þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 001-36478
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Delaware
(State or other jurisdiction of
incorporation or organization)
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46-5670947
(I.R.S. Employer
Identification No.)
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27200 Tourney Road, Suite 315
Santa Clarita, California
(Address of principal executive offices)
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91355
(Zip Code)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock
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New York Stock Exchange
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Large Accelerated Filer
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þ
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Accelerated Filer
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¨
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Non-Accelerated Filer
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¨
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Smaller Reporting Company
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¨
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Emerging Growth Company
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¨
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Page
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Part I
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Items 1 & 2
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BUSINESS AND PROPERTIES
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Business Operations and Environment
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Our Business Strategy
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Our Strengths
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Our Operations
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Acreage
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Production, Price and Cost History
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Reserves
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Recovery Mechanisms
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Drilling Locations
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Drilling Statistics
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Productive Wells
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Exploration Program
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Marketing Arrangements
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Infrastructure
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Employees
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Regulation of the Oil and Natural Gas Industry
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Spin-Off and Reverse Stock Split
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Available Information
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Item 1A
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RISK FACTORS
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Item 1B
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UNRESOLVED STAFF COMMENTS
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Item 3
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LEGAL PROCEEDINGS
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Item 4
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MINE SAFETY DISCLOSURES
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EXECUTIVE OFFICERS
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Part II
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Item 5
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MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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Item 6
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SELECTED FINANCIAL DATA
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Item 7
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Basis of Presentation and Certain Factors Affecting Comparability
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Business Environment and Industry Outlook
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Seasonality
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Joint Ventures
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Acquisitions and Divestitures
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Income Taxes
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Production and Prices
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Balance Sheet Analysis
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Statement of Operations Analysis
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Liquidity and Capital Resources
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2018 and 2019 Capital Program
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Off-Balance-Sheet Arrangements
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Lawsuits, Claims, Commitments and Contingencies
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Critical Accounting Policies and Estimates
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Significant Accounting and Disclosure Changes
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FORWARD-LOOKING STATEMENTS
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Item 7A
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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Page
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Item 8
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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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Report of Independent Registered Public Accounting Firm
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Consolidated Balance Sheets
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Consolidated Statements of Operations
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Consolidated Statements of Comprehensive Income
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Consolidated Statements of Equity
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Consolidated Statements of Cash Flows
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Notes to Consolidated Financial Statements
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Quarterly Financial Data (Unaudited)
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Supplemental Oil and Gas Information (Unaudited)
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SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
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Item 9
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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
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Item 9A
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CONTROLS AND PROCEDURES
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Item 9B
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OTHER INFORMATION
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Part III
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Item 10
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DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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Item 11
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EXECUTIVE COMPENSATION
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Item 12
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
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Item 13
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
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Item 14
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PRINCIPAL ACCOUNTANT FEES AND SERVICES
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Part IV
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Item 15
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EXHIBITS
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ITEMS 1 & 2
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BUSINESS AND PROPERTIES
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•
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Utilize our technical knowledge and experience to target production growth, delineate expansion areas and optimize hydrocarbon recovery;
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•
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Use our Value Creation Index (VCI) metric to ensure consistent, disciplined and effective capital allocation;
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•
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Optimize operational performance through streamlined processes, application of technology and entrepreneurial thinking to capture efficiencies, improve results and reduce costs;
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Strengthen our balance sheet by investing to grow cash flow, simplifying our capital structure, pursuing value-accretive acquisitions and reducing absolute levels of our debt and fixed charges; and
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•
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Maintain a proactive and collaborative approach to safety, environmental protection and community outreach while helping California address its energy and water needs.
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•
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Operational control and a diverse asset base provide us with flexibility.
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•
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Largest acreage position in a world-class oil and natural gas province.
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•
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Extensive drilling and workover portfolio.
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•
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Proven operational management and technical teams with extensive experience operating in California.
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San Joaquin Basin
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Los Angeles Basin
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Ventura Basin
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Sacramento Basin
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Total Operations
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|||||
Acreage:
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|||||
Net mineral acreage
(thousands)
|
1,446
|
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|
30
|
|
|
247
|
|
|
517
|
|
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2,240
|
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Average net mineral acreage held in fee (%)
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66
|
%
|
|
46
|
%
|
|
74
|
%
|
|
38
|
%
|
|
60
|
%
|
|
|
|
|
|
|
|
|
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|||||
Number of fields
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49
|
|
|
8
|
|
|
27
|
|
|
53
|
|
|
137
|
|
Average net revenue interest (%)
(a)
|
90
|
%
|
|
73
|
%
|
|
83
|
%
|
|
78
|
%
|
|
86
|
%
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Average drilling rigs
|
7
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|
|
3
|
|
|
—
|
|
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—
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|
10
|
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Net wells drilled and completed
|
128.6
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|
|
48.2
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3.5
|
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|
—
|
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180.3
|
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|||||
Proved reserves:
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|||||
Oil (MMBbl)
|
317
|
|
|
173
|
|
|
40
|
|
|
—
|
|
|
530
|
|
NGLs (MMBbl)
|
57
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
60
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|
Natural Gas (Bcf)
|
621
|
|
|
13
|
|
|
32
|
|
|
68
|
|
|
734
|
|
Total (MMBoe)
|
478
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|
175
|
|
|
48
|
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|
11
|
|
|
712
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Oil percentage of proved reserves
|
66
|
%
|
|
99
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%
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|
83
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%
|
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—
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%
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|
74
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%
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|||||
Production:
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|||||
Total (MMBoe)
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35
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|
|
9
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|
|
2
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|
2
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|
48
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Average net daily production (MBoe/d)
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96
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|
25
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|
|
6
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|
5
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|
132
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Oil percentage of production
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55
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%
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|
100
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%
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|
67
|
%
|
|
—
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%
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|
62
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%
|
|
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|||||
Reserves to production ratio (years)
(b)
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13.7
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19.4
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24.0
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5.5
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14.8
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(a)
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The average net revenue interest represents our interest in production after taking into account royalties and similar burdens and third- party working interests.
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(b)
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Calculated as total proved reserves as of
December 31, 2018
divided by total production for the year ended
December 31, 2018
.
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San Joaquin Basin
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Los Angeles Basin
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Ventura Basin
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Sacramento Basin
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Total
|
|||||
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(in thousands)
|
|||||||||||||
Developed
(a)
|
|
|
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Gross
(b)
|
417
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|
|
21
|
|
|
63
|
|
|
266
|
|
|
767
|
|
Net
(c)
|
378
|
|
|
16
|
|
|
61
|
|
|
246
|
|
|
701
|
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Undeveloped
(d)
|
|
|
|
|
|
|
|
|
|
|
|
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Gross
(b)
|
1,297
|
|
|
17
|
|
|
222
|
|
|
355
|
|
|
1,891
|
|
Net
(c)
|
1,068
|
|
|
14
|
|
|
186
|
|
|
271
|
|
|
1,539
|
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Total
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|
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|
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|||||
Gross
(b)
|
1,714
|
|
|
38
|
|
|
285
|
|
|
621
|
|
|
2,658
|
|
Net
(c)
|
1,446
|
|
|
30
|
|
|
247
|
|
|
517
|
|
|
2,240
|
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(a)
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Acres spaced or assigned to productive wells.
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(b)
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Total number of acres in which interests are owned.
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(c)
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Sum of our fractional interests based on working interests or interests under PSC-type contracts.
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(d)
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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.
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|
Year Ended December 31,
|
||||||||||
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2018
|
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2017
|
|
2016
|
||||||
Average net daily production:
|
|
|
|
|
|
|
|
|
|||
Oil (MBbl/d)
(a)
|
82
|
|
|
83
|
|
|
91
|
|
|||
NGLs (MBbl/d)
|
16
|
|
|
16
|
|
|
16
|
|
|||
Natural gas (MMcf/d)
|
202
|
|
|
182
|
|
|
197
|
|
|||
Total net production (MBoe/d)
(b)
|
132
|
|
|
129
|
|
|
140
|
|
|||
|
|
|
|
|
|
||||||
Total production (MMBoe)
(a)(b)
|
48
|
|
|
47
|
|
|
51
|
|
|||
|
|
|
|
|
|
||||||
Average realized prices:
|
|
|
|
|
|
|
|
|
|||
Oil prices with hedge ($/Bbl)
|
$
|
62.60
|
|
|
$
|
51.24
|
|
|
$
|
42.01
|
|
Oil prices without hedge ($/Bbl)
|
$
|
70.11
|
|
|
$
|
51.47
|
|
|
$
|
39.72
|
|
NGLs prices ($/Bbl)
|
$
|
43.67
|
|
|
$
|
35.76
|
|
|
$
|
22.39
|
|
Natural gas prices ($/Mcf)
|
$
|
3.00
|
|
|
$
|
2.67
|
|
|
$
|
2.28
|
|
|
|
|
|
|
|
||||||
Average benchmark prices:
|
|
|
|
|
|
|
|
|
|||
Brent oil ($/Bbl)
|
$
|
71.53
|
|
|
$
|
54.82
|
|
|
$
|
45.04
|
|
WTI oil ($/Bbl)
|
$
|
64.77
|
|
|
$
|
50.95
|
|
|
$
|
43.32
|
|
NYMEX gas ($/MMBtu)
|
$
|
2.97
|
|
|
$
|
3.09
|
|
|
$
|
2.42
|
|
|
|
|
|
|
|
||||||
Average production costs per Boe
(b)
:
|
|
|
|
|
|
|
|
|
|||
Production costs
|
$
|
18.88
|
|
|
$
|
18.64
|
|
|
$
|
15.61
|
|
Production costs, excluding effects of PSC-type contracts
(c)
|
$
|
17.47
|
|
|
$
|
17.48
|
|
|
$
|
14.69
|
|
(a)
|
Our PSC-type contracts negatively impacted our oil production in 2018 by over 1 MBoe/d compared to 2017. The impact on our oil production was immaterial in 2017 compared to 2016.
|
(b)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas (Mcf) to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
(c)
|
The reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs. These amounts represent production costs after adjusting for the excess costs attributable to PSC-type contracts.
|
|
Elk Hills
|
|
Wilmington
|
||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
Average net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbl/d)
|
22
|
|
|
19
|
|
|
21
|
|
|
21
|
|
|
23
|
|
|
25
|
|
||||||
NGLs (MBbl/d)
|
12
|
|
|
13
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Natural gas (MMcf/d)
|
108
|
|
|
95
|
|
|
106
|
|
|
1
|
|
|
1
|
|
|
—
|
|
||||||
Total net production (MBoe/d)
|
52
|
|
|
48
|
|
|
52
|
|
|
21
|
|
|
23
|
|
|
25
|
|
||||||
Average realized prices
(a)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbl/d)
|
$
|
73.98
|
|
|
$
|
55.58
|
|
|
$
|
44.50
|
|
|
$
|
67.81
|
|
|
$
|
49.87
|
|
|
$
|
37.98
|
|
NGLs (MBbl/d)
|
$
|
43.58
|
|
|
$
|
36.26
|
|
|
$
|
23.03
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Natural gas (MMcf/d)
|
$
|
2.87
|
|
|
$
|
2.52
|
|
|
$
|
2.27
|
|
|
$
|
1.71
|
|
|
$
|
2.12
|
|
|
$
|
1.83
|
|
Production costs per Boe
(b)
|
$
|
12.07
|
|
|
$
|
11.76
|
|
|
$
|
10.48
|
|
|
$
|
29.81
|
|
|
$
|
27.91
|
|
|
$
|
22.27
|
|
Production costs per Boe, excluding effects of PSC-type contracts
(c)
|
N/A
|
|
N/A
|
|
N/A
|
|
$
|
21.02
|
|
|
$
|
21.59
|
|
|
$
|
17.21
|
|
(a)
|
Excludes the effect of hedges.
|
(b)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
(c)
|
The reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs. These amounts represent production costs after adjusting for the excess costs attributable to PSC-type contracts.
|
|
As of December 31, 2018
|
|||||||||||||
|
San Joaquin Basin
|
|
Los Angeles Basin
|
|
Ventura Basin
|
|
Sacramento Basin
|
|
Total
|
|||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
231
|
|
|
131
|
|
|
27
|
|
|
—
|
|
|
389
|
|
NGLs (MMBbl)
|
45
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
47
|
|
Natural Gas (Bcf)
|
473
|
|
|
9
|
|
|
23
|
|
|
60
|
|
|
565
|
|
Total (MMBoe)
(a)(b)
|
355
|
|
|
132
|
|
|
33
|
|
|
10
|
|
|
530
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
86
|
|
|
42
|
|
|
13
|
|
|
—
|
|
|
141
|
|
NGLs (MMBbl)
|
12
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
13
|
|
Natural Gas (Bcf)
|
148
|
|
|
4
|
|
|
9
|
|
|
8
|
|
|
169
|
|
Total (MMBoe)
(b)
|
123
|
|
|
43
|
|
|
15
|
|
|
1
|
|
|
182
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
317
|
|
|
173
|
|
|
40
|
|
|
—
|
|
|
530
|
|
NGLs (MMBbl)
|
57
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
60
|
|
Natural Gas (Bcf)
|
621
|
|
|
13
|
|
|
32
|
|
|
68
|
|
|
734
|
|
Total (MMBoe)
(b)
|
478
|
|
|
175
|
|
|
48
|
|
|
11
|
|
|
712
|
|
(a)
|
As of December 31, 2018, approximately
23%
of proved developed oil reserves,
9%
of proved developed NGLs reserves,
13%
of proved developed natural gas reserves and, overall,
20%
of total proved developed reserves are non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full peak production response has not yet occurred due to the nature of such projects.
|
(b)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
|
San Joaquin Basin
|
|
Los Angeles Basin
(a)
|
|
Ventura Basin
|
|
Sacramento Basin
|
|
Total
|
|||||
Balance at December 31, 2017
|
419
|
|
|
145
|
|
|
40
|
|
|
14
|
|
|
618
|
|
Revisions related to price
|
16
|
|
|
23
|
|
|
1
|
|
|
(2
|
)
|
|
38
|
|
Revisions related to performance
|
(8
|
)
|
|
8
|
|
|
5
|
|
|
1
|
|
|
6
|
|
Improved recovery
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Extensions and discoveries
|
18
|
|
|
8
|
|
|
4
|
|
|
—
|
|
|
30
|
|
Purchases
|
64
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
64
|
|
Sales
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(35
|
)
|
|
(9
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
(48
|
)
|
Balance at December 31, 2018
|
478
|
|
|
175
|
|
|
48
|
|
|
11
|
|
|
712
|
|
Note:
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
(a)
|
Includes proved reserves related to PSC-type contracts of
131
MMBoe and 108 MMBoe at December 31, 2018 and 2017, respectively.
|
|
San Joaquin Basin
|
|
Los Angeles Basin
|
|
Ventura Basin
|
|
Sacramento Basin
|
|
Total
|
|||||
Balance at December 31, 2017
|
125
|
|
|
40
|
|
|
11
|
|
|
2
|
|
|
178
|
|
Revisions related to performance
|
(15
|
)
|
|
1
|
|
|
4
|
|
|
—
|
|
|
(10
|
)
|
Revisions related to price changes
|
2
|
|
|
2
|
|
|
(4
|
)
|
|
(1
|
)
|
|
(1
|
)
|
Extensions and discoveries
|
12
|
|
|
5
|
|
|
4
|
|
|
—
|
|
|
21
|
|
Improved recovery
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Purchases
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
Transfers to proved developed reserves
|
(21
|
)
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(26
|
)
|
Balance at December 31, 2018
|
123
|
|
|
43
|
|
|
15
|
|
|
1
|
|
|
182
|
|
Note:
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
|
As of December 31, 2018
|
||
|
(in millions)
|
||
Standardized measure of discounted future net cash flows
|
$
|
7,275
|
|
Present value of future income taxes discounted at 10%
|
2,136
|
|
|
PV-10 of proved reserves
|
$
|
9,411
|
|
Organic reserve replacement ratio
(a)
|
127
|
%
|
|
All-in reserve replacement ratio
(b)
|
296
|
%
|
(a)
|
The organic reserve replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries, improved recovery and performance-related revisions (excluding 21 MMBoe of PUDs downgraded at management's discretion), divided by oil-equivalent production. There is no guarantee that historical sources of reserves additions will continue as many factors are fully or partially outside management's control, including commodity prices, availability of capital and the underlying geology, all of which affect reserves additions. Management uses this measure to gauge the results of its capital program. Other oil and gas producers may use different methods to calculate replacement ratios, which may affect comparability.
|
(b)
|
The all-in reserve replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries, improved recovery, revisions and purchases, divided by oil-equivalent production. There is no guarantee that historical sources of reserves additions will continue as many factors are fully or partially outside management's control, including commodity prices, availability of capital and the underlying geology, all of which affect reserves additions. Management uses this measure to gauge the results of its capital program. Other oil and gas producers may use different methods to calculate replacement ratios, which may affect comparability.
