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Share Name | Share Symbol | Market | Type |
---|---|---|---|
California Resources Corporation | NYSE:CRC | NYSE | Common Stock |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.18 | 0.35% | 51.68 | 51.87 | 51.12 | 51.64 | 460,180 | 01:00:00 |
þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
¨
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
Delaware
(State or other jurisdiction of
incorporation or organization)
|
|
46-5670947
(I.R.S. Employer
Identification No.)
|
|
|
|
9200 Oakdale Ave.
Los Angeles, California
(Address of principal executive offices)
|
|
91311
(Zip Code)
|
Title of Each Class
|
|
Name of Each Exchange on Which Registered
|
Common Stock
|
|
New York Stock Exchange
|
5% Senior Notes due 2020
|
|
|
5
½
% Senior Notes due 2021
|
|
|
6% Senior Notes due 2024
|
|
|
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
|
Yes
¨
No
þ
|
|
Large Accelerated Filer
|
¨
|
Accelerated Filer
|
þ
|
|
Non-Accelerated Filer
|
¨
|
Smaller Reporting Company
|
¨
|
Name
|
|
Jurisdiction of Formation
|
California Heavy Oil, Inc.
|
|
Delaware
|
California Resources Coles Levee, LLC
|
|
Delaware
|
California Resources Coles Levee, L.P.
|
|
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 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
|
|
Page
|
|
Part I
|
|
|
Items 1
|
BUSINESS
|
|
|
General
|
|
|
Business Operations
|
|
|
Our Business Strategy
|
|
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Key Characteristics of our Operations
|
|
|
Portfolio Management and 2017 Capital Budget
|
|
|
Reserves and Production Information
|
|
|
Marketing Arrangements
|
|
|
Regulation of the Oil and Natural Gas Industry
|
|
|
Employees
|
|
|
Available Information
|
|
Item 1A
|
RISK FACTORS
|
|
Item 1B
|
UNRESOLVED STAFF COMMENTS
|
|
Item 2
|
PROPERTIES
|
|
|
Our Operations
|
|
|
Our Reserves and Production Information
|
|
|
Determination of Identified Drilling Locations
|
|
|
Production, Price and Cost History
|
|
|
Productive Wells
|
|
|
Acreage
|
|
|
Participation in Exploratory and Development Wells Being Drilled
|
|
|
Delivery Commitments
|
|
|
Our Infrastructure
|
|
Item 3
|
LEGAL PROCEEDINGS
|
|
Item 4
|
MINE SAFETY DISCLOSURES
|
|
|
EXECUTIVE OFFICERS
|
|
Part II
|
|
|
Item 5
|
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
|
Item 6
|
SELECTED FINANCIAL DATA
|
|
Item 7
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
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The Separation and Spin-off
|
|
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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
|
|
|
Income Taxes
|
|
|
Operations
|
|
|
Financial and Operating Results
|
|
|
Balance Sheet Analysis
|
|
|
Statement of Operations Analysis
|
|
|
Liquidity and Capital Resources
|
|
|
Cash Flow Analysis
|
|
|
Acquisitions and Divestitures
|
|
|
2016 Capital Program and 2017 Capital Budget
|
|
|
Off-Balance-Sheet Arrangements
|
|
|
Lawsuits, Claims, Contingencies and Commitments
|
|
|
Critical Accounting Policies and Estimates
|
|
|
Significant Accounting and Disclosure Changes
|
|
Item 7A
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
|
FORWARD-LOOKING STATEMENTS
|
|
Item 8
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
Report of Independent Registered Public Accounting Firm on Consolidated and Combined Financial Statements
|
|
|
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
|
|
|
Consolidated Balance Sheets
|
|
|
Consolidated and Combined Statements of Operations
|
|
|
Consolidated and Combined Statements of Comprehensive Income
|
|
|
Consolidated and Combined Statements of Equity
|
|
Consolidated and Combined Statements of Cash Flows
|
|
|
Notes to Consolidated and Combined Financial Statements
|
|
|
Quarterly Financial Data (Unaudited)
|
|
|
Supplemental Oil and Gas Information (Unaudited)
|
|
|
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
|
|
Item 9
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|
|
Item 9A
|
CONTROLS AND PROCEDURES
|
|
Item 9B
|
OTHER INFORMATION
|
|
Part III
|
|
|
Item 10
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
|
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
|
|
Part IV
|
|
|
Item 15
|
EXHIBITS
|
Item 1
|
BUSINESS
|
|
Acreage
|
|
Average Net Acreage Held in Fee (%)
|
|
Producing Wells, gross
|
|
Net Revenue Interest
(%)
|
|
Identified Drilling Locations
(1)
|
|||||||||||
|
Gross
|
|
Net
|
|
|
|
|
Gross
|
|
Net
|
||||||||||
San Joaquin Basin
|
1.8
|
|
|
1.5
|
|
|
64
|
%
|
|
6,246
|
|
|
79
|
%
|
|
23,900
|
|
|
16,650
|
|
Los Angeles Basin
(2)
|
<0.1
|
|
|
<0.1
|
|
|
52
|
%
|
|
1,315
|
|
|
78
|
%
|
|
2,150
|
|
|
2,050
|
|
Ventura Basin
|
0.3
|
|
|
0.3
|
|
|
72
|
%
|
|
567
|
|
|
84
|
%
|
|
2,950
|
|
|
2,750
|
|
Sacramento Basin
|
0.6
|
|
|
0.5
|
|
|
37
|
%
|
|
709
|
|
|
76
|
%
|
|
1,900
|
|
|
1,400
|
|
Total
|
2.8
|
|
|
2.3
|
|
|
58
|
%
|
|
8,837
|
|
|
79
|
%
|
|
30,900
|
|
|
22,850
|
|
(1)
|
Our total identified drilling locations exclude approximately
6,400
gross (
5,300
net) prospective resource drilling locations. Our total identified drilling locations include approximately
2,350
gross (
2,150
net) locations associated with proved undeveloped reserves as of
December 31, 2016
. Our total identified drilling locations also include approximately
2,300
gross (
2,100
net) injection well locations. Please see "Item 2 – Properties – Our Reserves and Production Information" for more information regarding the processes and criteria through which we identified our drilling locations.
|
(2)
|
We currently hold approximately 42,600 gross (34,400 net) acres in the Los Angeles basin. Our Los Angeles basin operations are concentrated with pad drilling.
|
•
|
Focus on high-margin crude oil projects to generate sufficient cash flows to internally fund our growth capital needs.
We expect the percentage of our oil production to continue to increase over time and favorably impact our overall margins as we anticipate directing virtually all of our capital investments towards oil-weighted opportunities to the extent the oil-to-gas price relationship remains favorable and capital is available. Approximately 95% of our identified drilling inventory is associated with oil-rich projects. Currently,
65%
of our production is oil while
72%
of our reserves are oil. Over time, we expect our share of oil production to approach the share of oil reserves.
|
•
|
Maintain an appropriate share of conventional projects in our production mix to manage production declines and lower base maintenance capital requirements.
Our portfolio of assets includes a large number of steamflood and waterflood projects that have much lower decline rates than many unconventional projects. At current price levels, we intend to focus a greater portion of our capital investments on such projects, which we expect will lower our production decline rates. Over time, we expect that this strategy will reduce the capital required to maintain flat crude oil production. We have significant additional lower-risk conventional opportunities with approximately
27,150
gross (
19,450
net) identified drilling locations, 54% of which are associated with Improved Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) projects. The remaining 46% are associated with primary recovery methods, many of which we expect will develop into IOR and EOR projects in the future.
|
•
|
Proactive and collaborative approach to safety, environmental protection, and community relations.
We are committed to managing our assets in a manner that safeguards people and protects the environment, and we seek to proactively engage with regulatory agencies, communities and other stakeholders to pursue mutually beneficial outcomes. As a California company, helping our state meet its water needs is a key strategic focus. Through our investments in water conservation and in recycling of produced water from oil and gas reservoirs, we are a net water supplier to agriculture. In
2016
, our operations supplied more than 3.9 billion gallons of reclaimed water to agricultural water districts, a 49% increase from
2015
. This water supply to agriculture set a company record and again exceeded the volume of fresh water we purchased for our operations statewide. We continue to evaluate measures to further decrease our fresh water use and to expand the beneficial use of our produced water over the coming years.
|
•
|
Continue to pursue joint venture development opportunities.
We continuously evaluate opportunities to accelerate future development through joint ventures. We would pursue these projects to the extent we believe they would increase stockholder value. We are actively discussing both development and exploration project opportunities. In addition to pursuing growth through joint ventures, we expect substantially all our cash flow to be directed to our capital program while considering other deleveraging opportunities as appropriate.
|
•
|
Continue to identify high-growth unconventional drilling opportunities.
