

(1,434)

559
—
(78)
206
77
(805)
(41)
—
41
3

(33)
—
25

(103)

130

(75)
(6)
20
—

(61)

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

(69)

—
12

1,004
4,852
(2,258)
(133)
81
(20)
7
310
200
9

99
—
18

(212)

403

(401)
(205)
—
(151)

(757)

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

352

(2)
14

1,198
3,402
(1,152)
5
(2)
—
—
—
113
101

146
2
(133)

125

2,371

(2,089)
69
—
(292)

(2,312)

515
(155)
5,000
1,000
—
—
(70)
—
—
(335)
(6,000)

(45)

14
—

Cash and cash equivalents—end of year

12 $

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

CALIFORNIA RESOURCES CORPORATION AND SUBSIDIARIES

Notes to Consolidated and Combined 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 the state of 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. Prior to November 30, 2014, all material
existing assets, operations and liabilities of Occidental’s California business were consolidated under
us. On November 30, 2014, Occidental distributed shares of our common stock on a pro-rata basis to
Occidental stockholders and we became an independent, publicly traded company (the Spin-off).
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

Basis of Presentation

The assets and liabilities in the consolidated and combined financial statements are presented on

a historical cost basis. We have eliminated all of our significant intercompany transactions and
accounts. Prior to the Spin-off, we participated in Occidental’s centralized treasury management
program and had not incurred any debt. Additionally, excess cash generated by our business was
distributed to Occidental, and likewise our cash needs were provided by Occidental in the form of
contributions.

All financial information represents our post Spin-off stand-alone consolidated financial position,

results of operations and cash flows, except as follows:

(cid:129) Our consolidated and combined statements of operations, comprehensive income and cash

flows for the year ended December 31, 2014 consist of the consolidated results for the month
ended December 31, 2014 and the combined results of the California business prior to the
Spin-off.

(cid:129) Our consolidated and combined statement of changes in equity for the year ended

December 31, 2014 consists of both the California business prior to the Spin-off and our
consolidated activity subsequent to the Spin-off.

Certain prior year amounts have been reclassified to conform to the 2016 presentation. In 2016,
we reclassified net derivative gains (losses) out of other revenue to its own line item. Prior period gains
(losses) on debt transactions were reclassified from other expenses, net, to gains on early
extinguishment of debt. We also reclassified transaction costs related to our 2015 debt exchange from
other expenses, net, to other non-operating income (expense). The current portion of deferred taxes of
$59 million as of December 31, 2015 was also reclassified from other current assets to other assets in
accordance with the retrospective application of recently adopted accounting rules.

Risks and Uncertainties

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

accounting principles requires management to 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.

Revenue Recognition

We recognize revenue from oil and natural gas production when 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.

Net Parent Company Investment

Prior to the Spin-off, our balance sheets included net parent company investment, which

represented Occidental’s historical investment in us, our accumulated net income and the net effect of
transactions with, and allocations from, Occidental.

Inventories

Materials and supplies are valued at weighted-average cost and are reviewed periodically for
obsolescence. Finished goods include oil and natural gas products, which are valued at the lower of
cost or market.

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.

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.

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

2016

2015
(in millions)

2014

6 $

4 $

—
(3)

(5)
(9)

Balance—end of year

4 $

6 $

(8)
(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.

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

production method. We amortize acquisition costs over total proved reserves, and capitalized
development and successful exploration costs over proved developed reserves. Substantially all of our
total depreciation, depletion and amortization expense relates to production costs.

Proved oil and gas reserves and production volumes are used as the basis for recording
depreciation and depletion of oil and gas properties. 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.

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.

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.

We evaluate these 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. At December 31, 2016, the net
capitalized costs attributable to unproved properties were approximately $300 million. 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. 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 timing of any write-
downs of these 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.

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. 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.

At year-end 2014, we performed impairment tests with respect to our proved and unproved

properties as a result of significant declines in oil prices largely during the last half of 2014. As a result,
in the fourth quarter of 2014, we recorded pre-tax asset impairment charges of $3.4 billion on certain
proved and unproved properties throughout our asset base. Approximately $650 million of the charge
was related to unproved properties.