|
|
Total Proved Reserves
|
|
Average Net Daily
Production (MBoe/d)
|
||
|
% of Total Basin
|
|
Year ended
December 31, 2018
|
||
San Joaquin Basin
|
|
|
|
|
|
Primary
|
15
|
%
|
|
15
|
|
Waterfloods
|
13
|
%
|
|
9
|
|
Steamfloods
|
31
|
%
|
|
24
|
|
Unconventional
|
41
|
%
|
|
48
|
|
San Joaquin Basin subtotal
(a)
|
478
|
|
|
96
|
|
|
|
|
|
||
Los Angeles Basin
|
|
|
|
|
|
Waterfloods
|
100
|
%
|
|
25
|
|
Los Angeles Basin subtotal
(a)
|
175
|
|
|
25
|
|
|
|
|
|
||
Ventura Basin
|
|
|
|
|
|
Primary
|
34
|
%
|
|
3
|
|
Waterfloods
|
66
|
%
|
|
3
|
|
Ventura Basin subtotal
(a)
|
48
|
|
|
6
|
|
|
|
|
|
||
Sacramento Basin
|
|
|
|
|
|
Primary
|
100
|
%
|
|
5
|
|
Sacramento Basin subtotal
(a)
|
11
|
|
|
5
|
|
|
|
|
|
||
Total
|
712
|
|
|
132
|
|
(a)
|
Subtotal basin reserves in MMBoe. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
|
Proven Drilling Locations
|
|
Total Identified Drilling Locations
(a)
|
||||||||
|
Oil and
Natural Gas Wells
|
|
Injection Wells
|
|
Oil and
Natural Gas Wells
|
|
Injection Wells
|
||||
San Joaquin Basin
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
140
|
|
|
—
|
|
|
8,080
|
|
|
—
|
|
Steamflood
|
570
|
|
|
150
|
|
|
8,350
|
|
|
450
|
|
Waterflood
|
90
|
|
|
40
|
|
|
1,970
|
|
|
980
|
|
Unconventional
|
220
|
|
|
—
|
|
|
4,520
|
|
|
—
|
|
San Joaquin Basin subtotal
|
1,020
|
|
|
190
|
|
|
22,920
|
|
|
1,430
|
|
|
|
|
|
|
|
|
|
||||
Los Angeles Basin
|
|
|
|
|
|
|
|
|
|
|
|
Waterflood
|
460
|
|
|
130
|
|
|
1,520
|
|
|
500
|
|
Los Angeles Basin subtotal
|
460
|
|
|
130
|
|
|
1,520
|
|
|
500
|
|
|
|
|
|
|
|
|
|
||||
Ventura Basin
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
30
|
|
|
—
|
|
|
1,400
|
|
|
—
|
|
Steamflood
|
—
|
|
|
—
|
|
|
120
|
|
|
—
|
|
Waterflood
|
80
|
|
|
60
|
|
|
1,560
|
|
|
520
|
|
Unconventional
|
—
|
|
|
—
|
|
|
100
|
|
|
—
|
|
Ventura Basin subtotal
|
110
|
|
|
60
|
|
|
3,180
|
|
|
520
|
|
|
|
|
|
|
|
|
|
||||
Sacramento Basin
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
10
|
|
|
—
|
|
|
2,280
|
|
|
—
|
|
Sacramento Basin subtotal
|
10
|
|
|
—
|
|
|
2,280
|
|
|
—
|
|
|
|
|
|
|
|
|
|
||||
Total Drilling Locations
|
1,600
|
|
|
380
|
|
|
29,900
|
|
|
2,450
|
|
(a)
|
Total gross identified drilling locations is comprised of gross proven drilling locations of
1,980
gross (
1,970
net), gross unproven drilling locations of
17,030
gross (
16,870
net) and gross conventional exploration drilling locations of
13,340
gross (
6,250
net). Total gross identified drilling locations excludes gross unconventional exploration drilling locations of 6,400 gross (5,300 net).
|
|
San Joaquin Basin
|
|
Los Angeles Basin
|
|
Ventura Basin
|
|
Sacramento Basin
|
|
Total Net Wells
|
|||||
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
0.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
Development
|
127.0
|
|
|
48.2
|
|
|
3.2
|
|
|
—
|
|
|
178.4
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
1.3
|
|
|
—
|
|
|
0.3
|
|
|
—
|
|
|
1.6
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|||||
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.0
|
|
Development
|
91.8
|
|
|
14.5
|
|
|
1.6
|
|
|
—
|
|
|
107.9
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
3.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.0
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
37.0
|
|
|
5.4
|
|
|
—
|
|
|
—
|
|
|
42.4
|
|
|
San Joaquin Basin
|
|
Los Angeles Basin
|
|
Ventura Basin
|
|
Sacramento Basin
|
|
Total
|
|||||
Exploratory and development wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(a)
|
14.0
|
|
|
2.0
|
|
|
3.3
|
|
|
—
|
|
|
19.3
|
|
Net
(b)
|
13.9
|
|
|
1.9
|
|
|
2.3
|
|
|
—
|
|
|
18.1
|
|
(a)
|
The total number of wells in which interests are owned.
|
(b)
|
Sum of our fractional interests.
|
|
As of December 31, 2018
|
||||||||||
|
Productive Oil Wells
|
|
Productive Gas Wells
|
||||||||
|
Gross
(a)
|
|
Net
(b)
|
|
Gross
(a)
|
|
Net
(b)
|
||||
San Joaquin Basin
|
8,419
|
|
|
7,961
|
|
|
166
|
|
|
161
|
|
Los Angeles Basin
|
1,533
|
|
|
1,486
|
|
|
1
|
|
|
1
|
|
Ventura Basin
|
1,320
|
|
|
1,312
|
|
|
—
|
|
|
—
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
1,012
|
|
|
930
|
|
Total
|
11,272
|
|
|
10,759
|
|
|
1,179
|
|
|
1,092
|
|
Multiple completion wells included in the total above
|
382
|
|
|
356
|
|
|
46
|
|
|
42
|
|
(a)
|
The total number of wells in which interests are owned.
|
(b)
|
Sum of our fractional interests.
|
Description
|
|
Quantity
|
|
Unit
(a)
|
|
Capacity
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
San Joaquin Basin
|
|
Other Basins
|
|
Total
|
Gas Plants
|
|
9
|
|
MMcf/d
|
|
610
|
|
50
|
|
660
|
Power Plants
|
|
3
|
|
MW
|
|
600
|
|
50
|
|
650
|
Steam Generators/Plants
|
|
>50
|
|
MBbl/d
|
|
220
|
|
—
|
|
220
|
Compressors
|
|
400
|
|
MHp
|
|
300
|
|
20
|
|
320
|
Water Management Systems
|
|
22
|
|
MBw/d
|
|
2,400
|
|
2,100
|
|
4,500
|
Water Softeners
|
|
30
|
|
MBw/d
|
|
265
|
|
—
|
|
265
|
Oil and NGL Storage
|
|
|
|
MBbls
|
|
580
|
|
660
|
|
1,240
|
Gathering Systems
|
|
|
|
Miles
|
|
|
|
|
|
>20,000
|
(a)
|
MW refers to megawatts of power; MBbl/d refers to thousand barrels of steam per day; MHp refers to thousand horsepower; MBw/d refers to thousand barrels of water per day; MBbl refers to thousands of barrels.
|
•
|
oil and natural gas production, including siting and spacing of wells and facilities on federal, state and private lands with associated conditions or mitigation measures;
|
•
|
methods of constructing, drilling, completing, stimulating, operating, maintaining and abandoning wells;
|
•
|
the design, construction, operation, maintenance and decommissioning of facilities, such as natural gas processing plants, power plants, compressors and liquid and natural gas pipelines or gathering lines;
|
•
|
improved or enhanced recovery techniques such as fluid injection for pressure management;
|
•
|
sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and improved or enhanced recovery processes;
|
•
|
imposition of taxes and fees with respect to our properties and operations;
|
•
|
the conservation of oil and natural gas, including provisions for the unitization or pooling of oil and natural gas properties;
|
•
|
posting of bonds or other financial assurance to drill, operate and abandon or decommission wells and facilities; and
|
•
|
occupational health, safety and environmental matters and the transportation, marketing and sale of our products as described below.
|
•
|
establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, conduct regional, community or field monitoring of air, soil or water quality, and require attainment plans to meet those regional standards, which may include significant mitigation measures or restrictions on development, economic activity and transportation in such region;
|
•
|
require various permits, approvals and mitigation measures before drilling, workover, production, underground fluid injection or waste disposal commences, or before facilities are constructed or put into operation;
|
•
|
require the installation of sophisticated safety and pollution control equipment, such as leak detection, monitoring and shutdown systems, and implementation of inspection, monitoring and repair programs to prevent or reduce releases or discharges of regulated materials to air, land, surface water or ground water;
|
•
|
restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require conservation and reclamation measures, impose energy efficiency or renewable energy standards on us or users of our products and services, and restrict the use of oil, natural gas or certain petroleum–based products such as fuels and plastics;
|
•
|
restrict the types, quantities and concentrations of regulated materials, including oil, natural gas, produced water or wastes, that can be released or discharged into the environment, or any other uses of those materials resulting from drilling, production, processing, power generation, transportation or storage activities;
|
•
|
limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater recharge, endangered species habitat and other protected areas, and require the dedication of surface acreage for habitat conservation;
|
•
|
establish standards for the management of solid and hazardous wastes or the closure, abandonment, cleanup or restoration of former operations, such as plugging and abandonment of wells and decommissioning of facilities;
|
•
|
impose substantial liabilities for unauthorized releases or discharges of regulated materials into the environment with respect to our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
|
•
|
require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state and private lands or leases;
|
•
|
impose taxes or fees with respect to the foregoing matters;
|
•
|
may expose us to litigation with government authorities, counterparties, special interest groups or others; and
|
•
|
may restrict our rate of oil, NGLs, natural gas and electricity production.
|
•
|
require reporting of annual GHG emissions from oil and gas exploration and production, power plants and gas processing plants; gathering and boosting compression and pipeline facilities; and certain completions and workovers;
|
•
|
incorporate measures to reduce GHG emissions in permits for certain facilities; and
|
•
|
restrict GHG emissions from certain mobile sources.
|
•
|
established a “cap-and-trade” program for GHG emissions that sets a statewide maximum limit on covered GHG emissions, and this cap declines annually to reach 40% below 1990 levels by 2030, the year that the cap-and-trade program currently expires;
|
•
|
require allowances or qualifying offsets for GHGs emitted from California operations and for the volume of natural gas, propane and liquid transportation fuels sold for use in California;
|
•
|
established a low carbon fuel standard and associated tradable credits that require a progressively lower carbon intensity of the state's fuel supply than baseline gasoline and diesel fuels;
|
•
|
mandated that California derive 60% of its electricity for retail customers from renewable resources by 2030;
|
•
|
established a policy to derive all of California’s retail electricity from renewable or "zero-carbon" resources by 2045, subject to required evaluation of the feasibility by state agencies; and
|
•
|
imposed state goals to double the energy efficiency of buildings by 2030 and to reduce emissions of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013 levels by 2030.
|
•
|
interstate and intrastate pipeline transportation rates for oil, natural gas and NGLs in regulated pipeline systems;
|
•
|
prevention of market manipulation in the oil, natural gas, NGL and power markets;
|
•
|
market transparency rules with respect to natural gas and power markets;
|
•
|
the physical and futures energy commodities market, including financial derivative and hedging activity; and
|
•
|
prevention of discrimination in natural gas gathering operations in favor of producers or sources of supply.
|
ITEM 1A
|
RISK FACTORS
|
•
|
changes in domestic and global supply and demand;
|
•
|
domestic and global inventory levels;
|
•
|
political and economic conditions;
|
•
|
the actions of OPEC and other significant producers and governments;
|
•
|
changes or disruptions in actual or anticipated production, refining and processing;
|
•
|
worldwide drilling and exploration activities;
|
•
|
government energy policies and regulation, including with respect to climate change;
|
•
|
the effects of conservation;
|
•
|
weather conditions and other seasonal impacts;
|
•
|
speculative trading in derivative contracts;
|
•
|
currency exchange rates;
|
•
|
technological advances;
|
•
|
transportation and storage capacity, bottlenecks and costs in producing areas;
|
•
|
the price, availability and acceptance of alternative energy sources;
|
•
|
regional market conditions; and
|
•
|
other matters affecting the supply and demand dynamics for these products.
|
•
|
reducing our proved oil and gas reserves over time, including as a result of impairments of existing reserves;
|
•
|
limiting our ability to grow or maintain future production;
|
•
|
causing a reduction in our borrowing base under our 2014 Revolving Credit Facility, which could affect our liquidity;
|
•
|
reducing our ability to make interest payments or maintain compliance with financial covenants in the agreements governing our indebtedness, which could trigger mandatory loan repayments and default and foreclosure by our lenders and bondholders against our assets;
|
•
|
forcing monetization events and potential issues under our JV arrangements;
|
•
|
affecting our ability to attract counterparties and enter into commercial transactions, including hedging transactions; and
|
•
|
limiting our access to funds through the capital markets and the price we could obtain for asset sales or other monetization transactions or our equity and debt securities.
|
•
|
jeopardizing our ability to execute our business plans;
|
•
|
increasing our vulnerability to adverse changes in economic and industry conditions related to our business;
|
•
|
putting us at a disadvantage against competitors that have lower fixed obligations and more cash flow to devote to their businesses;
|
•
|
limiting our ability to obtain favorable financing for working capital, capital investments and general corporate and other purposes;
|
•
|
limiting our ability to fund capital investments, react to competitive pressures and engage in certain transactions that might otherwise be beneficial to us;
|
•
|
defaulting on commercial agreements with our JV partners; and
|
•
|
failing to redeem the interests held by our JV partners.
|
•
|
incur additional indebtedness and granting additional liens;
|
•
|
repay junior indebtedness, including our Second Lien Notes and Senior Notes;
|
•
|
make investments;
|
•
|
enter into JVs;
|
•
|
pay dividends and making other restricted payments;
|
•
|
selling assets;
|
•
|
use the proceeds of asset sales for certain purposes;
|
•
|
enter into mergers or acquisitions; and
|
•
|
release collateral.
|
•
|
historical production from the area compared with production from similar areas;
|
•
|
the quality, quantity and interpretation of available relevant data;
|
•
|
commodity prices;
|
•
|
production and operating costs;
|
•
|
ad valorem, excise and income taxes;
|
•
|
development costs;
|
•
|
the effects of government regulations; and
|
•
|
future workover and facilities costs.
|
•
|
not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances;
|
•
|
bear unexpected integration costs or experience other integration difficulties;
|
•
|
experience share price declines based on the market’s evaluation of the activity;
|
•
|
assume liabilities that are greater than anticipated; and
|
•
|
be exposed to currency, political, marketing, labor and other risks, particularly associated with investments in foreign assets.
|
•
|
not be able to realize reasonable prices or rates of return for assets;
|
•
|
be required to retain liabilities that are greater than desired or anticipated;
|
•
|
experience increased operating costs; and
|
•
|
reduce our cash flows if we cannot replace associated revenue.
|
ITEM 1B
|
UNRESOLVED STAFF COMMENTS
|
ITEM 3
|
LEGAL PROCEEDINGS
|
ITEM 4
|
MINE SAFETY DISCLOSURES
|
Name
|
|
Employment History
|
|
Age at February 27, 2019
|
Todd A. Stevens
|
|
President, Chief Executive Officer and Director since 2014; Occidental Petroleum Corporation Vice President - Corporate Development 2012 to 2014; Oxy Oil & Gas Vice President - California Operations 2008 to 2012; Occidental Petroleum Corporation Vice President - Acquisitions and Corporate Finance 2004 to 2012.
|
|
52
|
Marshall D. Smith
|
|
Senior Executive Vice President and Chief Financial Officer since 2014; Ultra Petroleum Corporation Senior Vice President and Chief Financial Officer 2011 to 2014; Ultra Petroleum Corporation Chief Financial Officer 2005 to 2014.
|
|
59
|
Shawn M. Kerns
|
|
Executive Vice President - Operations and Engineering - 2018; Executive Vice President - Corporate Development 2014 to 2018; Vintage Production California President and General Manager 2012 to 2014; Occidental of Elk Hills General Manager 2010 to 2012; Occidental of Elk Hills Asset Development Manager 2008 to 2010.
|
|
48
|
Francisco J. Leon
|
|
Executive Vice President - Corporate Development and Strategic Planning - 2018; Vice President - Portfolio Management and Strategic Planning 2014 to 2018; Occidental Director - Portfolio Management 2012 to 2014; Occidental Director of Corporate Development and M&A 2010 to 2012; Occidental Manager of Business Development 2008 to 2010.
|
|
42
|
Roy M. Pineci
|
|
Executive Vice President - Finance since 2014; Occidental Vice President and Controller 2008 to 2014; Occidental Oil and Gas Senior Vice President 2007 to 2008.
|
|
56
|
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.
|
|
54
|
Charles F. Weiss
|
|
Executive Vice President - Public Affairs since 2014; Occidental Vice President, Health, Environment and Safety 2007 to 2014.
|
|
55
|
Darren Williams
|
|
Executive Vice President - Operations and Geoscience - 2018; Executive Vice President - Exploration 2014 to 2018; Marathon Upstream Gabon Limited President and Africa Exploration Manager 2013 to 2014; Marathon Oil Oklahoma Subsurface Manager 2010 to 2013; Marathon Oil Gulf of Mexico Exploration and Appraisal Manager 2008 to 2010.
|
|
47
|
ITEM 5
|
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
a)
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights
|
|
b)
|
Weighted-average exercise price of outstanding options, warrants and rights
|
|
c)
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities in column (a))
|
2,354,569
|
|
$62.82
(a)
|
|
1,253,892
(b)
|
(a)
|
Exercise price applies only to approximately 1.3 million options included in column (a) and not to any other awards.