Over the longer term and in a higher oil-price environment, we believe we can generate significant production growth from unconventional reservoirs such as tight sandstones and shales. In such an environment, we would expect to generate sufficient cash flow from our conventional projects to fund numerous unconventional opportunities in our portfolio. We hold mineral interests in approximately 1.3 million net acres with unconventional potential and have identified approximately
3,750
gross (
3,400
net) drilling locations on this acreage. A meaningful portion of our production already comes from unconventional assets. While we have not yet developed sufficient information to reliably predict success rates across our entire portfolio, our continued technical reviews of these unconventional projects are allowing us to better understand performance of these reservoirs in addition to improving our overall cycle time from project identification to development. As a result of our increased understanding of these reservoirs, we believe we will be able to direct future available capital more precisely to higher value projects, allowing us to strategically increase our investment levels in unconventional drilling over time.
|
•
|
Apply proven modern technologies to enhance production growth and cost efficiency.
Over the last several decades, the oil and gas industry has focused significantly less effort on utilizing modern development and exploration processes and technologies in California relative to other prolific U.S. basins. We believe this is largely due to other oil companies’ limited capital investments in California, concentration on shallow zone thermal projects, or investments in other assets within their global portfolios. As an independent company focused on California, we intend to use proven modern technologies in drilling and completing wells, as well as production methods, which we expect will substantially increase both our production and cost efficiency over time. We have developed an extensive 3D seismic library covering almost 4,800 square miles in all four of our basins, representing over 90% of the 3D seismic data available for California, and have tested and successfully implemented various exploration, drilling, completion, IOR and EOR technologies in the state.
|
•
|
Continued focus on our successful exploration program.
As prices improve and sufficient additional capital becomes available, we intend to significantly increase our investment in exploration, focusing on both unconventional and conventional opportunities, primarily in areas that we believe can be quickly developed, such as those adjacent to our existing properties. In addition, we plan to explore and test new unconventional resource areas, which, if successful, could result in significant longer-term production growth. In addition, we are also actively pursuing joint venture partnership opportunities, which may give us the opportunity to implement some of our exploration projects even in the current environment.
|
•
|
Operational control of our diverse asset base provides flexibility over various commodity price ranges and preserves future value and growth potential in a higher price environment.
Our near 100% operational control of
135
fields in California provides us flexibility to adapt our investments to various market environments through our ability to select drilling locations, the timing of our development and the drilling and completion techniques we use. Our large and diverse mineral acreage position, of which approximately 60% is held in fee, 15% is held by production and 25% are term leases, allows us to choose among multiple recovery mechanisms, including primary conventional, steamflood, waterflood and unconventional, and to develop various products, including oil, natural gas and natural gas liquids (NGLs). A majority of our interests are in producing properties located in reservoirs characterized by what we believe have long-lived production profiles with repeatable development opportunities. Approximately 95% of our identified drilling inventory is associated with oil-rich projects, primarily located in the San Joaquin, Los Angeles and Ventura basins, and the remaining inventory is associated with natural gas properties in the Sacramento, San Joaquin and Ventura basins. The variety of recovery mechanisms and product types available to us, together with our operating control, allows us to allocate capital in a manner designed to optimize cash flow over a wide range of commodity prices. The low base decline of our conventional assets allows us to limit production declines with minimal investment. We believe our low base decline positions us well to achieve oil production growth in the current price environment while living within our means.
|
•
|
Relatively favorable margins driven by California's deficit energy market.
We currently sell all of our crude oil into the California refining markets, which we believe have offered favorable pricing for comparable grades relative to other U.S. regions. California is heavily reliant on imported sources of energy, with approximately 65% of oil and 90% of natural gas consumed in recent years imported from outside the state. A vast majority of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based prices. We believe that the limited crude transportation infrastructure from other parts of the country to California will continue contributing to higher realizations than most other United States oil markets for comparable grades. In addition, we own fee mineral interests on approximately 60% of our net acreage position. The returns on fee mineral acreage are enhanced because we do not pay royalties and other lease payments. To further improve our margins, we are opportunistically pursuing newly opened export markets for our crude oil production.
|
•
|
Largest acreage position in a world-class oil and natural gas province.
We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately
2.3 million
net acres. California is one of the most prolific oil and natural gas producing regions in the world and is the third largest oil producing state in the nation. It has four of the 12 largest fields in the lower 48 states based on proved reserves as of 2013, and our portfolio includes interests in each of these four fields. California is also the nation’s largest state economy, and the world's sixth largest, with significant energy demands that exceed local supply. Our large acreage position with a diverse development portfolio enables us to pursue the appropriate production strategy for the relevant commodity price environment without the need to acquire new acreage. For example, in a high natural gas price environment we can rapidly increase our investments in the Sacramento basin to generate significant production growth. Our large acreage position also allows us to quickly deploy the knowledge we gain in our existing operations, together with our seismic data, in other areas within our portfolio.
|
•
|
Opportunity rich drilling and workover portfolio.
Our drilling inventory at December 31, 2016 consisted of approximately
30,900
gross identified well locations, including approximately
27,150
gross (
19,450
net) conventional drilling locations and approximately
3,750
gross (
3,400
net) unconventional drilling locations. Our drilling inventory count increased by about 30% from the prior year as a result of our technical teams' continued efforts. We also have approximately 1,000 workover projects that can deliver high returns. At about $55 Brent, we estimate that we have been able to increase investment opportunities that meet our 1.3 VCI hurdle sufficiently to double the drilling and workover capital we could deploy. In the process, our inventory of lower-risk conventional development opportunities with attractive returns has increased, even more than our unconventional opportunities. In a more favorable, sustained price environment, we believe we can also achieve further long-term production growth through the development of unconventional reservoirs. In addition, our rich conventional and unconventional portfolio can provide attractive joint venture partnership opportunities.
|
•
|
Proven operational management and technical teams with extensive experience operating in California.
The members of our operational management and technical teams have an average of over 25 years’ experience in the oil and natural gas industry, with an average of over 15 years focused on our California oil and gas operations through multiple pricing cycles. Our operational management team and technical staff have a proven track record of applying modern technologies and operating methods to develop our assets and improve their operating efficiencies. For example, our teams have successfully reduced field operating costs on a per unit basis by approximately 22% since the Spin-off.
|
|
Proved Reserves as of December 31, 2016
|
|
Average Net Daily Production for the Year Ended December 31, 2016
|
|
|
||||||||||||||||||||
|
Oil (MMBbl)
|
|
NGLs (MMBbl)
|
|
Natural Gas (Bcf)
|
|
Total (MMBoe)
|
|
Oil (%)
|
|
Proved Developed (%)
|
|
(MBoe/d)
|
|
Oil (%)
|
|
R/P Ratio (Years)
(1)
|
||||||||
San Joaquin Basin
|
287
|
|
|
53
|
|
|
536
|
|
|
429
|
|
|
67
|
%
|
|
67
|
%
|
|
97
|
|
|
59
|
%
|
|
12.1
|
Los Angeles Basin
|
98
|
|
|
—
|
|
|
7
|
|
|
99
|
|
|
99
|
%
|
|
84
|
%
|
|
30
|
|
|
97
|
%
|
|
9.0
|
Ventura Basin
|
24
|
|
|
2
|
|
|
15
|
|
|
29
|
|
|
83
|
%
|
|
86
|
%
|
|
7
|
|
|
71
|
%
|
|
11.3
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
68
|
|
|
11
|
|
|
—
|
|
|
100
|
%
|
|
6
|
|
|
—
|
%
|
|
5.0
|
Total operations
|
409
|
|
|
55
|
|
|
626
|
|
|
568
|
|
|
72
|
%
|
|
71
|
%
|
|
140
|
|
|
65
|
%
|
|
11.1
|
(1)
|
Calculated as total proved reserves as of
December 31, 2016
divided by annualized Average Net Daily Production for the year ended
December 31, 2016
.
|
|
Q1 2017
|
|
Q2 2017
|
|
Q3 2017
|
|
Q4 2017
|
|
Q1 2018
|
|
Q2-Q4 2018
|
||||||||||||
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Calls:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
12,100
|
|
|
5,000
|
|
|
10,000
|
|
|
15,000
|
|
|
15,600
|
|
|
15,000
|
|
||||||
Weighted-average price per barrel
|
$
|
56.37
|
|
|
$
|
55.05
|
|
|
$
|
56.15
|
|
|
$
|
56.12
|
|
|
$
|
58.77
|
|
|
$
|
58.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Puts:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
22,100
|
|
|
20,000
|
|
|
17,000
|
|
|
10,000
|
|
|
—
|
|
|
—
|
|
||||||
Weighted-average price per barrel
|
$
|
49.10
|
|
|
$
|
50.25
|
|
|
$
|
50.88
|
|
|
$
|
48.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
20,000
|
|
|
20,000
|
|
|
20,000
|
|
|
20,000
|
|
|
—
|
|
|
—
|
|
||||||
Weighted-average price per barrel
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
—
|
|
|
$
|
—
|
|
•
|
oil and natural gas production including well spacing or density on private and state lands;
|
•
|
methods of constructing, drilling, completing, stimulating, operating, maintaining and abandoning wells;
|
•
|
design, construction, operation, maintenance and decommissioning of facilities, such as natural gas processing plants, power plants, compressors and liquid and natural gas pipelines or gathering lines;
|
•
|
improved or enhanced recovery techniques such as fluid injection for pressure management, waterflooding or steamflooding;
|
•
|
sourcing and disposal of water used in the drilling, completion, stimulation, maintenance and enhanced recovery processes;
|
•
|
imposition of taxes and fees with respect to our properties and operations;
|
•
|
the conservation of oil and natural gas, including provisions for the unitization or pooling of oil and natural gas properties;
|
•
|
posting of bonds or other financial assurance to drill, operate and abandon or decommission wells and facilities; and
|
•
|
occupational health, safety and environmental matters and the transportation, marketing and sale of our products as described below.