100

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 to
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 depreciated over the useful life of the asset.

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 $397
million and $343 million is included in other long-term liabilities, with the remaining current portion in
accrued liabilities at December 31, 2016 and 2015, 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

Derivative Instruments

For the years ended
December 31,
2015
2016

(in millions)
357 $
2
(10)
22
(17)
57

411 $

415
7
(18)
20
—
(67)

357

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 in
earnings in the current period and are reported on a net basis in the statements of operations.

Stock-Based Incentive Plans

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

that are more fully described in Note 10. A summary of our accounting policy for awards issued under
our plans is as follows.

101

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, 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. Estimates of fair value are not intended to, and may not,
accurately predict the value ultimately realized by employees who receive the awards, and the ultimate
value may not be indicative of the reasonableness of the original estimates of fair value made by us.

The performance targets under the 2015 Performance Stock Unit (PSU) awards are 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 cash-settled
awards accounted for as liability awards until they were modified in 2016 and became stock-settled
awards accounted for as equity awards. Dividend equivalents, if any, declared during the vesting
period are accumulated and paid upon certification, for the number of vested shares.

Prior to the modification, the fair value of the VCI-based portions of the PSU were initially
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 PSU were initially 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. 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. Estimates of fair value are not intended to, and may not,
accurately predict the value ultimately realized by the employees who receive the awards, and the
ultimate value may not be indicative of the reasonableness of the original estimates of fair value made
by us. 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. All such performance or stock-price-related changes were recognized in
compensation expense.

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.

For cash-settled restricted stock units (RSU), compensation value is initially measured on the
grant date using the quoted market price of our common stock, which is then recognized on a straight-
line basis over the requisite service periods, adjusted for actual forfeitures. Compensation expense is
adjusted on a quarterly basis for the cumulative changes in the value of the underlying stock.

102

For stock-settled RSU and restricted stock awards, compensation value is initially measured on

the grant date using the quoted market price of our common stock, which is then recognized on a
straight-line basis over the requisite service periods, adjusted for actual forfeitures.

For performance-based restricted stock awards, compensation value is initially measured on the

grant date using the quoted market price of our common stock and estimated performance
achievement based on a cumulative EBITDA target, which is then recognized on a straight-line basis
over the requisite service period, adjusted for actual forfeitures.

For all of our awards with nonforfeitable dividend rights (except for PSU awards noted above),

dividends or dividend equivalents declared during the vesting period are paid as declared.

Earnings Per Share

We compute basic earnings per share (EPS) by dividing net income available to common
stockholders by the weighted-average common shares outstanding during the period and compute
diluted EPS by dividing earnings available to common stockholders by the weighted-average shares
outstanding during the period and the impact of securities that, if exercised, would have a dilutive effect
on EPS.

We compute basic EPS under the two-class method, which is a method of computing EPS when

an entity has both common stock and participating securities. We consider unvested restricted stock as
a participating security if it contains rights to receive non-forfeitable dividends at the same rate as
common stock. Under the two-class method, we exclude any income and distributions attributable to
participating securities from the calculation of basic and diluted EPS and exclude the participating
securities from the weighted-average shares outstanding.

Retirement and Postretirement Benefit Plans

Prior to the Spin-off, a majority of our employees participated in postretirement benefit plans
sponsored by Occidental, which included participants from other Occidental subsidiaries. These plans
had an insignificant amount of assets and were substantially funded as benefits were paid. We
recognized a liability in the accompanying balance sheets for the employees of the California business.
The related postretirement expenses were allocated to us from Occidental based on the employees of
the California business. Following the Spin-off, all of our employees participate in postretirement
benefit plans sponsored by us. These plans are funded as benefits are paid.

For defined benefit pension and postretirement plans that are 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.

103

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 and discounts those 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.

Our property, plant and equipment is written down to fair value if we determine that there has been

The carrying amounts of cash and other on-balance sheet financial instruments, other than fixed-

rate debt, approximate fair value.