|
(b)
|
Includes 656,929 shares available under our 2014 Employee Stock Purchase Plan (ESPP) for purchase at 85% of the lower of the market price at either (i) the beginning of a quarter or (ii) the end of a quarter.
|
|
|
|
|
December 31,
|
||||||||||||||||||||
|
|
12/1/2014
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
CRC
|
|
$
|
100
|
|
|
$
|
75
|
|
|
$
|
32
|
|
|
$
|
29
|
|
|
$
|
27
|
|
|
$
|
23
|
|
S&P 500
|
|
$
|
100
|
|
|
$
|
100
|
|
|
$
|
101
|
|
|
$
|
113
|
|
|
$
|
138
|
|
|
$
|
132
|
|
Dow Jones US Exploration & Production
|
|
$
|
100
|
|
|
$
|
99
|
|
|
$
|
76
|
|
|
$
|
94
|
|
|
$
|
95
|
|
|
$
|
78
|
|
2018 Peer Group
|
|
$
|
100
|
|
|
$
|
95
|
|
|
$
|
58
|
|
|
$
|
85
|
|
|
$
|
70
|
|
|
$
|
53
|
|
2017 Peer Group
|
|
$
|
100
|
|
|
$
|
96
|
|
|
$
|
62
|
|
|
$
|
92
|
|
|
$
|
81
|
|
|
$
|
53
|
|
ITEM 6
|
SELECTED FINANCIAL DATA
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(in millions, except for per share data)
|
||||||||||||||||||
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total revenues and other
|
$
|
3,064
|
|
|
$
|
2,006
|
|
|
$
|
1,547
|
|
|
$
|
2,403
|
|
|
$
|
4,173
|
|
Income (loss) before income taxes
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
201
|
|
|
$
|
(5,476
|
)
|
|
$
|
(2,421
|
)
|
Net income (loss) attributable to common stock
|
$
|
328
|
|
|
$
|
(266
|
)
|
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
Per common share
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
6.77
|
|
|
$
|
(6.26
|
)
|
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
Diluted
|
$
|
6.77
|
|
|
$
|
(6.26
|
)
|
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
Statement of Cash Flows Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
$
|
461
|
|
|
$
|
248
|
|
|
$
|
130
|
|
|
$
|
403
|
|
|
$
|
2,371
|
|
Capital investments
|
$
|
(690
|
)
|
|
$
|
(371
|
)
|
|
$
|
(75
|
)
|
|
$
|
(401
|
)
|
|
$
|
(2,089
|
)
|
Acquisitions and other
|
$
|
(553
|
)
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
(151
|
)
|
|
$
|
(292
|
)
|
Net (repayments) borrowings and related costs
|
$
|
(26
|
)
|
|
$
|
(18
|
)
|
|
$
|
(73
|
)
|
|
$
|
356
|
|
|
$
|
6,290
|
|
Contributions from noncontrolling interest holders, net
|
$
|
796
|
|
|
$
|
98
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Distributions paid to noncontrolling interest holders
|
$
|
(121
|
)
|
|
$
|
(8
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Spin-off related dividends to Occidental
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(6,000
|
)
|
Distributions to Occidental, net
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(335
|
)
|
Dividends per common share
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.30
|
|
|
$
|
—
|
|
|
As of December 31,
|
||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total current assets
|
$
|
640
|
|
|
$
|
483
|
|
|
$
|
425
|
|
|
$
|
438
|
|
|
$
|
701
|
|
Property, plant and equipment, net
|
$
|
6,455
|
|
|
$
|
5,696
|
|
|
$
|
5,885
|
|
|
$
|
6,312
|
|
|
$
|
11,685
|
|
Total assets
|
$
|
7,158
|
|
|
$
|
6,207
|
|
|
$
|
6,354
|
|
|
$
|
7,053
|
|
|
$
|
12,429
|
|
Current maturities of long-term debt
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
100
|
|
|
$
|
100
|
|
|
$
|
—
|
|
Total current liabilities
|
$
|
607
|
|
|
$
|
732
|
|
|
$
|
726
|
|
|
$
|
605
|
|
|
$
|
922
|
|
Long-term debt
|
$
|
5,251
|
|
|
$
|
5,306
|
|
|
$
|
5,168
|
|
|
$
|
6,043
|
|
|
$
|
6,360
|
|
Deferred gain and issuance costs, net
|
$
|
216
|
|
|
$
|
287
|
|
|
$
|
397
|
|
|
$
|
491
|
|
|
$
|
(68
|
)
|
Other long-term liabilities
|
$
|
575
|
|
|
$
|
602
|
|
|
$
|
620
|
|
|
$
|
830
|
|
|
$
|
549
|
|
Mezzanine equity
|
$
|
756
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity attributable to common stock
|
$
|
(361
|
)
|
|
$
|
(814
|
)
|
|
$
|
(557
|
)
|
|
$
|
(916
|
)
|
|
$
|
2,611
|
|
ITEM 7
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
2018
|
|
2017
|
|
2016
|
||||||
Brent oil ($/Bbl)
|
$
|
71.53
|
|
|
$
|
54.82
|
|
|
$
|
45.04
|
|
WTI oil ($/Bbl)
|
$
|
64.77
|
|
|
$
|
50.95
|
|
|
$
|
43.32
|
|
NYMEX gas ($/MMBtu)
|
$
|
2.97
|
|
|
$
|
3.09
|
|
|
$
|
2.42
|
|
|
For the years ended
December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Pre-tax income (loss)
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
201
|
|
Income tax benefit
|
—
|
|
|
—
|
|
|
78
|
|
|||
Net income (loss)
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
279
|
|
|
2018
|
|
2017
|
|
2016
|
|||
Oil (MBbl/d)
(a)
|
|
|
|
|
|
|||
San Joaquin Basin
|
53
|
|
|
52
|
|
|
57
|
|
Los Angeles Basin
|
25
|
|
|
27
|
|
|
29
|
|
Ventura Basin
|
4
|
|
|
4
|
|
|
5
|
|
Total
|
82
|
|
|
83
|
|
|
91
|
|
|
|
|
|
|
|
|||
NGLs (MBbl/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
15
|
|
|
15
|
|
|
15
|
|
Ventura Basin
|
1
|
|
|
1
|
|
|
1
|
|
Total
|
16
|
|
|
16
|
|
|
16
|
|
|
|
|
|
|
|
|||
Natural gas (MMcf/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
165
|
|
|
140
|
|
|
150
|
|
Los Angeles Basin
|
1
|
|
|
1
|
|
|
3
|
|
Ventura Basin
|
7
|
|
|
8
|
|
|
8
|
|
Sacramento Basin
|
29
|
|
|
33
|
|
|
36
|
|
Total
|
202
|
|
|
182
|
|
|
197
|
|
|
|
|
|
|
|
|||
Total Production (MBoe/d)
(a)(b)
|
132
|
|
|
129
|
|
|
140
|
|
Note:
|
MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent per day.
|
(a)
|
Our PSC-type contracts negatively impacted our oil production in 2018 by over 1 MBoe/d compared to 2017. The impact on our oil production was immaterial in 2017 compared to 2016.
|
(b)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
|
Price
|
|
Realization
|
|
Price
|
|
Realization
|
|
Price
|
|
Realization
|
||||||
Oil ($ per Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Brent
|
$
|
71.53
|
|
|
|
|
$
|
54.82
|
|
|
|
|
$
|
45.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Realized price, without hedge
|
$
|
70.11
|
|
|
98%
|
|
$
|
51.47
|
|
|
94%
|
|
$
|
39.72
|
|
|
88%
|
Settled hedges
|
(7.51
|
)
|
|
|
|
(0.23
|
)
|
|
|
|
2.29
|
|
|
|
|||
Realized price, with hedge
|
$
|
62.60
|
|
|
88%
|
|
$
|
51.24
|
|
|
93%
|
|
$
|
42.01
|
|
|
93%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
WTI
|
$
|
64.77
|
|
|
|
|
$
|
50.95
|
|
|
|
|
$
|
43.32
|
|
|
|
Realized price, without hedge
|
$
|
70.11
|
|
|
108%
|
|
$
|
51.47
|
|
|
101%
|
|
$
|
39.72
|
|
|
92%
|
Realized price, with hedge
|
$
|
62.60
|
|
|
97%
|
|
$
|
51.24
|
|
|
101%
|
|
$
|
42.01
|
|
|
97%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
NGLs ($ per Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Realized price (% of Brent)
|
$
|
43.67
|
|
|
61%
|
|
$
|
35.76
|
|
|
65%
|
|
$
|
22.39
|
|
|
50%
|
Realized price (% of WTI)
|
$
|
43.67
|
|
|
67%
|
|
$
|
35.76
|
|
|
70%
|
|
$
|
22.39
|
|
|
52%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
||||||
NYMEX ($/MMBTU)
|
$
|
2.97
|
|
|
|
|
$
|
3.09
|
|
|
|
|
$
|
2.42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Realized price, w/out hedge ($/Mcf)
|
$
|
3.00
|
|
|
101%
|
|
$
|
2.67
|
|
|
86%
|
|
$
|
2.28
|
|
|
94%
|
Settled hedges
|
(0.02
|
)
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|||
Realized price, with hedge ($/Mcf)
|
$
|
2.98
|
|
|
100%
|
|
$
|
2.67
|
|
|
86%
|
|
$
|
2.28
|
|
|
94%
|
Note:
|
We adopted a new revenue recognition standard on January 1, 2018 that required certain sales-related costs to be reported as expense as opposed to being netted against revenue. The adoption of this standard did not affect net income. Results for reporting periods beginning January 1, 2018 are presented under the new accounting standard while prior periods are not adjusted and continue to be reported under accounting standards in effect for the applicable period. Under prior accounting standards, the unhedged realized price and realization for natural gas would have been $2.79 per Mcf and 94%, respectively, and the hedged realized price and realization would have been $2.77 per Mcf and 93%, respectively. The new standard did not have a material impact to the realized price and realization for oil and NGLs.
|
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Cash
|
$
|
17
|
|
|
$
|
20
|
|
Trade receivables
|
$
|
299
|
|
|
$
|
277
|
|
Inventories
|
$
|
69
|
|
|
$
|
56
|
|
Other current assets, net
|
$
|
255
|
|
|
$
|
130
|
|
Property, plant and equipment, net
|
$
|
6,455
|
|
|
$
|
5,696
|
|
Other assets
|
$
|
63
|
|
|
$
|
28
|
|
Accounts payable
|
$
|
390
|
|
|
$
|
257
|
|
Accrued liabilities
|
$
|
217
|
|
|
$
|
475
|
|
Long-term debt
|
$
|
5,251
|
|
|
$
|
5,306
|
|
Deferred gain and issuance costs, net
|
$
|
216
|
|
|
$
|
287
|
|
Other long-term liabilities
|
$
|
575
|
|
|
$
|
602
|
|
Mezzanine equity
|
$
|
756
|
|
|
$
|
—
|
|
Equity attributable to common stock
|
$
|
(361
|
)
|
|
$
|
(814
|
)
|
Equity attributable to noncontrolling interests
|
$
|
114
|
|
|
$
|
94
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Production costs
|
$
|
18.88
|
|
|
$
|
18.64
|
|
|
$
|
15.61
|
|
Production costs, excluding effects of PSC-type contracts
(a)
|
$
|
17.47
|
|
|
$
|
17.48
|
|
|
$
|
14.69
|
|
Field general and administrative expenses
(b)(c)(d)
|
$
|
1.01
|
|
|
$
|
0.70
|
|
|
$
|
0.68
|
|
Field depreciation, depletion and amortization
(b)
|
$
|
9.71
|
|
|
$
|
10.85
|
|
|
$
|
10.28
|
|
Field taxes other than on income
(b)
|
$
|
2.42
|
|
|
$
|
2.34
|
|
|
$
|
2.36
|
|
(a)
|
As described in
Items 1 and 2 – Business and Properties – Our Operations – Production, Price and Cost History
, the reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs. These amounts represent our production costs after adjusting for this difference.
|
(b)
|
Excludes corporate amounts.
|
(c)
|
Field general and administrative expenses increased in 2018, compared to 2017, following the Elk Hills transaction since certain costs are no longer collected from our former working interest partner through G&A expenses.
|
(d)
|
For the years ended December 31, 2017 and 2016, certain pension benefit costs of $1 million and $2 million, respectively, have been reclassified to other non-operating expenses to conform to the current year presentation in accordance with new accounting rules adopted on January 1, 2018 related to the presentation of net periodic benefit costs for pension and postretirement benefits in the Consolidated Statements of Operations. See
Item 8 – Financial Statement and Supplementary Data – Note 2 Accounting and Disclosure Changes
for more information.
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Oil and gas sales
(a)
|
$
|
2,590
|
|
|
$
|
1,936
|
|
|
$
|
1,621
|
|
Net derivative gain (loss) from commodity contracts
|
1
|
|
|
(90
|
)
|
|
(206
|
)
|
|||
Other revenue
(a)
|
473
|
|
|
160
|
|
|
132
|
|
|||
Production costs
|
(912
|
)
|
|
(876
|
)
|
|
(800
|
)
|
|||
General and administrative expenses
(b)
|
(299
|
)
|
|
(249
|
)
|
|
(235
|
)
|
|||
Depreciation, depletion and amortization
|
(502
|
)
|
|
(544
|
)
|
|
(559
|
)
|
|||
Taxes other than on income
|
(149
|
)
|
|
(136
|
)
|
|
(144
|
)
|
|||
Exploration expense
|
(34
|
)
|
|
(22
|
)
|
|
(23
|
)
|
|||
Other expenses, net
(a)
|
(399
|
)
|
|
(106
|
)
|
|
(79
|
)
|
|||
Interest and debt expense, net
|
(379
|
)
|
|
(343
|
)
|
|
(328
|
)
|
|||
Net gain on early extinguishment of debt
|
57
|
|
|
4
|
|
|
805
|
|
|||
Gain on asset divestitures
|
5
|
|
|
21
|
|
|
30
|
|
|||
Other non-operating expenses
(b)
|
(23
|
)
|
|
(17
|
)
|
|
(13
|
)
|
|||
Income (loss) before income taxes
|
429
|
|
|
(262
|
)
|
|
201
|
|
|||
Income tax
|
—
|
|
|
—
|
|
|
78
|
|
|||
Net income (loss)
|
429
|
|
|
(262
|
)
|
|
279
|
|
|||
Net income attributable to noncontrolling interests
|
$
|
(101
|
)
|
|
$
|
(4
|
)
|
|
$
|
—
|
|
Net income (loss) attributable to common stock
|
$
|
328
|
|
|
$
|
(266
|
)
|
|
$
|
279
|
|
|
|
|
|
|
|
||||||
Adjusted net income (loss)
|
$
|
61
|
|
|
$
|
(187
|
)
|
|
$
|
(317
|
)
|
Adjusted EBITDAX
|
$
|
1,117
|
|
|
$
|
779
|
|
|
$
|
616
|
|
Effective tax rate
|
—
|
%
|
|
—
|
%
|
|
(39
|
)%
|
(a)
|
We adopted a new revenue recognition standard on January 1, 2018 that required certain sales-related costs to be reported as expense as opposed to being netted against revenue. The adoption of this standard did not affect net income. Results for reporting periods beginning January 1, 2018 are presented under the new accounting standard while prior periods are not adjusted and continue to be reported under accounting standards in effect for the applicable period. Under prior accounting standards, the 2018 total oil and gas sales would have been
$2,568 million
, other revenue would have been
$392 million
and other expenses, net would have been
$296 million
. See
Item 8 – Financial Statement and Supplementary Data – Note 15 Revenue Recognition
for more information.
|
(b)
|
For the years ended December 31, 2017 and 2016, certain pension benefit costs of $10 million and $13 million, respectively, have been reclassified from general and administrative expense to other non-operating expenses to conform to the current year presentation in accordance with new accounting rules adopted on January 1, 2018 related to the presentation of net periodic benefit costs for pension and postretirement benefits in the Consolidated Statements of Operations. See
Item 8 – Financial Statement and Supplementary Data – Note 2 Accounting and Disclosure Changes
for more information.
|
|
2018
|
|
2017
|
|
2016
|
||||||
First quarter
|
$
|
17.15
|
|
|
$
|
15.04
|
|
|
$
|
10.30
|
|
Second quarter
|
$
|
45.44
|
|
|
$
|
8.55
|
|
|
$
|
12.20
|
|
Third quarter
|
$
|
48.53
|
|
|
$
|
10.46
|
|
|
$
|
12.50
|
|
Fourth quarter
|
$
|
17.04
|
|
|
$
|
19.44
|
|
|
$
|
21.29
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions, except per Boe amounts)
|
||||||||||
G&A expenses
|
|
|
|
|
|
||||||
Cash-settled awards
|
$
|
23
|
|
|
$
|
9
|
|
|
$
|
6
|
|
Equity-settled awards
|
13
|
|
|
14
|
|
|
17
|
|
|||
Total stock-based compensation in G&A
|
$
|
36
|
|
|
$
|
23
|
|
|
$
|
23
|
|
Total stock-based compensation in G&A per Boe
|
$
|
0.75
|
|
|
$
|
0.49
|
|
|
$
|
0.45
|
|
|
|
|
|
|
|
||||||
Production costs
|
|
|
|
|
|
||||||
Cash-settled awards
|
$
|
6
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Equity-settled awards
|
3
|
|
|
4
|
|
|
5
|
|
|||
Total stock-based compensation in production costs
|
$
|
9
|
|
|
$
|
6
|
|
|
$
|
7
|
|
Total stock-based compensation in production costs per Boe
|
$
|
0.19
|
|
|
$
|
0.13
|
|
|
$
|
0.14
|
|
|
|
|
|
|
|
||||||
Total stock-based compensation
|
$
|
45
|
|
|
$
|
29
|
|
|
$
|
30
|
|
Total stock-based compensation per Boe
|
$
|
0.94
|
|
|
$
|
0.62
|
|
|
$
|
0.59
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions, except share data)
|
||||||||||
Net income (loss)
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
279
|
|
Net income attributable to noncontrolling interests
|
(101
|
)
|
|
(4
|
)
|
|
—
|
|
|||
Net income (loss) attributable to common stock
|
328
|
|
|
(266
|
)
|
|
279
|
|
|||
Unusual, infrequent and other items:
|
|
|
|
|
|
||||||
Non-cash derivative (gain) loss from commodities, excluding noncontrolling interest
|
(224
|
)
|
|
78
|
|
|
283
|
|
|||
Non-cash derivative loss from interest-rate contracts
|
6
|
|
|
—
|
|
|
—
|
|
|||
Early retirement, severance and other costs
|
4
|
|
|
5
|
|
|
20
|
|
|||
Net gain on early extinguishment of debt
|
(57
|
)
|
|
(4
|
)
|
|
(805
|
)
|
|||
Gain on asset divestitures
|
(5
|
)
|
|
(21
|
)
|
|
(30
|
)
|
|||
Other, net
|
9
|
|
|
21
|
|
|
(13
|
)
|
|||
Total unusual, infrequent and other items
|
(267
|
)
|
|
79
|
|
|
(545
|
)
|
|||
Deferred debt issuance costs write-off
|
—
|
|
|
—
|
|
|
12
|
|
|||
Reversal of valuation allowance for deferred tax assets
(a)
|
—
|
|
|
—
|
|
|
(63
|
)
|
|||
Adjusted net income (loss)
|
$
|
61
|
|
|
$
|
(187
|
)
|
|
$
|
(317
|
)
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stock per diluted share
|
$
|
6.77
|
|
|
$
|
(6.26
|
)
|
|
$
|
6.76
|
|
Adjusted net income (loss) per diluted share
|
$
|
1.27
|
|
|
$
|
(4.40
|
)
|
|
$
|
(7.85
|
)
|
(a)
|
Amount represents the out-of-period portion of the valuation allowance reversal.