|
•
|
establish air, soil and water quality standards for a given region, such as the San Joaquin Valley, and attainment plans to meet those regional standards, which may include significant restrictions on development, economic activity and transportation in such region;
|
•
|
require various permits and approvals before drilling, workover, production, underground fluid injection or waste disposal commences, or before facilities are constructed or put into operation;
|
•
|
require the installation of sophisticated safety and pollution control equipment, such as leak detection, monitoring and shutdown systems, to prevent or reduce releases or discharges of regulated materials to air, land, surface water or ground water;
|
•
|
restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require conservation and reclamation measures, and impose energy efficiency or renewable energy standards;
|
•
|
restrict the types, quantities and concentrations of regulated materials, including oil, natural gas, produced water or wastes, that can be released or discharged into the environment, or any other uses of those materials resulting from drilling, production, processing, power generation or transportation activities;
|
•
|
limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater recharge, endangered species habitat and other protected areas, and require the dedication of surface acreage for habitat conservation;
|
•
|
establish standards for the closure, abandonment, cleanup or restoration of former operations, such as plugging and abandonment of wells and decommissioning of facilities;
|
•
|
impose substantial liabilities for unauthorized releases or discharges of regulated materials into the environment with respect to our current or former properties and operations and other locations where such materials generated by us or our predecessors were released or discharged;
|
•
|
require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state and private lands or leases;
|
•
|
impose taxes or fees with respect to the foregoing matters;
|
•
|
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 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 total GHG emissions, and this cap declines annually to reach 1990 levels by 2020, the year that the cap-and-trade program currently expires;
|
•
|
require allowances or qualifying offsets for GHGs emitted from California operations and for the volume of propane and liquid transportation fuels sold for use in California, for which allowances we incurred costs of approximately $33 million in 2016;
|
•
|
require refiners to reduce the carbon content of transportation fuels they market in California by 10% by 2020;
|
•
|
impose a more stringent state goal of reducing GHG emissions to 40% below 1990 levels by 2030 by reducing industrial source emissions, even if the cap-and-trade program is not extended;
|
•
|
impose state goals to derive 50% of California’s electricity from renewable sources and to double the energy efficiency of buildings in the state by 2030; and
|
•
|
impose state goals of reducing emissions of methane and fluorocarbon gases by 40% and black carbon by 50% below 2013 levels by 2030.
|
•
|
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.
|
•
|
Forms 10-K, 10-Q, 8-K and amendments to these forms as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC);
|
•
|
Other SEC filings including Forms 3, 4 and 5; and
|
•
|
Corporate governance information, including our corporate governance guidelines, board-committee charters and code of business conduct (see Part III, Item 10, of this report for further information).
|
ITEM 1A
|
RISK FACTORS
|
•
|
reduced cash flow and decreased funds available for capital investments, interest payments and operational expenses;
|
•
|
reduced proved oil and gas reserves over time and related cash flows;
|
•
|
impairments of our oil and gas properties such as we experienced in 2014 and 2015;
|
•
|
reduced borrowing base capacity under our first-out revolving credit facility as proved oil and gas reserves values fall;
|
•
|
the potential for a reduction of our liquidity, mandatory loan repayments and default and foreclosure by our banks and bondholders against our secured assets;
|
•
|
inability to attract counterparties to our transactions, including hedging transactions; and
|
•
|
inability to access funds through the capital markets and the price we could obtain for, or our ability to conduct, asset sales or other monetization transactions.
|
•
|
jeopardizing our ability to execute our business plans;
|
•
|
increasing our vulnerability to adverse changes in our business and in economic and industry conditions generally, and putting us at a disadvantage against competitors that have lower fixed obligations and more cash flow to devote to their businesses;
|
•
|
limiting our ability to obtain additional financing for working capital, capital investments and general corporate and other purposes or increasing the cost of that capital; and
|
•
|
limiting our flexibility to operate our business, compete for capital, react to competitive pressures, address adverse regulatory changes and engage in certain transactions that might otherwise be beneficial to us.
|
•
|
incurrence of additional indebtedness;
|
•
|
investments;
|
•
|
amounts and types of joint ventures;
|
•
|
restricted payments;
|
•
|
creation of liens on our assets;
|
•
|
sales of assets that constitute collateral;
|
•
|
application of the full proceeds of asset sales other than to pay down debt;
|
•
|
mergers or acquisitions; and
|
•
|
release of 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 asset retirement costs.
|
•
|
a change in price basis differentials;
|
•
|
the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; and
|
•
|
an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions.
|
ITEM 1B
|
UNRESOLVED STAFF COMMENTS
|
ITEM 2
|
PROPERTIES
|
|
As of December 31, 2016
|
|||||||||||||
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
177
|
|
|
82
|
|
|
20
|
|
|
—
|
|
|
279
|
|
NGLs (MMBbl)
|
42
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
44
|
|
Natural Gas (Bcf)
|
410
|
|
|
7
|
|
|
15
|
|
|
68
|
|
|
500
|
|
Total (MMBoe)
(a)(b)
|
287
|
|
|
83
|
|
|
25
|
|
|
11
|
|
|
406
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
110
|
|
|
16
|
|
|
4
|
|
|
—
|
|
|
130
|
|
NGLs (MMBbl)
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
Natural Gas (Bcf)
|
126
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
126
|
|
Total (MMBoe)
(b)
|
142
|
|
|
16
|
|
|
4
|
|
|
—
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
287
|
|
|
98
|
|
|
24
|
|
|
—
|
|
|
409
|
|
NGLs (MMBbl)
|
53
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
55
|
|
Natural Gas (Bcf)
|
536
|
|
|
7
|
|
|
15
|
|
|
68
|
|
|
626
|
|
Total (MMBoe)
(b)
|
429
|
|
|
99
|
|
|
29
|
|
|
11
|
|
|
568
|
|
(a)
|
As of December 31, 2016, approximately
20%
of proved developed oil reserves,
11%
of proved developed NGLs reserves,
14%
of proved developed natural gas reserves and, overall,
17%
of total proved developed reserves are non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full peak production response has not yet occurred due to the nature of such projects.
|
(b)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of gas and one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in
2016
, the average prices of Brent oil and NYMEX natural gas were
$45.04
per Bbl and
$2.42
per MMBtu, respectively, resulting in an oil-to-gas price ratio of approximately
19
to 1.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
Improved recovery:
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MMBbl)
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total (MMBoe)
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Extensions and discoveries:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
11
|
|
|
1
|
|
|
2
|
|
|
—
|
|
|
14
|
|
NGLs (MMBbl)
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Natural Gas (Bcf)
|
20
|
|
|
—
|
|
|
3
|
|
|
2
|
|
|
25
|
|
Total (MMBoe)
|
16
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total reserves additions from capital program
|
19
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions related to performance (MMBoe):
|
12
|
|
|
—
|
|
|
2
|
|
|
(1
|
)
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions related to price changes (MMBoe):
|
(17
|
)
|
|
(23
|
)
|
|
(20
|
)
|
|
—
|
|
|
(60
|
)
|
|
|
|
|
|
|
|
|
|
|
|||||
Divestitures (MMBoe):
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
|
|
|
|
|
|
|
|
|
|
|||||
Improved recovery (MMBoe):
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Extensions and discoveries:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
8
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
9
|
|
NGLs (MMBbl)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Natural Gas (Bcf)
|
12
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
14
|
|
Total (MMBoe)
|
11
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions related to performance (MMBoe):
|
17
|
|
|
2
|
|
|
1
|
|
|
—
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions related to price changes
(MMBoe):
|
(8
|
)
|
|
(13
|
)
|
|
(8
|
)
|
|
—
|
|
|
(29
|
)
|
|
|
|
|
|
|
|
|
|
|
|||||
Transfers to proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
(3
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
Total (MMBoe)
|
(3
|
)
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
As of December 31, 2016
|
||
|
($ in millions)
|
||
PV-10 of proved reserves
|
$
|
2,848
|
|
Present value of future income taxes discounted at 10%
|
(181
|
)
|
|
Standardized measure of discounted future net cash flows
|
$
|
2,667
|
|
|
|
||
Organic reserves replacement ratio
(1)
|
71
|
%
|
(1)
|
The organic reserves replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries, improved recovery and performance-related revisions, divided by oil-equivalent production. There is no guarantee that historical sources of reserves additions will continue as many factors fully or partially outside management's control, including commodity prices, availability of capital and the underlying geology affect reserves additions. Management uses this measure to gauge the results of its capital allocation. Other oil and gas producers may use different methods to calculate replacement ratios, which may affect comparability.