Income Taxes

Until the Spin-off, our taxable income was historically included in the consolidated U.S. federal
income tax returns of Occidental and in a number of their consolidated state income tax returns. In the
accompanying financial statements, our provision for income taxes through the Spin-off is computed as
if we were a stand-alone tax-paying entity.

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 recorded 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 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.

104

Other Current Assets

Other current assets at December 31, 2016 and 2015 included net amounts due from joint interest
partners of $44 million and $42 million, derivative assets from commodities contracts of $39 million and
$87 million and prepaid expenses of $14 million and $26 million, respectively.

Accrued Liabilities

Accrued liabilities reflected derivative liabilities from commodities contracts of $103 million and $1

million at December 31, 2016 and 2015, respectively; greenhouse gas obligations of $89 million and $6
million at December 31, 2016 and 2015, respectively; accrued employee-related costs of $91 million
and $105 million at December 31, 2016 and 2015, respectively, and accrued interest of $25 million and
$39 million at December 31, 2016 and 2015, respectively.

Supplemental Cash Flow Information

We have not made United States federal and state income tax payments in 2016 and 2015 due to
the taxable loss we incurred. Until the Spin-off, our share of Occidental’s tax payments or refunds were
paid or received, as applicable, by Occidental. During the year ended December 31, 2014, Occidental
paid approximately $165 million on our behalf. We also paid taxes other than on income, consisting
mostly of property taxes, of approximately $115 million, $154 million and $183 million during the years
ended December 31, 2016, 2015 and 2014, respectively. Interest paid totaled approximately $384
million, $359 million and $3 million, respectively, for the years ended December 31, 2016, 2015 and
2014.

In 2014, Occidental transferred to us certain assets, liabilities and accruals, of which the most
significant consisted of outstanding trade receivables of approximately $400 million. These non-cash
transfers and the corresponding net contribution to us from Occidental were excluded from net cash
provided by operating activities and cash flow from financing activities.

Major Customers

For the year ended December 31, 2016, Phillips 66 Company, 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 at least 10%, and collectively, 64% of our revenue. For the year
ended December 31, 2014, ConocoPhillips/Phillips 66 Company and Tesoro Refining & Marketing
Company LLC each accounted for at least 10%, and, collectively, 45% of our revenue.

Reverse Stock Split

We completed a reverse stock split on May 31, 2016 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.

105

NOTE 2 ACCOUNTING AND DISCLOSURE CHANGES

Recently Issued Accounting and Disclosure Changes

During 2016, the Financial Accounting Standards Board (FASB) issued rules clarifying the new
revenue recognition standard issued in 2014. Under the new standard, an entity will recognize revenue
when it transfers promised goods or services to customers in an amount that reflects the consideration
to which the entity expects to be entitled in exchange for those goods or services. The new standard
also requires more detailed disclosures related to the nature, timing, amount and uncertainty of
revenue and cash flows arising from contracts with its customers. We will adopt these rules when they
become effective for interim and annual reporting periods beginning with our first quarter of 2018. We
believe the implementation of these rules will not have a material impact on the timing or net amounts
of our recurring commodity sales. However, we will enhance our disclosures to meet the new
requirements.

In August 2016, the FASB issued rules that modify how certain cash receipts and cash payments

In June 2016, the FASB issued rules that change how entities will measure credit losses for

In February 2016, the FASB issued rules requiring lessees to recognize assets and liabilities on

Recently Adopted Accounting and Disclosure Changes

In March 2016, the FASB simplified several aspects of the accounting for employee share-based

payment transactions, including the accounting for income taxes, forfeitures, and statutory tax
withholding requirements, as well as classification in the statement of cash flows. We adopted these
rules in 2016 with no material changes reflected in our financial statements.

106

In November 2015, the FASB issued rules requiring that deferred income tax liabilities and assets

be classified as noncurrent in a classified balance sheet. We adopted the new rule in 2016 and
reclassified the current portion of deferred tax assets of $59 million as of December 31, 2015 from
other current assets to other assets.

In August 2014, the FASB issued rules relating to management’s responsibility to evaluate and
make disclosures, if applicable, regarding the entity’s ability to continue as a going concern within one
year after the date that the financial statements are issued. We adopted these rules in 2016 with no
material changes reflected in our financial statements.