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Commodity Contracts:
|
|
|
|
|
|
||||||
Non-cash derivative gain (loss), excluding noncontrolling interest
|
$
|
224
|
|
|
$
|
(78
|
)
|
|
$
|
(283
|
)
|
Non-cash derivative gain (loss) included in noncontrolling interest
|
5
|
|
|
(5
|
)
|
|
—
|
|
|||
Net (payments) proceeds on settled commodity derivatives
|
(228
|
)
|
|
(7
|
)
|
|
77
|
|
|||
Net derivative gain (loss) from commodity contracts
|
$
|
1
|
|
|
$
|
(90
|
)
|
|
$
|
(206
|
)
|
|
|
|
|
|
|
||||||
Interest-Rate Contracts:
|
|
|
|
|
|
||||||
Non-cash derivative loss
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Net income (loss)
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
279
|
|
Interest and debt expense, net
|
379
|
|
|
343
|
|
|
328
|
|
|||
Income tax benefit
|
—
|
|
|
—
|
|
|
(78
|
)
|
|||
Depreciation, depletion and amortization
|
502
|
|
|
544
|
|
|
559
|
|
|||
Exploration expense
|
34
|
|
|
22
|
|
|
23
|
|
|||
Unusual, infrequent and other items
|
(267
|
)
|
|
79
|
|
|
(545
|
)
|
|||
Other non-cash items
|
40
|
|
|
53
|
|
|
50
|
|
|||
Adjusted EBITDAX
|
$
|
1,117
|
|
|
$
|
779
|
|
|
$
|
616
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Net cash provided by operating activities
|
$
|
461
|
|
|
$
|
248
|
|
|
$
|
130
|
|
Cash interest
|
441
|
|
|
396
|
|
|
384
|
|
|||
Exploration expenditures
|
17
|
|
|
20
|
|
|
20
|
|
|||
Working capital changes
|
199
|
|
|
94
|
|
|
95
|
|
|||
Other, net
|
(1
|
)
|
|
21
|
|
|
(13
|
)
|
|||
Adjusted EBITDAX
|
$
|
1,117
|
|
|
$
|
779
|
|
|
$
|
616
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Net cash provided by operating activities
|
$
|
461
|
|
|
$
|
248
|
|
|
$
|
130
|
|
Net cash used in investing activities:
|
|
|
|
|
|
||||||
Capital investments, net of accruals
|
$
|
(621
|
)
|
|
$
|
(344
|
)
|
|
$
|
(81
|
)
|
Acquisitions, divestitures and other
|
$
|
(535
|
)
|
|
$
|
31
|
|
|
$
|
20
|
|
Net cash provided (used) by financing activities
|
$
|
692
|
|
|
$
|
73
|
|
|
$
|
(69
|
)
|
|
Outstanding Principal
(in millions)
|
|
Interest Rate
|
|
Maturity
|
|
Security
|
||
Credit Agreements
|
|
|
|
|
|
|
|
||
2014 Revolving Credit Facility
|
$
|
540
|
|
|
LIBOR plus 3.25%-4.00%
ABR plus 2.25%-3.00% |
|
June 30, 2021
|
|
Shared First-Priority Lien
|
2017 Credit Agreement
|
1,300
|
|
|
LIBOR plus 4.75%
ABR plus 3.75% |
|
December 31, 2022
(a)
|
|
Shared First-Priority Lien
|
|
2016 Credit Agreement
|
1,000
|
|
|
LIBOR plus 10.375%
ABR plus 9.375% |
|
December 31, 2021
|
|
First-Priority Lien
|
|
Second Lien Notes
|
|
|
|
|
|
|
|
||
Second Lien Notes
|
2,067
|
|
|
8%
|
|
December 15, 2022
(b)
|
|
Second-Priority Lien
|
|
Senior Notes
|
|
|
|
|
|
|
|
||
5% Senior Notes due 2020
|
100
|
|
|
5%
|
|
January 15, 2020
|
|
Unsecured
|
|
5½% Senior Notes due 2021
|
100
|
|
|
5.5%
|
|
September 15, 2021
|
|
Unsecured
|
|
6% Senior Notes due 2024
|
144
|
|
|
6%
|
|
November 15, 2024
|
|
Unsecured
|
|
Total
|
$
|
5,251
|
|
|
|
|
|
|
|
(a)
|
The 2017 Credit Agreement is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.
|
(b)
|
The Second Lien Notes require principal repayments of approximately $326 million in June 2021, $65 million in December 2021 and $68 million in June 2022.
|
|
Q1
2019
|
|
Q2
2019
|
|
Q3
2019 |
|
Q4
2019 |
|
Q1
2020
|
||||||||||
Sold Calls:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
15,000
|
|
|
5,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Weighted-average price per barrel
|
$
|
66.15
|
|
|
$
|
68.45
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Purchased Calls:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
2,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Weighted-average price per barrel
|
$
|
71.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Purchased Puts:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
38,000
|
|
|
40,000
|
|
|
40,000
|
|
|
35,000
|
|
|
10,000
|
|
|||||
Weighted-average price per barrel
|
$
|
65.66
|
|
|
$
|
69.75
|
|
|
$
|
73.13
|
|
|
$
|
75.71
|
|
|
$
|
75.00
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Sold Puts:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
40,000
|
|
|
35,000
|
|
|
40,000
|
|
|
35,000
|
|
|
10,000
|
|
|||||
Weighted-average price per barrel
|
$
|
51.88
|
|
|
$
|
55.71
|
|
|
$
|
57.50
|
|
|
$
|
60.00
|
|
|
$
|
60.00
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Swaps:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
7,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Weighted-average price per barrel
|
$
|
67.71
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Conventional
|
|
Unconventional
|
|
Other
|
|
Total Capital Investments
|
||||||||||||||||||||
|
Primary
|
|
Waterflood
|
|
Steamflood
|
|
Total
|
|
Primary
|
|
|
||||||||||||||||
Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
San Joaquin
|
$
|
93
|
|
|
$
|
113
|
|
|
$
|
59
|
|
|
$
|
265
|
|
|
$
|
199
|
|
|
$
|
—
|
|
|
$
|
464
|
|
Los Angeles
|
—
|
|
|
155
|
|
|
—
|
|
|
155
|
|
|
—
|
|
|
—
|
|
|
155
|
|
|||||||
Ventura
|
22
|
|
|
10
|
|
|
1
|
|
|
33
|
|
|
—
|
|
|
—
|
|
|
33
|
|
|||||||
Sacramento
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|||||||
Basin Total
|
122
|
|
|
278
|
|
|
60
|
|
|
460
|
|
|
199
|
|
|
—
|
|
|
659
|
|
|||||||
Exploration and other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
31
|
|
|
31
|
|
|||||||
Total
|
$
|
122
|
|
|
$
|
278
|
|
|
$
|
60
|
|
|
$
|
460
|
|
|
$
|
199
|
|
|
$
|
31
|
|
|
$
|
690
|
|
|
Payments Due by Year
|
||||||||||||||||||
|
Total
|
|
Less than 1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More than 5 Years
|
||||||||||
|
(in millions)
|
||||||||||||||||||
On-Balance Sheet
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt
(a)
|
$
|
5,251
|
|
|
$
|
—
|
|
|
$
|
5,107
|
|
|
$
|
144
|
|
|
$
|
—
|
|
Interest on long-term debt
(b)
|
1,535
|
|
|
444
|
|
|
1,075
|
|
|
16
|
|
|
—
|
|
|||||
Asset retirement obligations
(c)
|
433
|
|
|
31
|
|
|
—
|
|
|
—
|
|
|
402
|
|
|||||
Pension and postretirement
|
147
|
|
|
6
|
|
|
25
|
|
|
26
|
|
|
90
|
|
|||||
Other long-term liabilities
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|||||
Off-Balance Sheet
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating leases
(d)
|
68
|
|
|
12
|
|
|
22
|
|
|
17
|
|
|
17
|
|
|||||
Purchase obligations
(e)
|
172
|
|
|
65
|
|
|
73
|
|
|
16
|
|
|
18
|
|
|||||
Total
(f)
|
$
|
7,612
|
|
|
$
|
558
|
|
|
$
|
6,308
|
|
|
$
|
219
|
|
|
$
|
527
|
|
(a)
|
In performing the calculation, the 2014 Revolving Credit Facility borrowings outstanding at December 31, 2018 of
$540 million
were assumed to be outstanding for the entire term of the agreement. See
Item 8 – Financial Statements and Supplementary Data – Note 6 Debt
for more information.
|
(b)
|
The calculation of cash interest payments on our variable interest-rate debt assumes the interest rate at December 31, 2018 will continue for the entire term and no settlement payments will be received under our interest-rate cap agreements.
|
(c)
|
Represents the estimated future asset retirement obligations on a discounted basis. We do not show the long-term asset retirement obligations by year as we are not able to precisely predict the timing of these amounts. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to revisions based on numerous factors, including the rate of inflation, changing technology, and changes to federal, state and local laws and regulations. See
Item 8 – Financial Statements and Supplementary Data – Note 1 Nature of Business, Summary of Significant Accounting Policies and Other
for more information.
|
(d)
|
Amounts include obligations for office space and vehicles.
|
(e)
|
Amounts include payments that will become due under long-term agreements to purchase goods and services used in the normal course of business primarily including pipeline capacity, land easements and field equipment. Obligations for field equipment include contractual agreements with third parties for drilling rigs and other related services. Purchase obligations for pipeline capacity are based on contractual volumes and our internal estimate of future prices during the contract period. Land easements include obligations for fixed payments under our term contracts, and those held by production cannot be reliably estimated.
|
(f)
|
Amounts exclude unrecognized tax benefit of $25 million due to uncertainty with respect to the timing of future cash outflows.
|
•
|
financial position, liquidity, cash flows and results of operations
|
•
|
business prospects
|
•
|
transactions and projects
|
•
|
operating costs
|
•
|
Value Creation Index (VCI) metrics, which are based on certain estimates including future production rates, costs and commodity prices
|
•
|
operations and operational results including production, hedging and capital investment
|
•
|
budgets and maintenance capital requirements
|
•
|
reserves
|
•
|
type curves
|
•
|
expected synergies from acquisitions and joint ventures
|
•
|
commodity price changes
|
•
|
debt limitations on our financial flexibility
|
•
|
insufficient cash flow to fund planned investments, debt repurchases or changes to our capital plan
|
•
|
inability to enter desirable transactions including acquisitions, asset sales and joint ventures
|
•
|
legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products
|
•
|
joint ventures and acquisitions and our ability to achieve expected synergies
|
•
|
the recoverability of resources and
|
•
|
incorrect estimates of reserves and related future cash flows and the inability to replace reserves
|
•
|
changes in business strategy
|
•
|
PSC effects on production and unit production costs
|
•
|
effect of stock price on costs associated with incentive compensation
|
•
|
insufficient capital, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors
|
•
|
effects of hedging transactions
|
•
|
equipment, service or labor price inflation or unavailability
|
•
|
availability or timing of, or conditions imposed on, permits and approvals
|
•
|
lower-than-expected production, reserves or resources from development projects, joint ventures or acquisitions, or higher-than-expected decline rates
|
•
|
disruptions due to accidents, mechanical failures, transportation or storage constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events
|
•
|
factors discussed in
Item 1A – Risk Factors
.
|
ITEM 7A
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
Pre-tax 2019 Price Sensitivities
|
(in millions)
|
||
$1 change in Brent index - Oil
(a)
|
$
|
24.0
|
|
$1 change in Brent index - NGLs
|
$
|
3.5
|
|
$0.10 change in NYMEX - Gas
(b)
|
$
|
3.8
|
|
(a)
|
Amount reflects the upside sensitivity.
|
(b)
|
Amount reflects the sensitivity with respect to unhedged volumes and includes the offsetting effect of internal gas use in the operations.
|
Year of Maturity
|
|
U.S. Dollar Fixed-Rate Debt
|
|
U.S. Dollar Variable-Rate Debt
|
|
Total
|
||||||
2019
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2020
|
|
100
|
|
|
—
|
|
|
100
|
|
|||
2021
|
|
491
|
|
|
1,540
|
|
|
2,031
|
|
|||
2022
(a)
|
|
1,676
|
|
|
1,300
|
|
|
2,976
|
|
|||
2023
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
2024
|
|
144
|
|
|
—
|
|
|
144
|
|
|||
Total
|
|
$
|
2,411
|
|
|
$
|
2,840
|
|
|
$
|
5,251
|
|
Weighted-average interest rate
|
|
7.65
|
%
|
|
9.13
|
%
|
|
8.45
|
%
|
|||
Fair value
|
|
$
|
1,652
|
|
|
$
|
2,840
|
|
|
$
|
4,492
|
|
(a)
|
The $1.3 billion U.S. dollar variable-rate debt is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.