|
|
Proven Drilling Locations
|
|
Total Identified Drilling Locations
|
||||||||
|
Oil and
Natural Gas Wells
|
|
Injection Wells
|
|
Oil and
Natural Gas Wells
|
|
Injection Wells
|
||||
San Joaquin Basin
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
200
|
|
|
—
|
|
|
9,000
|
|
|
—
|
|
Steamflood
|
1,050
|
|
|
250
|
|
|
7,550
|
|
|
450
|
|
Waterflood
|
100
|
|
|
50
|
|
|
2,100
|
|
|
1,050
|
|
Unconventional
|
250
|
|
|
—
|
|
|
3,750
|
|
|
—
|
|
San Joaquin Basin subtotal
|
1,600
|
|
|
300
|
|
|
22,400
|
|
|
1,500
|
|
|
|
|
|
|
|
|
|
||||
Los Angeles Basin
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Steamflood
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Waterflood
|
250
|
|
|
100
|
|
|
1,600
|
|
|
550
|
|
Unconventional
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Los Angeles Basin subtotal
|
250
|
|
|
100
|
|
|
1,600
|
|
|
550
|
|
|
|
|
|
|
|
|
|
||||
Ventura Basin
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
—
|
|
|
—
|
|
|
1,600
|
|
|
—
|
|
Steamflood
|
—
|
|
|
—
|
|
|
350
|
|
|
—
|
|
Waterflood
|
50
|
|
|
50
|
|
|
750
|
|
|
250
|
|
Unconventional
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin subtotal
|
50
|
|
|
50
|
|
|
2,700
|
|
|
250
|
|
|
|
|
|
|
|
|
|
||||
Sacramento Basin
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
—
|
|
|
—
|
|
|
1,900
|
|
|
—
|
|
Sacramento Basin subtotal
|
—
|
|
|
—
|
|
|
1,900
|
|
|
—
|
|
|
|
|
|
|
|
|
|
||||
Total Identified Drilling Locations
|
1,900
|
|
|
450
|
|
|
28,600
|
|
|
2,300
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Production Data:
|
|
|
|
|
|
|
|
|
|||
Oil (MBbl/d)
|
91
|
|
|
104
|
|
|
99
|
|
|||
NGLs (MBbl/d)
|
16
|
|
|
18
|
|
|
19
|
|
|||
Natural gas (MMcf/d)
|
197
|
|
|
229
|
|
|
246
|
|
|||
Average daily combined production (MBoe/d)
(a)
|
140
|
|
|
160
|
|
|
159
|
|
|||
Total combined production (MMBoe)
|
51
|
|
|
58
|
|
|
58
|
|
|||
Average realized prices:
|
|
|
|
|
|
|
|
|
|||
Oil prices with hedge ($/Bbl)
|
$
|
42.01
|
|
|
$
|
49.19
|
|
|
$
|
92.30
|
|
Oil prices without hedge ($/Bbl)
|
$
|
39.72
|
|
|
$
|
47.15
|
|
|
$
|
92.30
|
|
NGLs prices ($/Bbl)
|
$
|
22.39
|
|
|
$
|
19.62
|
|
|
$
|
47.84
|
|
Natural gas prices ($/Mcf)
|
$
|
2.28
|
|
|
$
|
2.66
|
|
|
$
|
4.39
|
|
Average Benchmark prices:
|
|
|
|
|
|
|
|
|
|||
Brent oil ($/Bbl)
|
$
|
45.04
|
|
|
$
|
53.64
|
|
|
$
|
99.51
|
|
WTI oil ($/Bbl)
|
$
|
43.32
|
|
|
$
|
48.80
|
|
|
$
|
93.00
|
|
NYMEX gas ($/MMBtu)
|
$
|
2.42
|
|
|
$
|
2.75
|
|
|
$
|
4.34
|
|
Average costs per Boe:
(b)
|
|
|
|
|
|
|
|
|
|||
Production costs
|
$
|
15.61
|
|
|
$
|
16.30
|
|
|
$
|
18.23
|
|
General and administrative expense, as adjusted
(c)
|
$
|
0.72
|
|
|
$
|
1.00
|
|
|
$
|
1.47
|
|
Other operating expenses, as adjusted
(d)
|
$
|
0.67
|
|
|
$
|
0.36
|
|
|
$
|
0.55
|
|
Depreciation, depletion and amortization
|
$
|
10.28
|
|
|
$
|
16.72
|
|
|
$
|
20.40
|
|
Taxes other than on income
|
$
|
2.36
|
|
|
$
|
2.67
|
|
|
$
|
3.50
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas to one Bbl of oil.
|
(b)
|
For 2015 and 2014, the amount excludes asset impairment charges of $4.9 billion and $3.4 billion, respectively.
|
(c)
|
For 2016, the amount excludes unusual and infrequent charges related to severance and early retirement costs associated with field personnel totaling $0.12 per Boe. For 2015, the amount excludes charges of $0.31 per Boe related to early retirement and severance costs. For 2014, the amount excludes charges of $0.10 per Boe related to Spin-off and transition-related costs.
|
(d)
|
For 2016, the amount excludes net unusual and infrequent gains of $0.35 per Boe that include refunds partially offset by plant turnaround charges and other items. For 2015, the amount excludes charges related to the write-down of certain assets and rig termination charges of $1.42 per Boe. For 2014, the amount excludes charges related to rig termination charges and Spin-off and transition-related charges of $0.97 per Boe.
|
|
Elk Hills
|
|
Wilmington
|
||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbl/d)
|
21
|
|
|
24
|
|
|
25
|
|
|
25
|
|
|
28
|
|
|
25
|
|
||||||
NGLs (MBbl/d)
|
13
|
|
|
15
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Natural gas (MMcf/d)
(a)
|
106
|
|
|
123
|
|
|
136
|
|
|
—
|
|
|
1
|
|
|
—
|
|
||||||
Average realized prices:
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbl/d)
|
$
|
44.50
|
|
|
$
|
52.78
|
|
|
$
|
97.27
|
|
|
$
|
37.98
|
|
|
$
|
45.50
|
|
|
$
|
90.37
|
|
NGLs (MBbl/d)
|
$
|
23.03
|
|
|
$
|
20.12
|
|
|
$
|
48.68
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Natural gas (MMcf/d)
(a)
|
$
|
2.27
|
|
|
$
|
2.67
|
|
|
$
|
4.47
|
|
|
$
|
1.83
|
|
|
$
|
2.05
|
|
|
$
|
—
|
|
Production costs per Boe
(c)
|
$
|
10.48
|
|
|
$
|
11.11
|
|
|
$
|
14.31
|
|
|
$
|
22.27
|
|
|
$
|
21.87
|
|
|
$
|
28.98
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas to one Bbl of oil.
|
(b)
|
Excludes the effect of hedges.
|
(c)
|
Production costs per Boe for Wilmington are higher than the actual cost to run the field due to the effect of PSCs. The reported production cost per Boe is calculated as total production cost for the entire field over our share of production. Using the total field production, the production costs per Boe would be $17.21, $17.74 and $19.94 for 2016, 2015 and 2014 respectively, which more accurately represent the actual cost of operating this field.
|
|
Total Proved Reserves
|
|
Average Net Daily
Production(MBoe/d)
|
|||||
|
% of Total Basin
|
|
Oil (%)
|
|
Year ended
December 31, 2016
|
|||
San Joaquin Basin
|
|
|
|
|
|
|
|
|
Primary Conventional
|
14
|
%
|
|
68
|
%
|
|
15
|
|
Waterfloods
|
12
|
%
|
|
79
|
%
|
|
8
|
|
Steamfloods
(a)
|
34
|
%
|
|
100
|
%
|
|
29
|
|
Unconventional
|
40
|
%
|
|
34
|
%
|
|
45
|
|
San Joaquin Basin subtotal
(b)
|
429
|
|
|
67
|
%
|
|
97
|
|
|
|
|
|
|
|
|||
Los Angeles Basin
|
|
|
|
|
|
|
|
|
Primary Conventional
|
—
|
|
|
100
|
%
|
|
—
|
|
Waterfloods
|
100
|
%
|
|
99
|
%
|
|
30
|
|
Steamfloods
|
—
|
|
|
—
|
|
|
—
|
|
Unconventional
|
—
|
|
|
—
|
|
|
—
|
|
Los Angeles Basin subtotal
(b)
|
99
|
|
|
99
|
%
|
|
30
|
|
|
|
|
|
|
|
|||
Ventura Basin
|
|
|
|
|
|
|
|
|
Primary Conventional
|
28
|
%
|
|
76
|
%
|
|
3
|
|
Waterfloods
|
72
|
%
|
|
86
|
%
|
|
4
|
|
Steamfloods
|
—
|
|
|
—
|
|
|
—
|
|
Unconventional
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin subtotal
(b)
|
29
|
|
|
83
|
%
|
|
7
|
|
|
|
|
|
|
|
|||
Sacramento Basin
|
|
|
|
|
|
|
|
|
Primary Conventional
|
100
|
%
|
|
—
|
|
|
6
|
|
Sacramento Basin subtotal
(b)
|
11
|
|
|
—
|
|
|
6
|
|
|
|
|
|
|
|
|||
Total
|
568
|
|
|
72
|
%
|
|
140
|
|
(a)
|
Includes reserves and production from gas injection of 14% and 8%, respectively.