In June 2014, the FASB issued rules for employee share-based payment awards in which the
terms of the awards provide that a performance target can be achieved after the requisite service
period. A performance target that affects vesting and that could be achieved after the requisite service
period will be treated as a performance condition. We adopted these rules in 2016 with no material
changes reflected in our financial statements.

NOTE 3 ACQUISITIONS AND DIVESTITURES

2016

During the year ended December 31, 2016, there were no acquisitions. However, we divested

non-core assets resulting in $20 million of proceeds and a $30 million gain included in other non-
operating income (expense).

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.

2014

During the year ended December 31, 2014, we paid approximately $290 million to acquire certain

producing and non-producing oil and gas properties, including oil and gas properties in the Ventura
basin purchased for approximately $200 million in the fourth quarter of 2014.

NOTE 4 INVENTORIES

Inventories consisted of the following:

Materials and supplies
Finished goods

Total

107

Balance at December 31,

2016

2015

(in millions)
55 $
3

58 $

55
3

NOTE 5 DEBT

Debt consisted of the following:

2014 First-Out Credit Facilities (Secured First Lien)

Revolving Credit Facility
Term Loan Facility

2016 Second-Out Credit Agreement (Secured First Lien)
Senior Notes (Secured Second Lien)

8% Notes Due 2022
Senior Unsecured Notes
5% Notes Due 2020
5 1⁄ 2% Notes Due 2021
6% Notes Due 2024

Total Debt—Principal Amount

Less Current Maturities of Long-Term Debt

Long-Term Debt—Principal Amount

December 31,
2015
2016

(in millions)

847 $
650
1,000

739
1,000
—

2,250

193
135
193

433
829
892

5,268
(100)

6,143
(100)

$ 5,168 $ 6,043

At 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.
The December 31, 2015 deferred gain and issuance costs were $491 million net, consisting of $560
million of deferred gains offset by $69 million of deferred issuance costs.

Credit Facilities

2014 First-Out Credit Facilities

Our first-lien, first-out credit facilities (2014 First-Out Credit Facilities) comprise (i) a $650 million
senior term loan facility (the Term Loan Facility) and (ii) a $1.4 billion senior revolving loan facility (the
Revolving Credit Facility). We are permitted to increase the size of the Revolving Credit Facility by up
to $250 million if we obtain additional commitments from new or existing lenders. The facilities mature
at the earlier of November 2019 and the 182nd day prior to the maturity of our 5% senior unsecured
notes due January 15, 2020 (2020 notes), to the extent more than $100 million of such notes remain
outstanding at such date. The Revolving Credit Facility includes a sub-limit of $400 million for the
issuance of letters of credit. Our credit limit under our 2014 First-Out Credit Facilities is $2.05 billion.
Borrowings under these facilities are also subject to a borrowing base, which was reaffirmed at $2.3
billion as of November 1, 2016.

As of December 31, 2016 and 2015, we had outstanding borrowings of $847 million and $739

million under our Revolving Credit Facility, and $650 million and $1 billion under the Term Loan
Facility, respectively. At December 31, 2016, we had $1 billion outstanding under a new first-lien,
second-out term loan credit facility (2016 Second-Out Credit Agreement). We made payments on the
Term Loan Facility during each of the four quarters in 2016 totaling $100 million and a $250 million
prepayment from proceeds of the 2016 Second-Out Credit Agreement.

108

additional collateral to our lenders and permit the incurrence of debt under the 2016 Second-Out Credit
Agreement and in February 2017 to facilitate additional joint venture transactions and note
repurchases, eliminate our capital expenditure restriction and adopt a minimum liquidity covenant.