|
ITEM 8
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
|
|
|
/s/ KPMG LLP
|
|
2018
|
|
2017
|
||||
CURRENT ASSETS
|
|
|
|
||||
Cash
|
$
|
17
|
|
|
$
|
20
|
|
Trade receivables
|
299
|
|
|
277
|
|
||
Inventories
|
69
|
|
|
56
|
|
||
Other current assets, net
|
255
|
|
|
130
|
|
||
Total current assets
|
640
|
|
|
483
|
|
||
PROPERTY, PLANT AND EQUIPMENT
|
22,523
|
|
|
21,260
|
|
||
Accumulated depreciation, depletion and amortization
|
(16,068
|
)
|
|
(15,564
|
)
|
||
Total property, plant and equipment, net
|
6,455
|
|
|
5,696
|
|
||
OTHER ASSETS
|
63
|
|
|
28
|
|
||
TOTAL ASSETS
|
$
|
7,158
|
|
|
$
|
6,207
|
|
|
|
|
|
||||
CURRENT LIABILITIES
|
|
|
|
||||
Accounts payable
|
390
|
|
|
257
|
|
||
Accrued liabilities
|
217
|
|
|
475
|
|
||
Total current liabilities
|
607
|
|
|
732
|
|
||
LONG-TERM DEBT
|
5,251
|
|
|
5,306
|
|
||
DEFERRED GAIN AND ISSUANCE COSTS, NET
|
216
|
|
|
287
|
|
||
OTHER LONG-TERM LIABILITIES
|
575
|
|
|
602
|
|
||
MEZZANINE EQUITY
|
|
|
|
||||
Redeemable noncontrolling interests
|
756
|
|
|
—
|
|
||
EQUITY
|
|
|
|
||||
Preferred stock (20 million shares authorized at $0.01 par value)
no shares outstanding at December 31, 2018 or 2017
|
—
|
|
|
—
|
|
||
Common stock (200 million shares authorized at $0.01 par value) outstanding shares (2018 — 48,650,420 shares and
2017 — 42,901,946 shares)
|
—
|
|
|
—
|
|
||
Additional paid-in capital
|
4,987
|
|
|
4,879
|
|
||
Accumulated deficit
|
(5,342
|
)
|
|
(5,670
|
)
|
||
Accumulated other comprehensive loss
|
(6
|
)
|
|
(23
|
)
|
||
Total equity attributable to common stock
|
(361
|
)
|
|
(814
|
)
|
||
Noncontrolling interests
|
114
|
|
|
94
|
|
||
Total equity
|
(247
|
)
|
|
(720
|
)
|
||
TOTAL LIABILITIES AND EQUITY
|
$
|
7,158
|
|
|
$
|
6,207
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
REVENUES AND OTHER
|
|
|
|
|
|
||||||
Oil and gas sales
|
$
|
2,590
|
|
|
$
|
1,936
|
|
|
$
|
1,621
|
|
Net derivative gain (loss) from commodity contracts
|
1
|
|
|
(90
|
)
|
|
(206
|
)
|
|||
Other revenue
|
473
|
|
|
160
|
|
|
132
|
|
|||
Total revenues and other
|
3,064
|
|
|
2,006
|
|
|
1,547
|
|
|||
|
|
|
|
|
|
||||||
COSTS AND OTHER
|
|
|
|
|
|
||||||
Production costs
|
912
|
|
|
876
|
|
|
800
|
|
|||
General and administrative expenses
|
299
|
|
|
249
|
|
|
235
|
|
|||
Depreciation, depletion and amortization
|
502
|
|
|
544
|
|
|
559
|
|
|||
Taxes other than on income
|
149
|
|
|
136
|
|
|
144
|
|
|||
Exploration expense
|
34
|
|
|
22
|
|
|
23
|
|
|||
Other expenses, net
|
399
|
|
|
106
|
|
|
79
|
|
|||
Total costs and other
|
2,295
|
|
|
1,933
|
|
|
1,840
|
|
|||
OPERATING INCOME (LOSS)
|
769
|
|
|
73
|
|
|
(293
|
)
|
|||
|
|
|
|
|
|
||||||
NON-OPERATING (LOSS) INCOME
|
|
|
|
|
|
||||||
Interest and debt expense, net
|
(379
|
)
|
|
(343
|
)
|
|
(328
|
)
|
|||
Net gain on early extinguishment of debt
|
57
|
|
|
4
|
|
|
805
|
|
|||
Gain on asset divestitures
|
5
|
|
|
21
|
|
|
30
|
|
|||
Other non-operating expenses
|
(23
|
)
|
|
(17
|
)
|
|
(13
|
)
|
|||
INCOME (LOSS) BEFORE INCOME TAXES
|
429
|
|
|
(262
|
)
|
|
201
|
|
|||
Income tax benefit
|
—
|
|
|
—
|
|
|
78
|
|
|||
NET INCOME (LOSS)
|
429
|
|
|
(262
|
)
|
|
279
|
|
|||
Net income attributable to noncontrolling interests
|
(101
|
)
|
|
(4
|
)
|
|
—
|
|
|||
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK
|
$
|
328
|
|
|
$
|
(266
|
)
|
|
$
|
279
|
|
|
|
|
|
|
|
||||||
Net income (loss) attributable to common stock per share
|
|
|
|
|
|
||||||
Basic
|
$
|
6.77
|
|
|
$
|
(6.26
|
)
|
|
$
|
6.76
|
|
Diluted
|
$
|
6.77
|
|
|
$
|
(6.26
|
)
|
|
$
|
6.76
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
Net income (loss)
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
279
|
|
Other comprehensive income (loss) items:
|
|
|
|
|
|
||||||
Reclassification of unrealized gains (losses) on pension and postretirement losses
(a)
|
13
|
|
|
(14
|
)
|
|
(9
|
)
|
|||
Reclassification of realized losses on pension and postretirement to income
(a)
|
4
|
|
|
5
|
|
|
10
|
|
|||
Total other comprehensive income (loss)
|
17
|
|
|
(9
|
)
|
|
1
|
|
|||
Comprehensive income attributable to noncontrolling interests
|
(101
|
)
|
|
(4
|
)
|
|
—
|
|
|||
Comprehensive income (loss) attributable to common stock
|
$
|
345
|
|
|
$
|
(275
|
)
|
|
$
|
280
|
|
(a)
|
No associated tax for 2018, 2017 and 2016. See
Note 14 Pension and Postretirement Benefit Plans
for additional information.
|
|
Additional Paid-in Capital
|
|
Accumulated (Deficit) Earnings
|
|
Accumulated Other
Comprehensive
(Loss) Income
|
|
Equity Attributable to Common Stock
|
|
Equity Attributable to Noncontrolling Interests
|
|
Total Equity
|
||||||||||||
Balance, December 31, 2015
|
$
|
4,782
|
|
|
$
|
(5,683
|
)
|
|
$
|
(15
|
)
|
|
$
|
(916
|
)
|
|
$
|
—
|
|
|
$
|
(916
|
)
|
Net income
|
—
|
|
|
279
|
|
|
—
|
|
|
279
|
|
|
—
|
|
|
279
|
|
||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||||
Share-based compensation, net
|
79
|
|
|
—
|
|
|
—
|
|
|
79
|
|
|
—
|
|
|
79
|
|
||||||
Balance, December 31, 2016
|
$
|
4,861
|
|
|
$
|
(5,404
|
)
|
|
$
|
(14
|
)
|
|
$
|
(557
|
)
|
|
$
|
—
|
|
|
$
|
(557
|
)
|
Net (loss) income
|
—
|
|
|
(266
|
)
|
|
—
|
|
|
(266
|
)
|
|
4
|
|
|
(262
|
)
|
||||||
Contribution from noncontrolling interest holders, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
98
|
|
|
98
|
|
||||||
Distributions paid to noncontrolling interest holders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
|
(8
|
)
|
||||||
Other comprehensive loss
|
—
|
|
|
—
|
|
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
|
(9
|
)
|
||||||
Share-based compensation, net
|
18
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
—
|
|
|
18
|
|
||||||
Balance, December 31, 2017
|
$
|
4,879
|
|
|
$
|
(5,670
|
)
|
|
$
|
(23
|
)
|
|
$
|
(814
|
)
|
|
$
|
94
|
|
|
$
|
(720
|
)
|
Net income
|
—
|
|
|
328
|
|
|
—
|
|
|
328
|
|
|
2
|
|
|
330
|
|
||||||
Contribution from noncontrolling interest holders, net
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
82
|
|
|
82
|
|
||||||
Distributions paid to noncontrolling interest holders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(64
|
)
|
|
(64
|
)
|
||||||
Issuance of common stock
(a)
|
101
|
|
|
—
|
|
|
—
|
|
|
101
|
|
|
—
|
|
|
101
|
|
||||||
Other comprehensive income
|
—
|
|
|
—
|
|
|
17
|
|
|
17
|
|
|
—
|
|
|
17
|
|
||||||
Share-based compensation, net
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
—
|
|
|
7
|
|
||||||
Balance, December 31, 2018
|
$
|
4,987
|
|
|
$
|
(5,342
|
)
|
|
$
|
(6
|
)
|
|
$
|
(361
|
)
|
|
$
|
114
|
|
|
$
|
(247
|
)
|
Note:
|
Excludes amounts related to redeemable noncontrolling interests recorded in mezzanine equity. See Note 5
Joint Ventures
for more information.
|
(a)
|
Includes 2.85 million shares of common stock (valued at $51 million at issuance) issued to Chevron in connection with our acquisition of Chevron's working interest in Elk Hills unit and 2.3 million shares of common stock (valued at $50 million at issuance) issued to an Ares-led investor group. See
Note 4 Acquisitions and Divestitures
and
Note 5 Joint Ventures
for more information.
|
|
2018
|
|
2017
|
|
2016
|
||||||
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
279
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
502
|
|
|
544
|
|
|
559
|
|
|||
Deferred income tax benefit
|
—
|
|
|
—
|
|
|
(78
|
)
|
|||
Net derivative (gain) loss from commodity contracts
|
(1
|
)
|
|
90
|
|
|
206
|
|
|||
Net (payments) proceeds on settled commodity derivatives
|
(228
|
)
|
|
(7
|
)
|
|
77
|
|
|||
Net gain on early extinguishment of debt
|
(57
|
)
|
|
(4
|
)
|
|
(805
|
)
|
|||
Amortization of deferred gain
|
(76
|
)
|
|
(74
|
)
|
|
(71
|
)
|
|||
Gain on asset divestitures
|
(5
|
)
|
|
(21
|
)
|
|
(30
|
)
|
|||
Other non-cash charges to income, net
|
97
|
|
|
77
|
|
|
101
|
|
|||
Dry hole expenses
|
16
|
|
|
2
|
|
|
3
|
|
|||
Changes in operating assets and liabilities, net:
|
|
|
|
|
|
||||||
Increase in trade receivables
|
(23
|
)
|
|
(45
|
)
|
|
(33
|
)
|
|||
(Increase) decrease in inventories
|
(6
|
)
|
|
2
|
|
|
—
|
|
|||
(Increase) decrease in other current assets
|
(9
|
)
|
|
(2
|
)
|
|
25
|
|
|||
Decrease in accounts payable and accrued liabilities
|
(178
|
)
|
|
(52
|
)
|
|
(103
|
)
|
|||
Net cash provided by operating activities
|
461
|
|
|
248
|
|
|
130
|
|
|||
|
|
|
|
|
|
||||||
CASH FLOW FROM INVESTING ACTIVITIES
|
|
|
|
|
|
||||||
Capital investments
|
(690
|
)
|
|
(371
|
)
|
|
(75
|
)
|
|||
Changes in capital investment accruals
|
69
|
|
|
27
|
|
|
(6
|
)
|
|||
Asset divestitures
|
18
|
|
|
33
|
|
|
20
|
|
|||
Acquisitions
|
(547
|
)
|
|
—
|
|
|
—
|
|
|||
Other
|
(6
|
)
|
|
(2
|
)
|
|
—
|
|
|||
Net cash used in investing activities
|
(1,156
|
)
|
|
(313
|
)
|
|
(61
|
)
|
|||
|
|
|
|
|
|
||||||
CASH FLOW FROM FINANCING ACTIVITIES
|
|
|
|
|
|
||||||
Proceeds from 2014 Revolving Credit Facility
|
2,823
|
|
|
1,696
|
|
|
2,218
|
|
|||
Repayments of 2014 Revolving Credit Facility
|
(2,646
|
)
|
|
(2,180
|
)
|
|
(2,110
|
)
|
|||
Proceeds from 2016 Credit Agreement
|
—
|
|
|
—
|
|
|
990
|
|
|||
Proceeds from 2017 Term Loan
|
—
|
|
|
1,274
|
|
|
—
|
|
|||
Payments on 2014 Term Loan
|
—
|
|
|
(650
|
)
|
|
(350
|
)
|
|||
Debt repurchases
|
(199
|
)
|
|
(116
|
)
|
|
(770
|
)
|
|||
Debt transaction costs
|
(4
|
)
|
|
(42
|
)
|
|
(51
|
)
|
|||
Contributions from noncontrolling interest holders, net
|
796
|
|
|
98
|
|
|
—
|
|
|||
Distributions paid to noncontrolling interest holders
|
(121
|
)
|
|
(8
|
)
|
|
—
|
|
|||
Issuance of common stock
|
54
|
|
|
3
|
|
|
4
|
|
|||
Shares canceled for taxes
|
(11
|
)
|
|
(2
|
)
|
|
—
|
|
|||
Net cash provided (used) by financing activities
|
692
|
|
|
73
|
|
|
(69
|
)
|
|||
(Decrease) increase in cash
|
(3
|
)
|
|
8
|
|
|
—
|
|
|||
Cash—beginning of year
|
20
|
|
|
12
|
|
|
12
|
|
|||
Cash—end of year
|
$
|
17
|
|
|
$
|
20
|
|
|
$
|
12
|
|
|
For the years ended
December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Beginning balance
|
$
|
422
|
|
|
$
|
411
|
|
Liabilities incurred, capitalized to PP&E
|
4
|
|
|
2
|
|
||
Liabilities settled and paid
|
(15
|
)
|
|
(9
|
)
|
||
Accretion expense
|
27
|
|
|
25
|
|
||
Acquisitions, capitalized to PP&E
(a)
|
8
|
|
|
—
|
|
||
Dispositions and other, reduction to PP&E
|
(2
|
)
|
|
—
|
|
||
Revisions in estimated cash flows, changes in PP&E
|
(11
|
)
|
|
(7
|
)
|
||
Ending balance
|
$
|
433
|
|
|
$
|
422
|
|
(a)
|
Includes $7 million related to the Elk Hills transaction and $1 million related to other acquisitions in 2018.
|
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Materials and supplies
|
$
|
65
|
|
|
$
|
53
|
|
Finished goods
|
4
|
|
|
3
|
|
||
Total
|
$
|
69
|
|
|
$
|
56
|
|
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Derivative assets
|
$
|
168
|
|
|
$
|
23
|
|
Amounts due from joint interest partners
|
68
|
|
|
76
|
|
||
Prepaid expenses
|
16
|
|
|
19
|
|
||
Assets held for sale
|
—
|
|
|
12
|
|
||
Other
|
3
|
|
|
—
|
|
||
Other current assets, net
|
$
|
255
|
|
|
$
|
130
|
|
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Accrued employee-related costs
|
$
|
109
|
|
|
$
|
86
|
|
Accrued taxes other than on income
|
38
|
|
|
130
|
|
||
Current portion of asset retirement obligation
|
31
|
|
|
19
|
|
||
Accrued interest
|
15
|
|
|
23
|
|
||
Derivative liabilities
|
3
|
|
|
154
|
|
||
Other
|
21
|
|
|
63
|
|
||
Accrued liabilities
|
$
|
217
|
|
|
$
|
475
|
|
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Proved oil and gas properties
|
$
|
20,882
|
|
|
$
|
19,664
|
|
Unproved oil and gas properties
|
1,103
|
|
|
1,111
|
|
||
Facilities and other
|
538
|
|
|
485
|
|
||
Total property, plant and equipment
|
22,523
|
|
|
21,260
|
|
||
Accumulated depreciation, depletion and amortization
|
(16,068
|
)
|
|
(15,564
|
)
|
||
Total property, plant and equipment, net
|
$
|
6,455
|
|
|
$
|
5,696
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Balance, beginning of year
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
6
|
|
Additions to capitalized exploratory well costs
|
19
|
|
|
4
|
|
|
1
|
|
|||
Reclassification to property, plant and equipment
|
(2
|
)
|
|
(2
|
)
|
|
—
|
|
|||
Charged to expense
|
(16
|
)
|
|
(2
|
)
|
|
(3
|
)
|
|||
Balance, end of year
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
4
|
|
NOTE 5
|
JOINT VENTURES
|
|
Equity Attributable to Noncontrolling Interest
|
|
Mezzanine Equity - Redeemable Noncontrolling Interest
|
||||||||||||
|
Ares JV
|
|
BSP JV
|
|
Total
|
|
Ares JV
|
||||||||
|
(in millions)
|
||||||||||||||
Balance, December 31, 2017
|
$
|
—
|
|
|
$
|
94
|
|
|
$
|
94
|
|
|
$
|
—
|
|
Net (loss) income attributable to noncontrolling interests
|
(11
|
)
|
|
13
|
|
|
2
|
|
|
99
|
|
||||
Contributions from noncontrolling interest holders, net
|
33
|
|
|
49
|
|
|
82
|
|
|
714
|
|
||||
Distributions to noncontrolling interest holders
|
(7
|
)
|
|
(57
|
)
|
|
(64
|
)
|
|
(57
|
)
|
||||
Balance, December 31, 2018
|
$
|
15
|
|
|
$
|
99
|
|
|
$
|
114
|
|
|
$
|
756
|
|
|
Outstanding Principal
(in millions)
|
|
Interest Rate
|
|
Maturity
|
|
Security
|
||||||
|
2018
|
|
2017
|
|
|
|
|
|
|
||||
Credit Agreements
|
|
|
|
|
|
|
|
|
|
||||
2014 Revolving Credit Facility
|
$
|
540
|
|
|
$
|
363
|
|
|
LIBOR plus 3.25%-4.00%
ABR plus 2.25%-3.00% |
|
June 30, 2021
|
|
Shared First-Priority Lien
|
2017 Credit Agreement
|
1,300
|
|
|
1,300
|
|
|
LIBOR plus 4.75%
ABR plus 3.75% |
|
December 31, 2022
(a)
|
|
Shared First-Priority Lien
|
||
2016 Credit Agreement
|
1,000
|
|
|
1,000
|
|
|
LIBOR plus 10.375%
ABR plus 9.375% |
|
December 31, 2021
|
|
First-Priority Lien
|
||
Second Lien Notes
|
|
|
|
|
|
|
|
|
|
||||
Second Lien Notes
|
2,067
|
|
|
2,250
|
|
|
8%
|
|
December 15, 2022
(b)
|
|
Second-Priority Lien
|
||
Senior Notes
|
|
|
|
|
|
|
|
|
|
||||
5% Senior Notes due 2020
|
100
|
|
|
100
|
|
|
5%
|
|
January 15, 2020
|
|
Unsecured
|
||
5½% Senior Notes due 2021
|
100
|
|
|
100
|
|
|
5.5%
|
|
September 15, 2021
|
|
Unsecured
|
||
6% Senior Notes due 2024
|
144
|
|
|
193
|
|
|
6%
|
|
November 15, 2024
|
|
Unsecured
|
||
Total
|
$
|
5,251
|
|
|
$
|
5,306
|
|
|
|
|
|
|
|
(a)
|
The 2017 Credit Agreement is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.
|
(b)
|
The Second Lien Notes require principal repayments of approximately $326 million in June 2021, $65 million in December 2021 and $68 million in June 2022.