|
(b)
|
Subtotal basin reserves in MMBoe.
|
|
As of December 31, 2016
|
||||||||||
|
Productive Oil Wells
|
|
Productive Gas Wells
|
||||||||
|
Gross
(a)
|
|
Net
(b)
|
|
Gross
(a)
|
|
Net
(b)
|
||||
San Joaquin Basin
|
8,035
|
|
|
6,848
|
|
|
184
|
|
|
153
|
|
Los Angeles Basin
|
1,699
|
|
|
1,641
|
|
|
—
|
|
|
—
|
|
Ventura Basin
|
1,204
|
|
|
1,197
|
|
|
—
|
|
|
—
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
909
|
|
|
832
|
|
Total
(c)
|
10,938
|
|
|
9,686
|
|
|
1,093
|
|
|
985
|
|
|
|
|
|
|
|
|
|
||||
Multiple completion wells included above
|
82
|
|
|
71
|
|
|
66
|
|
|
63
|
|
(a)
|
The total number of wells in which interests are owned.
|
(b)
|
Sum of fractional interests.
|
(c)
|
This total represents both producing and capable of producing wells. As of December 31, 2016, we had
2,957
gross (
2,726
net) oil wells and
237
gross (
208
net) gas wells that are capable of production but currently not producing.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
|
(in thousands)
|
|||||||||||||
Developed
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(b)
|
418
|
|
|
25
|
|
|
71
|
|
|
268
|
|
|
782
|
|
Net
(c)
|
380
|
|
|
20
|
|
|
69
|
|
|
248
|
|
|
717
|
|
Undeveloped
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(b)
|
1,382
|
|
|
17
|
|
|
229
|
|
|
357
|
|
|
1,985
|
|
Net
(c)
|
1,133
|
|
|
14
|
|
|
192
|
|
|
275
|
|
|
1,614
|
|
(a)
|
Acres spaced or assigned to productive wells.
|
(b)
|
Total acres in which we hold an interest.
|
(c)
|
Sum of fractional interests owned based on working interests or interests under arrangements similar to production-sharing contracts.
|
(d)
|
Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the acreage contains proved reserves.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
Exploratory and development wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
4
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
5
|
|
Net
|
4
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
37.0
|
|
|
5.4
|
|
|
—
|
|
|
—
|
|
|
42.4
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|||||
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
3.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.0
|
|
Development
|
254.0
|
|
|
29.1
|
|
|
—
|
|
|
—
|
|
|
283.1
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|||||
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
2.0
|
|
|
—
|
|
|
1.7
|
|
|
—
|
|
|
3.7
|
|
Development
|
775.2
|
|
|
170.2
|
|
|
20.3
|
|
|
—
|
|
|
965.7
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
3.0
|
|
|
3.0
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
8.0
|
|
|
—
|
|
|
2.0
|
|
|
1.0
|
|
|
11.0
|
|
Development
|
2.3
|
|
|
0.9
|
|
|
—
|
|
|
—
|
|
|
3.2
|
|
Description
|
|
Quantity
|
|
Unit
|
|
Capacity
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
San Joaquin Basin
|
|
Other Basins
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Gas Plants
|
|
9
|
|
MMcf/d
|
|
590
|
|
50
|
|
640
|
Power Plants/Co-generation
|
|
3
|
|
MW
|
|
600
|
|
50
|
|
650
|
Steam Generators/Plants
|
|
>50
|
|
Mb/d
|
|
220
|
|
—
|
|
220
|
Compressors
|
|
400
|
|
MHP
|
|
300
|
|
20
|
|
320
|
Water Disposal Systems
|
|
|
|
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
|
ITEM 3
|
LEGAL PROCEEDINGS
|
ITEM 4
|
MINE SAFETY DISCLOSURES
|
Name
|
|
Positions Held with CRC and Predecessor and Employment History
|
|
Age at February 24, 2017
|
Todd A. Stevens
|
|
President, Chief Executive Officer and Director since 2014; Occidental Vice President - Corporate Development 2012 to 2014; Oxy Oil & Gas Vice President - California Operations 2008 to 2012; Occidental Vice President - Acquisitions and Corporate Finance 2004 to 2012.
|
|
50
|
Marshall D. Smith
|
|
Senior Executive Vice President and Chief Financial Officer since 2014; Ultra Petroleum Corp. Chief Financial Officer 2005 to 2014; Ultra Petroleum Corp. Senior Vice President 2011 to 2014.
|
|
57
|
Robert A. Barnes
|
|
Executive Vice President - Operations since 2016; Executive Vice President - Northern Operations 2014 to 2016; Occidental of Elk Hills President and General Manager 2012 to 2014; Oxy Permian CO
2
Operations Manager 2011 to 2012, Occidental Argentina Deputy General Manager and Senior Vice President, Operations 2010 to 2011; Occidental Argentina Vice President, Operations 2007 to 2010.
|
|
60
|
Shawn M. Kerns
|
|
Executive Vice President - Corporate Development since 2014; Vintage Production California President and General Manager 2012 to 2014; Occidental of Elk Hills General Manager 2010 to 2012; Occidental of Elk Hills Asset Development Manager 2008 to 2010.
|
|
46
|
Roy 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.
|
|
54
|
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.
|
|
52
|
Charles F. Weiss
|
|
Executive Vice President - Public Affairs since 2014; Occidental Vice President, Health, Environment and Safety 2007 to 2014.
|
|
53
|
Darren Williams
|
|
Executive Vice President - Exploration since 2014; Marathon Upstream Gabon Limited President and Africa Exploration Manager 2013 to 2014; Marathon Oil Oklahoma Subsurface Manager 2010 to 2013; Marathon Oil Gulf of Mexico Exploration and Appraisal Manager 2008 to 2010.
|
|
45
|
ITEM 5
|
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
|
Stock Price
|
||||||||||||||
|
2016
|
|
2015
|
||||||||||||
|
High
|
|
Low
|
|
High
|
|
Low
|
||||||||
First Quarter
|
$
|
23.30
|
|
|
$
|
2.81
|
|
|
$
|
78.68
|
|
|
$
|
37.50
|
|
Second Quarter
|
$
|
25.50
|
|
|
$
|
9.20
|
|
|
$
|
98.65
|
|
|
$
|
55.90
|
|
Third Quarter
|
$
|
15.18
|
|
|
$
|
8.79
|
|
|
$
|
60.50
|
|
|
$
|
22.60
|
|
Fourth Quarter
|
$
|
21.97
|
|
|
$
|
9.84
|
|
|
$
|
51.50
|
|
|
$
|
17.60
|
|
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))
|
2,240,479
|
|
$69.89
|
|
2,288,027
(2)
|
(1)
|
Exercise price applies only to approximately 1.1 million options included in column (a) and not to any other awards.
|
(2)
|
Includes 503,348 shares available under our 2014 Employee Stock Purchase Plan (ESPP) at 85% of the lower of the market price at (i) the beginning of a quarter and (ii) the end of a quarter.
|
|
|
12/1/14
|
|
12/31/14
|
|
3/31/15
|
|
6/30/15
|
|
9/30/15
|
|
12/31/15
|
|
3/31/16
|
|
6/30/16
|
|
9/30/16
|
|
12/31/16
|
||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
California Resources Corp
|
|
$
|
100
|
|
|
$
|
75
|
|
|
$
|
103
|
|
|
$
|
82
|
|
|
$
|
35
|
|
|
$
|
32
|
|
|
$
|
14
|
|
|
$
|
17
|
|
|
$
|
17
|
|
|
$
|
29
|
|
S&P 500
|
|
100
|
|
|
100
|
|
|
101
|
|
|
101
|
|
|
94
|
|
|
101
|
|
|
102
|
|
|
105
|
|
|
109
|
|
|
113
|
|
||||||||||
Dow Jones US Exploration & Production
|
|
100
|
|
|
99
|
|
|
102
|
|
|
99
|
|
|
79
|
|
|
76
|
|
|
74
|
|
|
81
|
|
|
88
|
|
|
94
|
|
||||||||||
Peer Group
|
|
100
|
|
|
98
|
|
|
102
|
|
|
97
|
|
|
72
|
|
|
67
|
|
|
73
|
|
|
87
|
|
|
96
|
|
|
96
|
|
ITEM 6
|
SELECTED FINANCIAL DATA
|
•
|
The selected statement of operations and cash flows data for the years ended December 31,
2016
and
2015
consist of our stand-alone consolidated results post Spin-off. For the year ended December 31, 2014 the statement of operations and cash flows data includes the consolidated results for the month ended December 31, 2014 and the combined results of the California business prior to the Spin-off. The selected statement of operations data for the years ended December 31, 2013 and 2012 consists entirely of the combined results of the California business.
|
•
|
The selected balance sheet data at
December 31, 2016
,
2015
and 2014 consists of our stand-alone consolidated balances, while the selected balance sheet data at December 31, 2013 and 2012 consists of the combined balances of the California business.