Our financial performance covenants under the 2014 First-Out Credit Facilities require that (i) the

ratio of our first-lien, first-out secured debt to trailing four quarter EBITDAX (the First-Lien First-Out
Leverage Ratio) not exceed 3.50 to 1.00 at any quarter end through the quarter ending June 30, 2017
and 3.25 to 1.00 for the quarters ending September 30 and December 31, 2017 and (ii) the total
interest expense coverage ratio at each quarter end not be less than 1.20 to 1.00 at any quarter end
through the quarter ending December 31, 2017. Beginning with the end of the first quarter of 2018, the
First-Lien First-Out Leverage Ratio may not exceed 2.25 to 1.00 and the total interest expense
coverage ratio may not be less than 2.00 to 1.00. The covenants also include a requirement that the
first-lien asset coverage ratio must be at least 1.20 to 1.00 as of any June 30 and December 31
beginning December 31, 2016 and a requirement that minimum monthly liquidity be not less than $250
million. As of January 31, 2017, we had approximately $486 million of liquidity, subject to the minimum
liquidity requirement.

We must apply 100% of the proceeds from asset sales to repay loans outstanding under the 2014
First-Out Credit Facilities; except that we are permitted to (i) use up to 50% (or, if our leverage ratio is
less than 4:00 to 1:00, 60%) of proceeds from non-borrowing base asset sales or monetizations to
repurchase our notes to the extent available at a significant minimum discount to par, as specified in
the facilities and (ii) purchase up to $140 million of certain of our unsecured notes at a discount. The
2014 First-Out Credit Facilities also permit us to incur up to an additional $50 million of non-facility
indebtedness, which may be secured by non-borrowing base assets, subject to compliance with our
financial covenants and indentures, the proceeds of which must be applied to repay the Term Loan
Facility. We must apply cash on hand in excess of $150 million daily to repay amounts outstanding
under our Revolving Credit Facility. Further, we are restricted from paying dividends or making other
distributions to common stockholders.

109

(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.

2016 Second-Out Credit Agreement

The net borrowings under the 2016 Second-Out Credit Agreement were used to (i) prepay $250

million of the Term Loan Facility and (ii) reduce our Revolving Credit Facility by $740 million. The
proceeds received were net of a $10 million original issue discount. The loan under the 2016 Second-
Out Credit Agreement bears interest at a floating rate per annum equal to 10.375% plus LIBOR,
subject to a 1.00% LIBOR floor, determined for the applicable interest period (or ABR rates in certain
circumstances). 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.

The 2016 Second-Out Credit Agreement is secured by a security interest in the same collateral
used to secure the 2014 First-Out Credit Facilities, but, under intercreditor arrangements with our 2014
First-Out Credit Facilities lenders, are second in collateral recovery behind such lenders. Prepayment
of the 2016 Second-Out Credit Agreement is subject to a make-whole premium prior to the third
anniversary of closing and a premium to par equal to 50% of coupon between the third anniversary and
the fourth anniversary. Following the fourth anniversary, we may redeem at par. The 2016 Second-Out
Credit Agreement matures on December 31, 2021, but if the aggregate principal amount outstanding of
either our 2020 Notes or our 5 1⁄ 2% senior unsecured notes due September 15, 2021 (2021 Notes)
exceeds $100 million 91 days prior to their respective maturity dates, the maturity date of the term
loans will accelerate to such prior 91st day. As of December 31, 2016, we had $193 million and $135
million in aggregate principal amount of outstanding 2020 notes and 2021 notes, respectively.

Senior Notes

In October 2014, we issued $5.00 billion in aggregate principal amount of our senior unsecured
notes, including $1.00 billion of 2020 notes, $1.75 billion of 2021 notes and $2.25 billion of 6% senior
unsecured notes due November 15, 2024 (the 2024 notes, and together with the 2020 notes and the
2021 notes, the unsecured notes). We used the net proceeds from the issuance of the unsecured
notes to make a $4.95 billion cash distribution to Occidental in October 2014.

In January and February 2016, we repurchased over $100 million in aggregate principal amount of
our unsecured notes for under $13 million in cash, for a gain of $87 million, net of related expenses. In

110

May 2016, we entered into privately negotiated exchange agreements with a holder of our 2024 notes
and our 2021 notes to exchange a total of approximately 2.1 million shares of our common stock on a
post-split basis for notes in the aggregate principal amount of $80 million, resulting in a $44 million pre-
tax gain, net of related expenses.