|
Ratio
|
|
Components
(a)
|
|
Required Levels
|
|
Tested
|
Maximum leverage ratio
|
|
Ratio of indebtedness under our 2014 Revolving Credit Facility to trailing four-quarter Adjusted EBITDAX
|
|
Not greater than 1.90 to 1.00 through 2019
Not greater than 1.50 to 1.00 after 2019 |
|
Quarterly
|
Minimum interest coverage ratio
|
|
Ratio of Adjusted EBITDAX to consolidated cash interest charges
|
|
Not less than 1.20 to 1.00
|
|
Quarterly
|
Minimum asset coverage ratio
|
|
Ratio of PV-10 to first lien indebtedness
|
|
Not less than 1.20 to 1.00
|
|
Quarterly
|
(a)
|
Refer to the terms of our credit agreements for more detailed descriptions of the components of our financial covenants.
|
•
|
permit us to draw on our revolver to repurchase up to $300 million of our Second Lien Notes and Senior Notes at a discount to par;
|
•
|
permit us to draw on our revolver to repurchase our Second Lien Notes and Senior Notes at a discount to par, without regard to time limit, in an amount not to exceed a specified portion of proceeds from future dispositions of certain assets;
|
•
|
in connection with any repurchase of certain of our indebtedness, increase the minimum liquidity required to make such repurchase (calculated on a pro forma basis after giving effect to the repurchase) from $250 million to $300 million; and
|
•
|
enhance our ability to refinance our outstanding term loans under our 2017 Credit Agreement and 2016 Credit Agreement, Second Lien Notes and Senior Notes, in each case by allowing the use of permitted refinancing indebtedness for such refinancing so long as certain conditions are met.
|
•
|
permit us to repurchase our Second Lien Notes and Senior Notes at a discount to par, without regard to time limit, in an amount not to exceed a specified portion of proceeds from dispositions of certain assets; and
|
•
|
enhance our ability to refinance our outstanding Second Lien Notes, Senior Notes and 2016 Credit Agreement, in each case by allowing the use of permitted refinancing indebtedness for such refinancing so long as certain conditions are met.
|
2019
|
$
|
—
|
|
2020
|
100
|
|
|
2021
|
2,031
|
|
|
2022
|
2,976
|
|
|
2023
|
—
|
|
|
Thereafter
|
144
|
|
|
Total
|
$
|
5,251
|
|
2019
|
$
|
12
|
|
2020
|
8
|
|
|
2021
|
7
|
|
|
2022
|
7
|
|
|
2023
|
6
|
|
|
Thereafter
|
28
|
|
|
Total
|
$
|
68
|
|
2019
|
$
|
65
|
|
2020
|
63
|
|
|
2021
|
6
|
|
|
2022
|
4
|
|
|
2023
|
10
|
|
|
Thereafter
|
24
|
|
|
Total
|
$
|
172
|
|
|
Q1
2019
|
|
Q2
2019
|
|
Q3
2019 |
|
Q4
2019 |
|
Q1
2020
|
||||||||||
Sold Calls:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
15,000
|
|
|
5,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Weighted-average price per barrel
|
$
|
66.15
|
|
|
$
|
68.45
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Purchased Calls:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
2,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Weighted-average price per barrel
|
$
|
71.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Purchased Puts:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
38,000
|
|
|
40,000
|
|
|
40,000
|
|
|
35,000
|
|
|
10,000
|
|
|||||
Weighted-average price per barrel
|
$
|
65.66
|
|
|
$
|
69.75
|
|
|
$
|
73.13
|
|
|
$
|
75.71
|
|
|
$
|
75.00
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Sold Puts:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
40,000
|
|
|
35,000
|
|
|
40,000
|
|
|
35,000
|
|
|
10,000
|
|
|||||
Weighted-average price per barrel
|
$
|
51.88
|
|
|
$
|
55.71
|
|
|
$
|
57.50
|
|
|
$
|
60.00
|
|
|
$
|
60.00
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Swaps:
|
|
|
|
|
|
|
|
|
|
||||||||||
Barrels per day
|
7,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Weighted-average price per barrel
|
$
|
67.71
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
•
|
Sold calls – we make settlement payments for prices above the indicated weighted-average price per barrel.
|
•
|
Purchased calls – we receive settlement payments for prices above the indicated weighted-average price per barrel.
|
•
|
Purchased puts – we receive settlement payments for prices below the indicated weighted-average price per barrel.
|
•
|
Sold puts – we make settlement payments for prices below the indicated weighted-average price per barrel.
|
December 31, 2018
|
||||||||||||
Balance Sheet Classification
|
|
Gross Amounts Recognized at Fair Value
|
|
Gross Amounts Offset in the Balance Sheet
|
|
Net Fair Value Presented in the Balance Sheet
|
||||||
Assets:
|
|
|
|
|
|
|
||||||
Other current assets
|
|
$
|
252
|
|
|
$
|
(84
|
)
|
|
$
|
168
|
|
Other assets
|
|
23
|
|
|
(9
|
)
|
|
14
|
|
|||
|
|
|
|
|
|
|
||||||
Liabilities:
|
|
|
|
|
|
|
||||||
Accrued liabilities
|
|
(87
|
)
|
|
84
|
|
|
(3
|
)
|
|||
Other long-term liabilities
|
|
(10
|
)
|
|
9
|
|
|
(1
|
)
|
|||
|
|
$
|
178
|
|
|
$
|
—
|
|
|
$
|
178
|
|
December 31, 2017
|
||||||||||||
Balance Sheet Classification
|
|
Gross Amounts Recognized at Fair Value
|
|
Gross Amounts Offset in the Balance Sheet
|
|
Net Fair Value Presented in the Balance Sheet
|
||||||
Assets:
|
|
|
|
|
|
|
||||||
Other current assets
|
|
$
|
39
|
|
|
$
|
(16
|
)
|
|
$
|
23
|
|
Other assets
|
|
1
|
|
|
—
|
|
|
1
|
|
|||
|
|
|
|
|
|
|
||||||
Liabilities:
|
|
|
|
|
|
|
||||||
Accrued liabilities
|
|
(170
|
)
|
|
16
|
|
|
(154
|
)
|
|||
Other long-term liabilities
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
|||
|
|
$
|
(133
|
)
|
|
$
|
—
|
|
|
$
|
(133
|
)
|
|
For the years ended
December 31,
|
|||||||
|
2018
|
|
2017
|
|
2016
|
|||
U.S. federal statutory tax rate
|
21
|
%
|
|
(35
|
)%
|
|
35
|
%
|
State income taxes, net
|
6
|
|
|
(6
|
)
|
|
6
|
|
Exclusion of tax attributable to noncontrolling interests
|
(5
|
)
|
|
—
|
|
|
—
|
|
Decrease in U.S. federal corporate tax rate
|
—
|
|
|
91
|
|
|
—
|
|
Tax credits, net
|
(6
|
)
|
|
(19
|
)
|
|
—
|
|
Cancellation of debt income, net
|
—
|
|
|
—
|
|
|
(275
|
)
|
Stock-based compensation, net
|
—
|
|
|
1
|
|
|
2
|
|
Change in valuation allowance, net
|
(17
|
)
|
|
(33
|
)
|
|
192
|
|
Other
|
1
|
|
|
1
|
|
|
1
|
|
Effective tax rate
|
—
|
%
|
|
—
|
%
|
|
(39
|
)%
|
|
2018
|
|
2017
|
||||||||||||
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
||||||||
|
(in millions)
|
||||||||||||||
Debt
|
$
|
253
|
|
|
$
|
—
|
|
|
$
|
324
|
|
|
$
|
—
|
|
Property, plant and equipment differences
|
11
|
|
|
(316
|
)
|
|
33
|
|
|
(261
|
)
|
||||
Postretirement benefit accruals
|
27
|
|
|
—
|
|
|
33
|
|
|
—
|
|
||||
Deferred compensation and benefits
|
56
|
|
|
—
|
|
|
53
|
|
|
—
|
|
||||
Asset retirement obligations
|
129
|
|
|
—
|
|
|
126
|
|
|
—
|
|
||||
Net operating loss carryforwards and credits
|
396
|
|
|
—
|
|
|
417
|
|
|
—
|
|
||||
Investment in partnerships
|
93
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
All other
|
17
|
|
|
(41
|
)
|
|
22
|
|
|
(41
|
)
|
||||
Subtotal
|
982
|
|
|
(357
|
)
|
|
1,008
|
|
|
(302
|
)
|
||||
Valuation allowance
|
(625
|
)
|
|
—
|
|
|
(706
|
)
|
|
—
|
|
||||
Total net deferred taxes
|
$
|
357
|
|
|
$
|
(357
|
)
|
|
$
|
302
|
|
|
$
|
(302
|
)
|
|
Stock-Settled
|
|
Cash-Settled
|
||||||
|
Number of Units
(in thousands)
|
|
Weighted-Average Grant-Date Fair Value
|
|
Number of Units
(in thousands) |
||||
Unvested at January 1
|
1,035
|
|
|
$
|
16.04
|
|
|
2,066
|
|
Granted
(a)
|
291
|
|
|
$
|
20.62
|
|
|
1,656
|
|
Vested
|
(466
|
)
|
|
$
|
16.57
|
|
|
(903
|
)
|
Forfeited
|
(41
|
)
|
|
$
|
16.33
|
|
|
(183
|
)
|
Unvested at December 31
|
819
|
|
|
$
|
17.36
|
|
|
2,636
|
|
(a)
|
During
2018
and
2017
, our non-employee directors were granted stock-settled RSUs representing approximately 46,000 and 98,000 shares, respectively.
|
|
Modification Date
|
|
Grant Date
|
||||
Risk-free interest rate
|
0.77
|
%
|
|
1.06
|
%
|
||
Dividend yield
|
—
|
%
|
|
0.95
|
%
|
||
Volatility factor
|
69.69
|
%
|
|
43.63
|
%
|
||
Expected life (years)
|
2.16
|
|
|
2.9
|
|
||
Fair value of underlying common stock
|
$
|
18.50
|
|
|
$
|
42.00
|
|
|
Stock-Settled
|
|
Cash-Settled
|
||||||
|
Number of Awards
(in thousands) |
|
Weighted-Average Grant-Date Fair Value
|
|
Number of Units
(in thousands) |
||||
Unvested at January 1
|
384
|
|
|
$
|
39.05
|
|
|
—
|
|
Granted
|
306
|
|
|
$
|
18.34
|
|
|
204
|
|
Vested
|
(384
|
)
|
|
$
|
39.05
|
|
|
—
|
|
Forfeited
|
(12
|
)
|
|
$
|
18.34
|
|
|
(8
|
)
|
Unvested at December 31
|
294
|
|
|
$
|
18.34
|
|
|
196
|
|
|
2018
|
|
2015
|
|
2014
|
||||||
Exercise price per share
|
$
|
20.17
|
|
|
$
|
42.00
|
|
|
$
|
81.10
|
|
Expected life (in years)
|
4.5
|
|
|
4.5
|
|
|
4.5
|
|
|||
Expected volatility
|
69.85
|
%
|
|
44.7
|
%
|
|
35.4
|
%
|
|||
Risk-free interest rate
|
2.63
|
%
|
|
1.56
|
%
|
|
1.40
|
%
|
|||
Dividend yield
|
—
|
%
|
|
0.95
|
%
|
|
0.50
|
%
|
|||
Grant-date fair value of stock option awards
|
$
|
10.02
|
|
|
$
|
15.00
|
|
|
$
|
19.80
|
|
|
Options
(000's)
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Grant-Date Fair Value
|
|
Aggregate Intrinsic Value
|
|||||||
Beginning balance, January 1
|
1,105
|
|
|
$
|
69.95
|
|
|
$
|
18.43
|
|
|
$
|
—
|
|
Granted
|
187
|
|
|
$
|
20.17
|
|
|
$
|
10.02
|
|
|
$
|
—
|
|
Exercised
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Forfeited
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Expired or Canceled
|
(5
|
)
|
|
$
|
42.00
|
|
|
$
|
15.00
|
|
|
$
|
—
|
|
Ending balance, December 31
|
1,287
|
|
|
$
|
62.82
|
|
|
$
|
17.22
|
|
|
$
|
—
|
|
Exercisable at December 31
|
1,109
|
|
|
$
|
69.66
|
|
|
$
|
18.38
|
|
|
$
|
—
|
|
|
Common Stock
|
|
|
(in thousands)
|
|
Balance, December 31, 2016
|
42,543
|
|
Issued
|
359
|
|
Balance, December 31, 2017
|
42,902
|
|
Issued
|
6,110
|
|
Canceled
|
(362
|
)
|
Balance, December 31, 2018
|
48,650
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions, except per share amounts)
|
||||||||||
Basic EPS calculation
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
279
|
|
Less: Net income attributable to noncontrolling interests
|
(101
|
)
|
|
(4
|
)
|
|
—
|
|
|||
Net income (loss) attributable to common stock
|
328
|
|
|
(266
|
)
|
|
279
|
|
|||
Less: Net income allocated to participating securities
|
(7
|
)
|
|
—
|
|
|
(6
|
)
|
|||
Net income (loss) available to common stockholders
|
$
|
321
|
|
|
$
|
(266
|
)
|
|
$
|
273
|
|
Weighted-average common shares outstanding
|
47.4
|
|
|
42.5
|
|
|
40.4
|
|
|||
Basic EPS
|
$
|
6.77
|
|
|
$
|
(6.26
|
)
|
|
$
|
6.76
|
|
|
|
|
|
|
|
||||||
Diluted EPS calculation
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
429
|
|
|
$
|
(262
|
)
|
|
$
|
279
|
|
Less: Net income attributable to noncontrolling interests
|
(101
|
)
|
|
(4
|
)
|
|
—
|
|
|||
Net income (loss) attributable to common stock
|
328
|
|
|
(266
|
)
|
|
279
|
|
|||
Less: Net income allocated to participating securities
|
(7
|
)
|
|
—
|
|
|
(6
|
)
|
|||
Net income (loss) available to common stockholders
|
$
|
321
|
|
|
$
|
(266
|
)
|
|
$
|
273
|
|
Weighted-average common shares outstanding
|
47.4
|
|
|
42.5
|
|
|
40.4
|
|
|||
Dilutive effect of potentially dilutive securities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Diluted EPS
|
$
|
6.77
|
|
|
$
|
(6.26
|
)
|
|
$
|
6.76
|
|
Weighted-average anti-dilutive shares
(a)
|
1.6
|
|
|
2.3
|
|
|
1.1
|
|
(a)
|
Anti-dilutive shares represent potential common shares that are excluded from the computation of diluted EPS.