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in millions, except for per share data)
|
||||||||||||||||||
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues
|
$
|
1,547
|
|
|
$
|
2,403
|
|
|
$
|
4,173
|
|
|
$
|
4,284
|
|
|
$
|
4,073
|
|
Income (loss) before income taxes
|
$
|
201
|
|
|
$
|
(5,476
|
)
|
|
$
|
(2,421
|
)
|
|
$
|
1,447
|
|
|
$
|
1,181
|
|
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
Per common share
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
|
$
|
22.38
|
|
|
$
|
18.01
|
|
Diluted
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
|
$
|
22.38
|
|
|
$
|
18.01
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of Cash Flows Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
$
|
130
|
|
|
$
|
403
|
|
|
$
|
2,371
|
|
|
$
|
2,476
|
|
|
$
|
2,223
|
|
Capital investments
|
$
|
(75
|
)
|
|
$
|
(401
|
)
|
|
$
|
(2,089
|
)
|
|
$
|
(1,669
|
)
|
|
$
|
(2,331
|
)
|
Acquisitions
|
$
|
—
|
|
|
$
|
(141
|
)
|
|
$
|
(288
|
)
|
|
$
|
(48
|
)
|
|
$
|
(427
|
)
|
Net (repayments) borrowings and related costs
|
$
|
(73
|
)
|
|
$
|
356
|
|
|
$
|
6,290
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Spin-off related dividends to Occidental
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(6,000
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
(Distributions to) contributions from Occidental, net
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(335
|
)
|
|
$
|
(763
|
)
|
|
$
|
532
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Dividends per Common Share
|
$
|
—
|
|
|
$
|
0.30
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
As of December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total current assets
|
$
|
425
|
|
|
$
|
438
|
|
|
$
|
701
|
|
|
$
|
254
|
|
|
$
|
245
|
|
Property, plant and equipment, net
|
$
|
5,885
|
|
|
$
|
6,312
|
|
|
$
|
11,685
|
|
|
$
|
14,008
|
|
|
$
|
13,499
|
|
Total assets
|
$
|
6,354
|
|
|
$
|
7,053
|
|
|
$
|
12,429
|
|
|
$
|
14,297
|
|
|
$
|
13,764
|
|
Current maturities of long-term debt
|
$
|
100
|
|
|
$
|
100
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total current liabilities
|
$
|
726
|
|
|
$
|
605
|
|
|
$
|
922
|
|
|
$
|
689
|
|
|
$
|
551
|
|
Long-term debt - principal amount
|
$
|
5,168
|
|
|
$
|
6,043
|
|
|
$
|
6,360
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Deferred gain and issuance costs, net
|
$
|
397
|
|
|
$
|
491
|
|
|
$
|
(68
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Other long-term liabilities
|
$
|
620
|
|
|
$
|
830
|
|
|
$
|
549
|
|
|
$
|
497
|
|
|
$
|
511
|
|
Equity
|
$
|
(557
|
)
|
|
$
|
(916
|
)
|
|
$
|
2,611
|
|
|
$
|
9,989
|
|
|
$
|
9,860
|
|
ITEM 7
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
2016
|
|
2015
|
|
2014
|
||||||
Brent oil ($/Bbl)
|
$
|
45.04
|
|
|
$
|
53.64
|
|
|
$
|
99.51
|
|
WTI oil ($/Bbl)
|
$
|
43.32
|
|
|
$
|
48.80
|
|
|
$
|
93.00
|
|
NYMEX gas ($/MMBtu)
|
$
|
2.42
|
|
|
$
|
2.75
|
|
|
$
|
4.34
|
|
|
For the years ended
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Pre-tax income (loss)
|
$
|
201
|
|
|
$
|
(5,476
|
)
|
|
$
|
(2,421
|
)
|
Income tax benefit
|
78
|
|
|
1,922
|
|
|
987
|
|
|||
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
For the years ended
December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
United States federal statutory tax rate
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
State income taxes, net of federal
|
6
|
|
|
5
|
|
|
6
|
|
Valuation allowance
|
199
|
|
|
(7
|
)
|
|
—
|
|
Cancellation of debt income
|
(288
|
)
|
|
—
|
|
|
—
|
|
Stock-based compensation
|
3
|
|
|
—
|
|
|
—
|
|
Federal effect of state taxes on above items
|
5
|
|
|
2
|
|
|
—
|
|
Other
|
1
|
|
|
—
|
|
|
—
|
|
Effective tax rate
|
(39
|
)%
|
|
35
|
%
|
|
41
|
%
|
•
|
Realized crude oil prices, including the effect of cash received from settled hedges, decreased
15%
from
$49.19
to
$42.01
per barrel.
|
•
|
Reduced capital investment by 81% from $401 million in 2015 to $75 million in 2016.
|
•
|
Average daily oil and gas production volumes decreased
12.5%
from
160,000
to
140,000
Boe.
|
•
|
Production costs decreased
16%
from $951 million to
$800 million
.
|
•
|
General and administrative expenses decreased 30% from $354 million to $248 million, and adjusted general and administrative expenses decreased 20%.
|
•
|
In 2016, net income of
$279 million
included a net gain of
$805 million
on early extinguishment of debt and $283 million of non-cash derivative losses.
|
•
|
Adjusted net loss increased
2%
from
$311 million
to
$317 million
.
|
•
|
Realized crude oil prices, including the effect of cash received from settled hedges, decreased 47% from
$92.30
to
$49.19
per barrel.
|
•
|
Reduced capital investment by 81% from $2,089 million in 2014 to $401 million in 2015.
|
•
|
Average daily oil and gas production volumes increased 1% from
159,000
to
160,000
Boe.
|
•
|
Production costs decreased 10% from $1,057 million to $951 million.
|
•
|
General and administrative expenses increased 17% from $302 million to $354 million, and adjusted general and administrative expenses decreased 2%.
|
•
|
In 2015, net loss of $3.6 billion included after-tax asset impairments of $2.9 billion.
|
•
|
Adjusted net income decreased from income of
$650 million
to a loss of
$311 million
.