|
|
As of December 31,
|
||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||
|
(in millions)
|
||||||||||||||
Amounts recognized in the balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accrued liabilities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
(3
|
)
|
Other long-term liabilities
|
(14
|
)
|
|
(19
|
)
|
|
(82
|
)
|
|
(90
|
)
|
||||
|
$
|
(14
|
)
|
|
$
|
(19
|
)
|
|
$
|
(84
|
)
|
|
$
|
(93
|
)
|
|
|
|
|
|
|
|
|
||||||||
Amounts recognized in accumulated other comprehensive (loss) income:
|
$
|
(10
|
)
|
|
$
|
(13
|
)
|
|
$
|
4
|
|
|
$
|
(10
|
)
|
|
As of December 31,
|
||||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||
|
(in millions)
|
||||||||||||||
Changes in the benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Benefit obligation—beginning of year
|
$
|
65
|
|
|
$
|
70
|
|
|
$
|
93
|
|
|
$
|
77
|
|
Service cost—benefits earned during the period
|
1
|
|
|
1
|
|
|
4
|
|
|
3
|
|
||||
Interest cost on projected benefit obligation
|
2
|
|
|
2
|
|
|
4
|
|
|
4
|
|
||||
Actuarial (gain) loss
|
(2
|
)
|
|
7
|
|
|
(14
|
)
|
|
11
|
|
||||
Benefits paid
|
(10
|
)
|
|
(15
|
)
|
|
(3
|
)
|
|
(2
|
)
|
||||
Benefit obligation—end of year
|
$
|
56
|
|
|
$
|
65
|
|
|
$
|
84
|
|
|
$
|
93
|
|
|
|
|
|
|
|
|
|
||||||||
Changes in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Fair value of plan assets—beginning of year
|
$
|
46
|
|
|
$
|
44
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
(2
|
)
|
|
5
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
8
|
|
|
12
|
|
|
3
|
|
|
2
|
|
||||
Benefits paid
|
(10
|
)
|
|
(15
|
)
|
|
(3
|
)
|
|
(2
|
)
|
||||
Fair value of plan assets—end of year
|
$
|
42
|
|
|
$
|
46
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Unfunded status
|
$
|
(14
|
)
|
|
$
|
(19
|
)
|
|
$
|
(84
|
)
|
|
$
|
(93
|
)
|
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Projected Benefit Obligation
|
$
|
56
|
|
|
$
|
65
|
|
Accumulated Benefit Obligation
|
$
|
53
|
|
|
$
|
62
|
|
Fair Value of Plan Assets
|
$
|
42
|
|
|
$
|
46
|
|
|
For the years ended December 31,
|
||||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||||||||||
|
(in millions)
|
||||||||||||||||||||||
Net periodic benefit costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Service cost—benefits earned during the period
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
3
|
|
Interest cost on projected benefit obligation
|
2
|
|
|
2
|
|
|
3
|
|
|
4
|
|
|
4
|
|
|
3
|
|
||||||
Expected return on plan assets
|
(3
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net actuarial loss
|
2
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Settlement costs
|
4
|
|
|
5
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost
|
$
|
6
|
|
|
$
|
7
|
|
|
$
|
11
|
|
|
$
|
8
|
|
|
$
|
7
|
|
|
$
|
6
|
|
|
For the years ended December 31,
|
||||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||||||||||
|
(in millions)
|
||||||||||||||||||||||
Amounts recognized in other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net actuarial (loss) gain
|
$
|
(3
|
)
|
|
$
|
(4
|
)
|
|
$
|
(9
|
)
|
|
$
|
14
|
|
|
$
|
(12
|
)
|
|
$
|
—
|
|
Settlement costs
|
4
|
|
|
5
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net actuarial gain/loss
|
2
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total recognized in other comprehensive income (loss)
|
$
|
3
|
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
14
|
|
|
$
|
(12
|
)
|
|
$
|
—
|
|
|
For the years ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
Benefit Obligation Assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
4.22
|
%
|
|
3.53
|
%
|
|
4.57
|
%
|
|
3.87
|
%
|
Rate of compensation increase
|
4.00
|
%
|
|
4.00
|
%
|
|
—
|
|
|
—
|
|
Net Periodic Benefit Cost Assumptions:
|
|
|
|
|
|
|
|
||||
Discount rate
|
3.53
|
%
|
|
3.88
|
%
|
|
3.87
|
%
|
|
4.58
|
%
|
Assumed long-term rate of return on assets
|
6.50
|
%
|
|
6.50
|
%
|
|
—
|
|
|
—
|
|
Rate of compensation increase
|
4.00
|
%
|
|
4.00
|
%
|
|
—
|
|
|
—
|
|
|
Fair Value Measurements at
December 31, 2018
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Asset Class:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cash equivalents
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Commingled funds:
|
|
|
|
|
|
|
|
||||||||
Fixed income
|
—
|
|
|
9
|
|
|
—
|
|
|
9
|
|
||||
U.S. equity
|
—
|
|
|
9
|
|
|
—
|
|
|
9
|
|
||||
International equity
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
|
|
||||||
Bond funds
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Blend funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Value funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Growth funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Guaranteed deposit account
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
||||
Total pension plan assets
|
$
|
12
|
|
|
$
|
23
|
|
|
$
|
7
|
|
|
$
|
42
|
|
|
Fair Value Measurements at
December 31, 2017 |
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Asset Class:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cash equivalents
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Commingled funds:
|
|
|
|
|
|
|
|
||||||||
Fixed income
|
—
|
|
|
7
|
|
|
—
|
|
|
7
|
|
||||
U.S. equity
|
—
|
|
|
9
|
|
|
—
|
|
|
9
|
|
||||
International equity
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
|
|
||||||
Bond funds
|
6
|
|
|
—
|
|
|
—
|
|
|
6
|
|
||||
Blend funds
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Value funds
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Growth funds
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Guaranteed deposit account
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
||||
Total pension plan assets
|
$
|
18
|
|
|
$
|
21
|
|
|
$
|
7
|
|
|
$
|
46
|
|
For the years ended December 31,
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||
|
(in millions)
|
||||||
2019
|
$
|
17
|
|
|
$
|
3
|
|
2020
|
$
|
5
|
|
|
$
|
4
|
|
2021
|
$
|
4
|
|
|
$
|
4
|
|
2022
|
$
|
4
|
|
|
$
|
4
|
|
2023
|
$
|
4
|
|
|
$
|
4
|
|
2024 - 2028
|
$
|
14
|
|
|
$
|
23
|
|
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Oil and gas sales:
|
|
|
|
|
|
||||||
Oil
|
$
|
2,110
|
|
|
$
|
1,549
|
|
|
$
|
1,325
|
|
NGLs
|
260
|
|
|
210
|
|
|
132
|
|
|||
Natural gas
|
220
|
|
|
177
|
|
|
164
|
|
|||
|
2,590
|
|
|
1,936
|
|
|
1,621
|
|
|||
Other revenue:
|
|
|
|
|
|
||||||
Electricity
|
111
|
|
|
125
|
|
|
107
|
|
|||
Marketing, trading and other
|
361
|
|
|
35
|
|
|
25
|
|
|||
Interest income
|
1
|
|
|
—
|
|
|
—
|
|
|||
|
473
|
|
|
160
|
|
|
132
|
|
|||
Net derivative gain from commodity contracts
|
1
|
|
|
(90
|
)
|
|
(206
|
)
|
|||
Total revenues and other
|
$
|
3,064
|
|
|
$
|
2,006
|
|
|
$
|
1,547
|
|
|
2018
|
||||||||||
|
As Reported
ASC 606
|
|
Previous
GAAP
|
|
Change
|
||||||
|
(in millions)
|
||||||||||
Oil and gas sales
|
$
|
2,590
|
|
|
$
|
2,568
|
|
|
$
|
22
|
|
Other revenue
|
$
|
473
|
|
|
$
|
392
|
|
|
$
|
81
|
|
Other expenses, net
|
$
|
399
|
|
|
$
|
296
|
|
|
$
|
103
|
|
|
|
2018
|
|
2017
|
||||||||||||||||||||||||||||
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||||||||||
|
|
(in millions, except per share amounts)
|
||||||||||||||||||||||||||||||
Revenues and other
(a)
|
|
$
|
609
|
|
|
$
|
549
|
|
|
$
|
828
|
|
|
$
|
1,078
|
|
|
$
|
590
|
|
|
$
|
516
|
|
|
$
|
445
|
|
|
$
|
455
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Operating income (loss)
(b)
|
|
$
|
108
|
|
|
$
|
11
|
|
|
$
|
185
|
|
|
$
|
465
|
|
|
$
|
115
|
|
|
$
|
41
|
|
|
$
|
(45
|
)
|
|
$
|
(38
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net (loss) income attributable to common stock
(c)
|
|
$
|
(2
|
)
|
|
$
|
(82
|
)
|
|
$
|
66
|
|
|
$
|
346
|
|
|
$
|
53
|
|
|
$
|
(48
|
)
|
|
$
|
(133
|
)
|
|
$
|
(138
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net (loss) income attributable to common stock per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Basic
|
|
$
|
(0.05
|
)
|
|
$
|
(1.70
|
)
|
|
$
|
1.34
|
|
|
$
|
7.00
|
|
|
$
|
1.23
|
|
|
$
|
(1.13
|
)
|
|
$
|
(3.11
|
)
|
|
$
|
(3.23
|
)
|
Diluted
|
|
$
|
(0.05
|
)
|
|
$
|
(1.70
|
)
|
|
$
|
1.32
|
|
|
$
|
7.00
|
|
|
$
|
1.22
|
|
|
$
|
(1.13
|
)
|
|
$
|
(3.11
|
)
|
|
$
|
(3.23
|
)
|
(a)
|
We adopted the new revenue recognition standard on January 1, 2018 which required certain sales-related costs to be reported as expense as opposed to being netted against revenue. The adoption of this standard did not affect net income. Results for reporting periods beginning January 1, 2018 are presented under the new accounting standard while prior periods were not adjusted and continue to be reported under accounting standards in effect for the applicable period.
|
(b)
|
For 2017, certain pension benefit costs of have been reclassified to other non-operating expenses to conform to the current year presentation in accordance with new accounting rules adopted on January 1, 2018 related to the presentation of net periodic benefit costs for pension and postretirement benefits in the Consolidated Statements of Operations. See
Item 8 – Financial Statement and Supplementary Data – Note 2 Accounting and Disclosure Changes
for more information.
|
(c)
|
Net (loss) income attributable to common stock included the following unusual, infrequent and other items:
|
|
2018
|
|
2017
|
||||||||||||||||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||||||||||
|
(in millions)
|
||||||||||||||||||||||||||||||
Non-cash derivative loss (gain) from commodities, excluding noncontrolling interest
|
$
|
7
|
|
|
$
|
92
|
|
|
$
|
(28
|
)
|
|
$
|
(295
|
)
|
|
$
|
(75
|
)
|
|
$
|
(35
|
)
|
|
$
|
72
|
|
|
$
|
116
|
|
Non-cash derivative loss from interest-rate contracts
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Early retirement, severance and other costs
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
1
|
|
|
$
|
1
|
|
Net gain on early extinguishment of debt
|
$
|
—
|
|
|
$
|
(24
|
)
|
|
$
|
(2
|
)
|
|
$
|
(31
|
)
|
|
$
|
(4
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Gain on asset divestitures
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
(3
|
)
|
|
$
|
(1
|
)
|
|
$
|
(21
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Other, net
|
$
|
1
|
|
|
$
|
(2
|
)
|
|
$
|
9
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
5
|
|
|
$
|
8
|
|
|
$
|
7
|
|
|
Oil
(MMBbl)
(a)
|
|
NGLs
(MMBbl)
|
|
Natural Gas
(Bcf)
|
|
Total
(MMBoe)
(b)
|
||||
Balance at December 31, 2015
|
466
|
|
|
59
|
|
|
715
|
|
|
644
|
|
Revisions of previous estimates
(c)
|
(40
|
)
|
|
—
|
|
|
(42
|
)
|
|
(47
|
)
|
Improved recovery
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Extensions and discoveries
|
14
|
|
|
2
|
|
|
25
|
|
|
20
|
|
Purchases
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
Production
|
(33
|
)
|
|
(6
|
)
|
|
(72
|
)
|
|
(51
|
)
|
Balance at December 31, 2016
|
409
|
|
|
55
|
|
|
626
|
|
|
568
|
|
Revisions of previous estimates
(c)
|
47
|
|
|
7
|
|
|
104
|
|
|
71
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
24
|
|
|
2
|
|
|
45
|
|
|
34
|
|
Purchases
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales
|
(8
|
)
|
|
—
|
|
|
(3
|
)
|
|
(8
|
)
|
Production
|
(30
|
)
|
|
(6
|
)
|
|
(66
|
)
|
|
(47
|
)
|
Balance at December 31, 2017
|
442
|
|
|
58
|
|
|
706
|
|
|
618
|
|
Revisions of previous estimates
(c)
|
51
|
|
|
(4
|
)
|
|
(15
|
)
|
|
44
|
|
Improved recovery
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Extensions and discoveries
|
25
|
|
|
1
|
|
|
27
|
|
|
30
|
|
Purchases
|
38
|
|
|
11
|
|
|
89
|
|
|
64
|
|
Sales
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(30
|
)
|
|
(6
|
)
|
|
(73
|
)
|
|
(48
|
)
|
Balance at December 31, 2018
|
530
|
|
|
60
|
|
|
734
|
|
|
712
|
|
|
|
|
|
|
|
|
|
||||
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
338
|
|
|
47
|
|
|
575
|
|
|
481
|
|
December 31, 2016
|
279
|
|
|
44
|
|
|
500
|
|
|
406
|
|
December 31, 2017
|
304
|
|
|
45
|
|
|
543
|
|
|
440
|
|
December 31, 2018
(d)
|
389
|
|
|
47
|
|
|
565
|
|
|
530
|
|
|
|
|
|
|
|
|
|
||||
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
|
128
|
|
|
12
|
|
|
140
|
|
|
163
|
|
December 31, 2016
|
130
|
|
|
11
|
|
|
126
|
|
|
162
|
|
December 31, 2017
|
138
|
|
|
13
|
|
|
163
|
|
|
178
|
|
December 31, 2018
|
141
|
|
|
13
|
|
|
169
|
|
|
182
|
|
(a)
|
Includes proved reserves related to economic arrangements similar to PSCs of
131
MMBbl, 108 MMBbl, 85 MMBbl and 103 MMBbl at December 31,
2018
,
2017
,
2016
and 2015, respectively.
|
(b)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six Mcf of natural gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
(c)
|
Commodity price changes affect the proved reserves we record. For example, higher prices generally increase the economically recoverable reserves in all of our operations, because the extra margin extends their expected lives and renders more projects economic. Partially offsetting this effect, higher prices decrease our share of proved cost recovery reserves under arrangements similar to production-sharing contracts at our Wilmington field in Long Beach because fewer reserves are required to recover costs. Conversely, when prices drop, we experience the opposite effects. Performance-related revisions can include upward or downward changes to previous proved reserves estimates due to the evaluation or interpretation of recent geologic, production decline or operating performance data.
|
(d)
|
Approximately
23%
of proved developed oil reserves,
9%
of proved developed NGLs reserves,
13%
of proved developed natural gas reserves and, overall,
20%
of total proved developed reserves are non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full peak production response has not yet occurred due to the nature of such projects.
|
|
As of December 31,
|
||||||
|
2018
|
|
2017
|
||||
|
(in millions)
|
||||||
Proved properties
|
$
|
20,883
|
|
|
$
|
19,664
|
|
Unproved properties
|
1,103
|
|
|
1,111
|
|
||
Total capitalized costs
(a)
|
21,986
|
|
|
20,775
|
|
||
Accumulated depreciation, depletion and amortization
(b)
|
(15,839
|
)
|
|
(15,391
|
)
|
||
Net capitalized costs
|
$
|
6,147
|
|
|
$
|
5,384
|
|
(a)
|
Includes acquisition and development costs.
|
(b)
|
Includes accumulated valuation allowance for total unproved properties of $819 million at December 31,
2018
,
2017
and
2016
.
|
|
For the years ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Property acquisition costs
|
|
|
|
|
|
||||||
Proved properties
(a)
|
$
|
553
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Unproved properties
|
1
|
|
|
—
|
|
|
—
|
|
|||
Exploration costs
|
38
|
|
|
25
|
|
|
21
|
|
|||
Development costs
(b)
|
652
|
|
|
357
|
|
|
102
|
|
|||
Costs incurred
|
$
|
1,244
|
|
|
$
|
382
|
|
|
$
|
123
|
|
(a)
|
Acquisition costs capitalized to proved properties include $8 million of liabilities assumed related to ARO in 2018.
|
(b)
|
Development costs include a $7 million decrease, a $5 million decrease and a $49 million increase in ARO in
2018
,
2017
and
2016
, respectively.
|
|
For the years ended December 31,
|
||||||||||||||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||||||||||||||
|
(millions)
|
|
($/Boe)
(a)
|
|
(millions)
|
|
($/Boe)
(a)
|
|
(millions)
|
|
($/Boe)
(a)
|
||||||||||||
Revenues
(b)
|
$
|
2,378
|
|
|
$
|
49.23
|
|
|
$
|
1,931
|
|
|
$
|
41.09
|
|
|
$
|
1,700
|
|
|
$
|
33.17
|
|
Production costs
(c)
|
912
|
|
|
18.88
|
|
|
876
|
|
|
18.64
|
|
|
800
|
|
|
15.61
|
|
||||||
General and administrative expenses
(d)
|
49
|
|
|
1.01
|
|
|
33
|
|
|
0.70
|
|
|
35
|
|
|
0.68
|
|
||||||
Adjusted other operating expenses
(e)
|
66
|
|
|
1.38
|
|
|
26
|
|
|
0.56
|
|
|
34
|
|
|
0.67
|
|
||||||
Depreciation, depletion and amortization
|
469
|
|
|
9.71
|
|
|
510
|
|
|
10.85
|
|
|
527
|
|
|
10.28
|
|
||||||
Taxes other than on income
|
117
|
|
|
2.42
|
|
|
110
|
|
|
2.34
|
|
|
121
|
|
|
2.36
|
|
||||||
Exploration expenses
|
34
|
|
|
0.70
|
|
|
22
|
|
|
0.47
|
|
|
23
|
|
|
0.45
|
|
||||||
Pretax income
|
731
|
|
|
15.13
|
|
|
354
|
|
|
7.53
|
|
|
160
|
|
|
3.12
|
|
||||||
Income tax expense
(f)
|
(181
|
)
|
|
(3.75
|
)
|
|
(116
|
)
|
|
(2.47
|
)
|
|
(65
|
)
|
|
(1.27
|
)
|
||||||
Results of operations
|
$
|
550
|
|
|
$
|
11.38
|
|
|
$
|
238
|
|
|
$
|
5.06
|
|
|
$
|
95
|
|
|
$
|
1.85
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content of six Mcf of natural gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
|
(b)
|
Revenues include cash settlements on our commodity derivatives which are reported in net derivative (gain) loss from commodity contracts on our consolidated statements of operations. Revenues also include sales related to processing third-party gas which are reported in other revenue on the consolidated statements of operations.
|
(c)
|
Production costs are the costs incurred in lifting the oil and natural gas to the surface and include gathering, processing, field storage and insurance on proved properties. Production costs on a per Boe basis, excluding the effects of PSC contracts, were
$17.47
, $17.48 and $14.69 for
2018
,
2017
and
2016
, respectively.
|
(d)
|
For the years ended December 31, 2017 and 2016, certain pension benefit costs of $1 million and $2 million, respectively, have been reclassified to other non-operating expenses to conform to the current year presentation in accordance with new accounting rules adopted on January 1, 2018 related to the presentation of net periodic benefit costs for pension and postretirement benefits in the Consolidated Statements of Operations. See
Item 8 – Financial Statement and Supplementary Data – Note 2 Accounting and Disclosure Changes
for more information.
|
(e)
|
Other operating expenses include accretion expense in 2018, 2017 and 2016. Other operating expenses in 2018 also include wet gas purchases from third parties, transportation and other expenses due to the adoption of a new accounting standard related to revenue recognition on January 1, 2018. Adjusted other operating expenses for 2018 exclude net unusual and infrequent gains of $10 million ($0.21 per Boe) that include receivables and refunds partially offset by rig termination expenses. For 2017, the amounts exclude net unusual and infrequent charges of $5 million ($0.10 per Boe) primarily related to rig termination expenses partially offset by property tax refunds, recovery of amounts due from joint interest partners and other items. For 2016, the amounts exclude net unusual and infrequent gains of $18 million ($0.35 per Boe) that include refunds partially offset by plant turnaround charges and other items.
|
(f)
|
Income taxes are calculated on the basis of a stand-alone tax filing entity. The combined U.S. federal and California statutory tax rate for 2018 was 28% as compared to 41% in both 2017 and 2016. The top corporate tax rate was reduced beginning January 1, 2018 as a result of tax reform legislation enacted on December 22, 2017. The effective tax rate for 2018 and 2017 reflects the benefit of enhanced oil recovery tax credits.
|
|
At December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Future cash inflows
|
$
|
42,325
|
|
|
$
|
26,685
|
|
|
$
|
18,831
|
|
Future costs
|
|
|
|
|
|
|
|
|
|||
Production costs
(a)
|
(19,452
|
)
|
|
(13,988
|
)
|
|
(10,092
|
)
|
|||
Development costs
(b)
|
(4,432
|
)
|
|
(3,848
|
)
|
|
(3,376
|
)
|
|||
Future income tax expense
|
(4,231
|
)
|
|
(1,585
|
)
|
|
(340
|
)
|
|||
Future net cash flows
|
14,210
|
|
|
7,264
|
|
|
5,023
|
|
|||
Ten percent discount factor
|
(6,935
|
)
|
|
(3,499
|
)
|
|
(2,356
|
)
|
|||
Standardized measure of discounted future net cash flows
|
$
|
7,275
|
|
|
$
|
3,765
|
|
|
$
|
2,667
|
|
(a)
|
Includes general and administrative expenses and taxes other than on income.
|
(b)
|
Includes asset retirement costs.
|
|
For the years ended December 31,
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
|
(in millions)
|
||||||||||
Beginning of year
|
$
|
3,765
|
|
|
$
|
2,667
|
|
|
$
|
4,024
|
|
Sales of oil and natural gas, net of production and other operating costs
|
(1,511
|
)
|
|
(918
|
)
|
|
(742
|
)
|
|||
Changes in price, net of production and other operating costs
|
3,648
|
|
|
1,405
|
|
|
(2,297
|
)
|
|||
Previously estimated development costs incurred
|
351
|
|
|
159
|
|
|
62
|
|
|||
Change in estimated future development costs
|
(38
|
)
|
|
(98
|
)
|
|
89
|
|
|||
Extensions, discoveries and improved recovery, net of costs
|
443
|
|
|
177
|
|
|
117
|
|
|||
Revisions of previous quantity estimates
(a)
|
738
|
|
|
737
|
|
|
(247
|
)
|
|||
Accretion of discount
|
427
|
|
|
260
|
|
|
458
|
|
|||
Net change in income taxes
|
(1,356
|
)
|
|
(599
|
)
|
|
854
|
|
|||
Purchases and sales of reserves in place
|
766
|
|
|
(43
|
)
|
|
(4
|
)
|
|||
Changes in production rates and other
|
42
|
|
|
18
|
|
|
353
|
|
|||
Net change
|
3,510
|
|
|
1,098
|
|
|
(1,357
|
)
|
|||
End of year
|
$
|
7,275
|
|
|
$
|
3,765
|
|
|
$
|
2,667
|
|
(a)
|
Includes revisions related to performance and price changes.
|
(in millions)
|
Balance at Beginning of Period
|
|
Charged (Credited) to Costs and Expenses
|
|
Charged to Other Accounts
|
|
Deductions
|
|
Balance at End of Period
|
||||||||||
2018
|
|
|
|
|
|
|
|
|
|
||||||||||
Deferred tax valuation allowance
|
$
|
706
|
|
|
$
|
(76
|
)
|
|
$
|
(5
|
)
|
|
$
|
—
|
|
|
$
|
625
|
|
Other asset valuation allowance
|
$
|
44
|
|
|
$
|
(13
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
31
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2017
|
|
|
|
|
|
|
|
|
|
||||||||||
Deferred tax valuation allowance
|
$
|
780
|
|
|
$
|
(78
|
)
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
706
|
|
Other asset valuation allowance
|
$
|
56
|
|
|
$
|
(12
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
44
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Deferred tax valuation allowance
|
$
|
382
|
|
|
$
|
398
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
780
|
|
Other asset valuation allowance
|
$
|
68
|
|
|
$
|
(12
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
56
|
|
ITEM 9
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
ITEM 9A
|
CONTROLS AND PROCEDURES
|
ITEM 9B
|
OTHER INFORMATION
|
ITEM 10
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
ITEM 11
|
EXECUTIVE COMPENSATION
|
ITEM 12
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
ITEM 13
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
|
ITEM 14
|
PRINCIPAL ACCOUNTANT FEES AND SERVICES
|
ITEM 15
|
EXHIBITS
|
•
|
should not be treated as categorical statements of fact, but rather as a way of allocating the risk among the parties if those statements prove to be inaccurate;
|
•
|
have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
|
•
|
may apply standards of materiality in a way that is different from the way the Company and investors may view materiality; and
|
•
|
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
|
Exhibit Number
|
|
Exhibit Description
|
2.1
|
|
|
|
|
|
3.1
|
|
|
|
|
|
3.2
|
|
|
|
|
|
4.1
|
|
|
|
|
|
4.2
|
|
|
|
|
|
4.3
|
|
|
|
|
|
4.4
|
|
|
|
|
|
4.5
|
|
|
|
|
|
Exhibit Number
|
|
Exhibit Description
|
4.6
|
|
|
|
|
|
4.7
|
|
|
|
|
|
4.8
|
|
|
|
|
|
4.9
|
|
|
|
|
|
4.10
|
|
|
|
|
|
4.11
|
|
|
|
|
|
4.12
|
|
|
|
|
|
4.13
|
|
|
|
|
|
4.14
|
|
|
|
|
|
4.15
|
|
|
|
|
|
10.1
|
|
|
|
|
|
10.2
|
|
|
|
|
|
10.3
|
|
|
|
|
|
10.4
|
|
|
|
|
|
Exhibit Number
|
|
Exhibit Description
|
10.5
|
|
|
|
|
|
10.6
|
|
|
|
|
|
10.7
|
|
|
|
|
|
10.8
|
|
|
|
|
|
10.9
|
|
|
|
|
|
10.10
|
|
|
|
|
|
10.11
|
|
|
|
|
|
10.12
|
|
|
|
|
|
10.13
|
|
|
|
|
|
10.14
|
|
|
|
|
|
10.15
|
|
|
|
|
|
10.16
|
|
|
|
|
|
10.17
|
|
|
|
|
|
10.18
|
|
|
|
|
|
Exhibit Number
|
|
Exhibit Description
|
10.19
|
|
|
|
|
|
10.20
|
|
|
|
|
|
10.21
|
|
|
|
|
|
10.22
|
|
|
|
|
|
10.23
|
|
|
|
|
|
10.24
|
|
|
|
|
|
10.25
|
|
|
|
|
|
10.26
|
|
|
|
|
|
10.27
|
|
|
|
|
|
|
|
The following are management contracts and compensatory plans required to be identified specifically as responsive to Item 601(b)(10)(iii)(A) of Regulation S-K pursuant to Item 15(b) of Form 10-K.
|
|
|
|
10.28
|
|
|
|
|
|
10.29
|
|
|
|
|
|
10.30
|
|
|
|
|
|
10.31
|
|
|
|
|
|
10.32
|
|
|
|
|
|
Exhibit Number
|
|
Exhibit Description
|
10.33
|
|
|
|
|
|
10.34
|
|
|
|
|
|
10.35
|
|
|
|
|
|
10.36
|
|
|
|
|
|
10.37*
|
|
|
|
|
|
10.38
|
|
|
|
|
|
10.39
|
|
|
|
|
|
10.40
|
|
|
|
|
|
10.41
|
|
|
|
|
|
10.42
|
|
|
|
|
|
10.43
|
|
|
|
|
|
10.44
|
|
|
|
|
|
10.45
|
|
|
|
|
|
10.46
|
|
|
|
|
|
10.47
|
|
|
|
|
|
10.48
|
|
|
|
|
|
10.49
|
|
|
|
|
|
10.50
|
|
|
|
|
|
Exhibit Number
|
|
Exhibit Description
|
10.51
|
|
|
|
|
|
10.52
|
|
|
|
|
|
10.53
|
|
|
|
|
|
10.54
|
|
|
|
|
|
10.55
|
|
|
|
|
|
21*
|
|
|
|
|
|
23.1*
|
|
|
|
|
|
23.2*
|
|
|
|
|
|
31.1*
|
|
|
|
|
|
31.2*
|
|
|
|
|
|
32.1*
|
|
|
|
|
|
99.1*
|
|
|
|
|
|
101.INS*
|
|
XBRL Instance Document.
|
|
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document.
|
|
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
|
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
|
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
|
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
|
CALIFORNIA RESOURCES CORPORATION
|
|
|
|
|
February 27, 2019
|
By:
|
/s/ Todd A. Stevens
|
|
|
Todd A. Stevens
|
|
|
President
|
|
|
and Chief Executive Officer
|
|
|
|
Title
|
Date
|
|
|
|
|
|
|
/s/ Todd A. Stevens
|
|
President,
|
February 27, 2019
|
|
Todd A. Stevens
|
|
Chief Executive Officer and Director
|
|
|
|
|
|
|
|
/s/ Marshall D. Smith
|
|
Senior Executive Vice President and
|
February 27, 2019
|
|
Marshall D. Smith
|
|
Chief Financial Officer
|
|
|
|
|
|
|
|
/s/ Roy Pineci
|
|
Executive Vice President - Finance and
|
February 27, 2019
|
|
Roy Pineci
|
|
Principal Accounting Officer
|
|
|
|
|
|
|
|
/s/ William E. Albrecht
|
|
Chairman of the Board
|
February 27, 2019
|
|
William E. Albrecht
|
|
||
|
|
|
|
|
|
/s/ Justin A. Gannon
|
|
Director
|
February 27, 2019
|
|
Justin A. Gannon
|
|
||
|
|
|
|
|
|
/s/ Harold M. Korell
|
|
Director
|
February 27, 2019
|
|
Harold M. Korell
|
|
||
|
|
|
|
|
|
/s/ Harry T. McMahon
|
|
Director
|
February 27, 2019
|
|
Harry T. McMahon
|
|
||
|
|
|
|
|
|
/s/ Richard W. Moncrief
|
|
Director
|
February 27, 2019
|
|
Richard W. Moncrief
|
|
||
|
|
|
|
|
|
/s/ Avedick B. Poladian
|
|
Director
|
February 27, 2019
|
|
Avedick B. Poladian
|
|
||
|
|
|
|
|
|
/s/ Anita M. Powers
|
|
Director
|
February 27, 2019
|
|
Anita M. Powers
|
|
||
|
|
|
|
|
|
/s/ Laurie A. Siegel
|
|
Director
|
February 27, 2019
|
|
Laurie A. Siegel
|
|
||
|
|
|
|
|
|
/s/ Robert V. Sinnott
|
|
Director
|
February 27, 2019
|
|
Robert V. Sinnott
|
|
21
|
|
List of Subsidiaries of California Resources Corporation.
|
|
|
|
23.1
|
|
Consent of Independent Registered Public Accounting Firm.
|
|
|
|
23.2
|
|
Consent of Independent Petroleum Engineers.
|
|
|
|
31.1
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
31.2
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
32.1
|
|
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
99.1
|
|
Ryder Scott Company Estimated Future Reserves Attributable to Certain Leasehold and Royalty Interests as of December 31, 2018.
|
|
|
|
101.INS
|
|
XBRL Instance Document.
|
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema Document.
|
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
Name
|
|
Jurisdiction of Formation
|
California Heavy Oil, Inc.
|
|
Delaware
|
California Resources Coles Levee, LLC
|
|
Delaware
|
California Resources Coles Levee, L.P.
|
|
Delaware
|
California Resources Development JV, LLC
|
|
Delaware
|
California Resources Elk Hills, LLC
|
|
Delaware
|
California Resources Long Beach, Inc.
|
|
Delaware
|
California Resources Petroleum Corporation
|
|
Delaware
|
California Resources Production Corporation
|
|
Delaware
|
California Resources Real Estate Ventures, LLC
|
|
Delaware
|
California Resources Tidelands, Inc.
|
|
Delaware
|
California Resources Wilmington, LLC
|
|
Delaware
|
CRC Construction Services, LLC
|
|
Delaware
|
CRC Marketing, Inc.
|
|
Delaware
|
CRC Services, LLC
|
|
Delaware
|
Elk Hills Power, LLC
|
|
Delaware
|
Socal Holding, LLC
|
|
Delaware
|
Southern San Joaquin Production, Inc.
|
|
Delaware
|
Thums Long Beach Company
|
|
Delaware
|
Tidelands Oil Production Company
|
|
Texas
|
|
/s/ Ryder Scott Company, L.P.
|
|
RYDER SCOTT COMPANY, L.P.
|
|
TBPE Firm Registration No. F-1580
|
1.
|
I have reviewed this annual report on Form 10-K of California Resources Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
|
|
|
|
/s/ Todd A. Stevens
|
|
|
|
|
Todd A. Stevens
|
|
|
|
|
President and Chief Executive Officer
|
|
|
|
|
(Principal Executive Officer)
|
1.
|
I have reviewed this annual report on Form 10-K of California Resources Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
|
|
|
|
/s/ Marshall D. Smith
|
|
|
|
|
Marshall D. Smith
|
|
|
|
|
Senior Executive Vice President and
|
|
|
|
|
Chief Financial Officer
|
|
|
|
|
(Principal Financial Officer)
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ Todd A. Stevens
|
|
|
||
Name:
|
|
Todd A. Stevens
|
|
|
Title:
|
|
President and Chief Executive Officer
|
|
|
Date:
|
|
February 27, 2019
|
|
|
/s/ Marshall D. Smith
|
|
|
||
Name:
|
|
Marshall D. Smith
|
|
|
Title:
|
|
Senior Executive Vice President and Chief Financial Officer
|
|
|
Date:
|
|
February 27, 2019
|
|
|
|
\s\ Larry P. Connor
|
|
\s\ Eric A. Sepolio
|
|
|
Larry P. Connor, P.E.
|
|
Eric A. Sepolio, P.E.
|
|
|
TBPE License No. 58639
|
|
TBPE License No. 128738
|
|
|
Advising Senior Vice President
|
|
Vice President
|
|
[SEAL]
|
|
|
|
[SEAL]
|
SEC PARAMETERS
|
||||||||
Estimated Net Reserves
|
||||||||
Certain Leasehold and Royalty Interests of
|
||||||||
California Resources Corporation
|
||||||||
As of December 31, 2018
|
||||||||
|
|
|
||||||
|
|
Proved
|
||||||
|
|
Developed
|
|
|
|
Total
|
||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Proved
|
Audited by Ryder Scott
Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate – MMBarrels
|
|
252
|
|
65
|
|
114
|
|
431
|
Plant Products – MMBarrels
|
|
39
|
|
3
|
|
12
|
|
54
|
Gas – Bcf
|
|
374
|
|
40
|
|
148
|
|
562
|
MMBOE
|
|
353
|
|
75
|
|
151
|
|
579
|
|
|
|
|
|
|
|
|
|
Not Audited by Ryder Scott
Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate – MMBarrels
|
|
50
|
|
22
|
|
27
|
|
99
|
Plant Products – MMBarrels
|
|
4
|
|
1
|
|
1
|
|
6
|
Gas – Bcf
|
|
116
|
|
35
|
|
21
|
|
172
|
MMBOE
|
|
73
|
|
29
|
|
31
|
|
133
|
|
|
|
|
|
|
|
|
|
Total Net Reserves
|
|
|
|
|
|
|
|
|
Oil/Condensate – MMBarrels
|
|
302
|
|
87
|
|
141
|
|
530
|
Plant Products – MMBarrels
|
|
43
|
|
4
|
|
13
|
|
60
|
Gas – Bcf
|
|
490
|
|
75
|
|
169
|
|
734
|
MMBOE
|
|
426
|
|
104
|
|
182
|
|
712
|
Geographic Area
|
Product
|
Price
Reference
|
Average
Benchmark
Prices
|
Average Realized
Prices
|
North America
|
|
|
|
|
|
Oil/Condensate
|
Brent Spot
|
$71.75/Bbl
|
$71.03/Bbl
|
United States
|
NGLs
|
Brent Spot
|
$71.75/Bbl
|
$44.42/Bbl
|
|
Gas
|
Henry Hub
|
$3.10/MMBTU
|
$2.98/Mcf
|
Very truly yours,
|
|
|
|
|
|
RYDER SCOTT COMPANY, L.P.
|
|
|
TBPE Firm Registration No. F-1580
|
|
|
|
|
|
\s\ Larry P. Connor, P.E.
|
|
[SEAL]
|
Larry P. Connor, P.E.
|
|
|
TBPE License No. 58639
|
|
|
Advising Senior Vice President
|
|
|
|
|
|
\s\ Eric A. Sepolio
|
|
[SEAL]
|
Eric A. Sepolio, P.E
|
|
|
TBPE License No. 128738
|
|
|
Vice President
|
|
|
(1)
|
completion intervals that are open at the time of the estimate but which have not yet started producing;
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(2)
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wells which were shut-in for market conditions or pipeline connections; or
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(3)
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wells not capable of production for mechanical reasons.
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(i)
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Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
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