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions, except share data)
|
||||||||||
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
Unusual and infrequent items:
|
|
|
|
|
|
||||||
Non-cash derivative losses (gains)
|
283
|
|
|
(52
|
)
|
|
—
|
|
|||
Severance, early retirement and other costs
|
20
|
|
|
67
|
|
|
—
|
|
|||
Net gains on early extinguishment of debt
|
(805
|
)
|
|
(20
|
)
|
|
—
|
|
|||
Gain from asset divestitures
|
(30
|
)
|
|
—
|
|
|
—
|
|
|||
Refunds, plant turnaround charges and other
|
(13
|
)
|
|
11
|
|
|
52
|
|
|||
Debt issuance costs
|
—
|
|
|
28
|
|
|
—
|
|
|||
Asset impairments
|
—
|
|
|
4,852
|
|
|
3,402
|
|
|||
Write-down of certain assets
|
—
|
|
|
71
|
|
|
—
|
|
|||
Spin-off and transition-related costs
|
—
|
|
|
—
|
|
|
55
|
|
|||
Adjusted income (loss) items before interest and taxes
|
(545
|
)
|
|
4,957
|
|
|
3,509
|
|
|||
Deferred debt issuance costs write-off
|
12
|
|
|
—
|
|
|
—
|
|
|||
Reversal of valuation allowance for deferred tax assets
(a)
|
(63
|
)
|
|
294
|
|
|
—
|
|
|||
Tax effects of these items
|
—
|
|
|
(2,008
|
)
|
|
(1,425
|
)
|
|||
Total
|
(596
|
)
|
|
3,243
|
|
|
2,084
|
|
|||
Adjusted net (loss) income
|
$
|
(317
|
)
|
|
$
|
(311
|
)
|
|
$
|
650
|
|
|
|
|
|
|
|
||||||
Net income (loss) per diluted share
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
Adjusted net (loss) income per diluted share
|
$
|
(7.85
|
)
|
|
$
|
(8.12
|
)
|
|
$
|
16.73
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Non-cash derivative losses (gains)
|
$
|
283
|
|
|
$
|
(52
|
)
|
|
$
|
3
|
|
Net (proceeds) payments from settled derivatives
|
(77
|
)
|
|
(81
|
)
|
|
2
|
|
|||
Net derivative losses (gains)
|
$
|
206
|
|
|
$
|
(133
|
)
|
|
$
|
5
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
General and administrative expenses
|
$
|
248
|
|
|
$
|
354
|
|
|
$
|
302
|
|
Severance, early retirement and other costs
|
(20
|
)
|
|
(67
|
)
|
|
(10
|
)
|
|||
Adjusted general and administrative expenses
|
$
|
228
|
|
|
$
|
287
|
|
|
$
|
292
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Oil prices with hedge ($ per Bbl)
|
$
|
42.01
|
|
|
$
|
49.19
|
|
|
$
|
92.30
|
|
|
|
|
|
|
|
||||||
Oil prices without hedge ($ per Bbl)
|
$
|
39.72
|
|
|
$
|
47.15
|
|
|
$
|
92.30
|
|
NGLs prices ($ per Bbl)
|
$
|
22.39
|
|
|
$
|
19.62
|
|
|
$
|
47.84
|
|
Gas prices with hedge ($ per Mcf)
|
$
|
2.28
|
|
|
$
|
2.66
|
|
|
$
|
4.39
|
|
|
2016
|
|
2015
|
|
2014
|
|||
Oil with hedge as a percentage of Brent
|
93
|
%
|
|
92
|
%
|
|
93
|
%
|
|
|
|
|
|
|
|||
Oil without hedge as a percentage of Brent
|
88
|
%
|
|
88
|
%
|
|
93
|
%
|
Oil without hedge as a percentage of WTI
|
92
|
%
|
|
97
|
%
|
|
99
|
%
|
Gas with hedge as a percentage of NYMEX
|
94
|
%
|
|
97
|
%
|
|
101
|
%
|
|
2016
|
|
2015
|
|
2014
|
|||
Oil (MBbl/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
57
|
|
|
64
|
|
|
64
|
|
Los Angeles Basin
|
29
|
|
|
34
|
|
|
29
|
|
Ventura Basin
|
5
|
|
|
6
|
|
|
6
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
91
|
|
|
104
|
|
|
99
|
|
|
|
|
|
|
|
|||
NGLs (MBbl/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
15
|
|
|
17
|
|
|
18
|
|
Los Angeles Basin
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin
|
1
|
|
|
1
|
|
|
1
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
16
|
|
|
18
|
|
|
19
|
|
|
|
|
|
|
|
|||
Natural gas (MMcf/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
150
|
|
|
172
|
|
|
180
|
|
Los Angeles Basin
|
3
|
|
|
2
|
|
|
1
|
|
Ventura Basin
|
8
|
|
|
11
|
|
|
11
|
|
Sacramento Basin
|
36
|
|
|
44
|
|
|
54
|
|
Total
|
197
|
|
|
229
|
|
|
246
|
|
|
|
|
|
|
|
|||
Total Production (MBoe/d)
(a)
|
140
|
|
|
160
|
|
|
159
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, for the year ended December 31,
2016
, the average prices of Brent oil and NYMEX natural gas were
$45.04
per barrel and
$2.42
per MMBtu, respectively, resulting in an oil-to-gas price ratio of approximately
19
to 1.
|
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
Cash and cash equivalents
|
$
|
12
|
|
|
$
|
12
|
|
Trade receivables, net
|
$
|
232
|
|
|
$
|
200
|
|
Inventories
|
$
|
58
|
|
|
$
|
58
|
|
Other current assets
|
$
|
123
|
|
|
$
|
168
|
|
Property, plant and equipment, net
|
$
|
5,885
|
|
|
$
|
6,312
|
|
Other assets
|
$
|
44
|
|
|
$
|
303
|
|
Current maturities of long-term debt
|
$
|
100
|
|
|
$
|
100
|
|
Accounts payable
|
$
|
219
|
|
|
$
|
257
|
|
Accrued liabilities
|
$
|
407
|
|
|
$
|
222
|
|
Current income taxes
|
$
|
—
|
|
|
$
|
26
|
|
Long-term debt - principal amount
|
$
|
5,168
|
|
|
$
|
6,043
|
|
Deferred gain and financing costs, net
|
$
|
397
|
|
|
$
|
491
|
|
Other long-term liabilities
|
$
|
620
|
|
|
$
|
830
|
|
Equity
|
$
|
(557
|
)
|
|
$
|
(916
|
)
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Oil and gas net sales
(a)
|
$
|
1,621
|
|
|
$
|
2,134
|
|
|
$
|
4,064
|
|
Net derivative (losses) gains
(b)
|
(206
|
)
|
|
133
|
|
|
(5
|
)
|
|||
Other revenue
|
132
|
|
|
136
|
|
|
114
|
|
|||
Production costs
|
(800
|
)
|
|
(951
|
)
|
|
(1,057
|
)
|
|||
General and administrative expenses
|
(248
|
)
|
|
(354
|
)
|
|
(302
|
)
|
|||
Depreciation, depletion and amortization
|
(559
|
)
|
|
(1,004
|
)
|
|
(1,198
|
)
|
|||
Asset impairments
|
—
|
|
|
(4,852
|
)
|
|
(3,402
|
)
|
|||
Taxes other than on income
|
(144
|
)
|
|
(180
|
)
|
|
(217
|
)
|
|||
Exploration expense
|
(23
|
)
|
|
(36
|
)
|
|
(139
|
)
|
|||
Other expenses, net
|
(79
|
)
|
|
(168
|
)
|
|
(207
|
)
|
|||
Interest and debt expense, net
|
(328
|
)
|
|
(326
|
)
|
|
(72
|
)
|
|||
Net gains on early extinguishment of debt
|
805
|
|
|
20
|
|
|
—
|
|
|||
Other non-operating income (expense)
|
30
|
|
|
(28
|
)
|
|
—
|
|
|||
Income tax benefit
|
78
|
|
|
1,922
|
|
|
987
|
|
|||
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
|
|
|
|
|
||||||
Adjusted net (loss) income
(c)
|
$
|
(317
|
)
|
|
$
|
(311
|
)
|
|
$
|
650
|
|
Adjusted EBITDAX
(d)
|
$
|
616
|
|
|
$
|
906
|
|
|
$
|
2,548
|
|
|
|
|
|
|
|
||||||
Effective tax rate
|
(39
|
)%
|
|
35
|
%
|
|
41
|
%
|
(a)
|
Includes related-party sales for 2014.
|
(b)
|
Amounts are net of (proceeds) payments from settled derivatives of $(77) million, $(81) million and $2 million, in 2016, 2015 and 2014, respectively.
|
(c)
|
See "Financial and Operating Results" above for our Non-GAAP reconciliation.
|
(d)
|
We define adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and other unusual and infrequent items. Our management believes adjusted EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. While adjusted EBITDAX is a non-GAAP measure, the amounts included in the calculation of adjusted EBITDAX were computed in accordance with GAAP. This measure is a material component of certain of our financial covenants under our first-lien, first-out credit facilities and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from adjusted EBITDAX are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
Interest and debt expense
|
328
|
|
|
326
|
|
|
72
|
|
|||
Income tax benefit
|
(78
|
)
|
|
(1,922
|
)
|
|
(987
|
)
|
|||
Depreciation, depletion and amortization
|
559
|
|
|
1,004
|
|
|
1,198
|
|
|||
Exploration expense
|
23
|
|
|
36
|
|
|
139
|
|
|||
Adjusted income items before interest and taxes
(a)
|
(545
|
)
|
|
4,957
|
|
|
3,509
|
|
|||
Other non-cash items
|
50
|
|
|
59
|
|
|
51
|
|
|||
Adjusted EBITDAX
|
$
|
616
|
|
|
$
|
906
|
|
|
$
|
2,548
|
|
(a)
|
See "Financial and Operating Results" for a table which includes items reconciling net income (loss) to adjusted net income (loss).
|
|
2016
|
|
2015
|
|
2014
|
||||||
Production costs
|
$
|
15.61
|
|
|
$
|
16.30
|
|
|
$
|
18.23
|
|
General and administrative expense, as adjusted
(a)
|
$
|
0.72
|
|
|
$
|
1.00
|
|
|
$
|
1.47
|
|
Other operating expenses, as adjusted
(b)
|
$
|
0.67
|
|
|
$
|
0.36
|
|
|
$
|
0.55
|
|
Depreciation, depletion and amortization
|
$
|
10.28
|
|
|
$
|
16.72
|
|
|
$
|
20.40
|
|
Taxes other than on income
|
$
|
2.36
|
|
|
$
|
2.67
|
|
|
$
|
3.50
|
|
(a)
|
For 2016, the amount excludes unusual and infrequent charges related to severance and early retirement costs associated with field personnel totaling $0.12 per Boe. For 2015, the amount excludes charges of $0.31 per Boe related to early retirement and severance costs. For 2014, the amount excludes charges of $0.10 per Boe related to Spin-off and transition-related costs.
|
(b)
|
For 2016, the amount excludes net unusual and infrequent gains of $0.35 that include refunds partially offset by plant turnaround charges and other items. For 2015, the amount excludes charges related to the write-down of certain assets and rig termination charges of $1.42 per Boe. For 2014, the amount excludes charges related to rig termination charges and Spin-off and transition-related charges of $0.97 per Boe.
|
|
Q1 2017
|
|
Q2 2017
|
|
Q3 2017
|
|
Q4 2017
|
|
Q1 2018
|
|
Q2-Q4 2018
|
||||||||||||
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Calls:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
12,100
|
|
|
5,000
|
|
|
10,000
|
|
|
15,000
|
|
|
15,600
|
|
|
15,000
|
|
||||||
Weighted-average price per barrel
|
$
|
56.37
|
|
|
$
|
55.05
|
|
|
$
|
56.15
|
|
|
$
|
56.12
|
|
|
$
|
58.77
|
|
|
$
|
58.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Puts:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
22,100
|
|
|
20,000
|
|
|
17,000
|
|
|
10,000
|
|
|
—
|
|
|
—
|
|
||||||
Weighted-average price per barrel
|
$
|
49.10
|
|
|
$
|
50.25
|
|
|
$
|
50.88
|
|
|
$
|
48.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
20,000
|
|
|
20,000
|
|
|
20,000
|
|
|
20,000
|
|
|
—
|
|
|
—
|
|
||||||
Weighted-average price per barrel
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Net cash flows provided by operating activities
|
$
|
130
|
|
|
$
|
403
|
|
|
$
|
2,371
|
|
Net cash flows used in investing activities
|
$
|
(61
|
)
|
|
$
|
(757
|
)
|
|
$
|
(2,312
|
)
|
Net cash flows provided by (used in) financing activities
|
$
|
(69
|
)
|
|
$
|
352
|
|
|
$
|
(45
|
)
|
Adjusted EBITDAX
(a)
|
$
|
616
|
|
|
$
|
906
|
|
|
$
|
2,548
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Net cash provided by operating activities
|
$
|
130
|
|
|
$
|
403
|
|
|
$
|
2,371
|
|
Cash interest
|
384
|
|
|
359
|
|
|
3
|
|
|||
Cash income taxes
|
—
|
|
|
—
|
|
|
165
|
|
|||
Exploration expenditures
|
20
|
|
|
27
|
|
|
38
|
|
|||
Other changes in operating assets and liabilities
|
95
|
|
|
106
|
|
|
(81
|
)
|
|||
Other
|
(13
|
)
|
|
11
|
|
|
52
|
|
|||
Adjusted EBITDAX
|
$
|
616
|
|
|
$
|
906
|
|
|
$
|
2,548
|
|
|
Conventional
|
|
Unconventional
|
|
Other
|
|
Total Capital Investments
|
||||||||||||||||||||
|
Primary
|
|
Waterflood
|
|
Steamflood
|
|
Total
|
|
Primary
|
|
|
||||||||||||||||
Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
San Joaquin
|
$
|
6
|
|
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
15
|
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
27
|
|
Los Angeles
|
—
|
|
|
8
|
|
|
7
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|||||||
Ventura
|
7
|
|
|
1
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|||||||
Sacramento
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|||||||
Basin Total
|
16
|
|
|
14
|
|
|
11
|
|
|
41
|
|
|
12
|
|
|
—
|
|
|
53
|
|
|||||||
Other
(a)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
22
|
|
|||||||
Total
|
$
|
16
|
|
|
$
|
14
|
|
|
$
|
11
|
|
|
$
|
41
|
|
|
$
|
12
|
|
|
$
|
22
|
|
|
$
|
75
|
|
(a)
|
Includes $19 million for a major turnaround of our power plant.
|
|
Payments Due by Year
|
||||||||||||||||||
|
Total
|
|
2017
|
|
2018 and 2019
|
|
2020 and 2021
|
|
2022 and thereafter
|
||||||||||
|
(in millions)
|
||||||||||||||||||
On-Balance Sheet
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt - principal amount (Note 5)
(a)
|
$
|
5,268
|
|
|
$
|
100
|
|
|
$
|
1,397
|
|
|
$
|
1,754
|
|
|
$
|
2,017
|
|
Other long-term liabilities
(b)
|
159
|
|
|
12
|
|
|
19
|
|
|
15
|
|
|
113
|
|
|||||
|
|
|
|
|
|
|
|
|
|
||||||||||
Off-Balance Sheet
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating leases
|
112
|
|
|
16
|
|
|
30
|
|
|
16
|
|
|
50
|
|
|||||
Purchase obligations
(c)(d)
|
340
|
|
|
74
|
|
|
219
|
|
|
16
|
|
|
31
|
|
|||||
Total
|
$
|
5,879
|
|
|
$
|
202
|
|
|
$
|
1,665
|
|
|
$
|
1,801
|
|
|
$
|
2,211
|
|
(a)
|
Excludes interest on the debt. As of December 31, 2016, interest on long-term debt totaling $2.0 billion is payable in the following years: 2017 - $380 million, 2018 and 2019 - $743 million, 2020 and 2021 - $627 million, 2022 and thereafter - $206 million. The calculation of interest payable on the variable interest debt assumes the interest rate at December 31, 2016 to be the applicable interest rate for the entire term. In performing the calculation, the Revolving Credit Facility borrowings outstanding at December 31, 2016 of
$847 million
were assumed to be outstanding for the entire term of the agreement.
|
(b)
|
Includes obligations under postretirement benefit and deferred compensation plans.
|
(c)
|
Amounts include payments that will become due under long-term agreements to purchase goods and services used in the normal course of business to secure pipeline capacity, drilling rigs and services.
|
(d)
|
Included in these obligations is a commitment to invest approximately $170 million in evaluation and development activities for one of our oil and gas properties prior to the end of 2018. Any deficiency in meeting this capital investment obligation would need to be paid in cash. Our 2017 capital program includes development plans for these properties, and we expect to fulfill the minimum investment requirement.
|
ITEM 7A
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
Pre-tax 2017 Price Sensitivities
|
On Income
|
|
On Cash
|
$1 change in Brent index - Oil
(a)
|
$18.0 million
|
|
$18.0 million
|
$1 change in Brent index - NGLs
|
$2.8 million
|
|
$2.8 million
|
$0.50 change in NYMEX - Gas
|
$11.8 million
|
|
$11.8 million
|
Year of Maturity
|
|
U.S. Dollar Fixed-Rate Debt
|
|
U.S. Dollar Variable-Rate Debt
|
|
Total
|
||||||
2017
|
|
$
|
—
|
|
|
$
|
100
|
|
|
$
|
100
|
|
2018
|
|
—
|
|
|
100
|
|
|
100
|
|
|||
2019
|
|
—
|
|
|
1,297
|
|
|
1,297
|
|
|||
2020
|
|
193
|
|
|
—
|
|
|
193
|
|
|||
2021
|
|
561
|
|
|
1,000
|
|
|
1,561
|
|
|||
Thereafter
|
|
2,017
|
|
|
—
|
|
|
2,017
|
|
|||
Total
|
|
$
|
2,771
|
|
|
$
|
2,497
|
|
|
$
|
5,268
|
|
Weighted-average interest rate
|
|
7.53
|
%
|
|
6.91
|
%
|
|
7.24
|
%
|
|||
Fair Value
|
|
$
|
2,390
|
|
|
$
|
2,497
|
|
|
$
|
4,887
|
|
•
|
financial position, liquidity, cash flows, and results of operations
|
•
|
business prospects
|
•
|
transactions and projects
|
•
|
operating costs
|
•
|
operations and operational results including production, hedging, capital investment and expected VCI
|
•
|
budgets and maintenance capital requirements
|
•
|
reserves
|
•
|
commodity price changes
|
•
|
debt limitations on our financial flexibility
|
•
|
insufficient cash flow to fund planned investment
|
•
|
inability to enter desirable transactions including asset sales and joint ventures
|
•
|
legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products
|
•
|
unexpected geologic conditions
|
•
|
changes in business strategy
|
•
|
inability to replace reserves
|
•
|
insufficient capital, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors
|
•
|
inability to enter efficient hedges
|
•
|
equipment, service or labor price inflation or unavailability
|
•
|
availability or timing of, or conditions imposed on, permits and approvals
|
•
|
lower-than-expected production, reserves or resources from development projects or acquisitions or higher-than-expected decline rates
|
•
|
disruptions due to accidents, mechanical failures, transportation constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events
|
•
|
factors discussed in “Item 1A – Risk Factors”.
|
ITEM 8
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
|
|
|
/s/ KPMG LLP
|
|
|
|
|
|
/s/ KPMG LLP
|
|
2016
|
|
2015
|
||||
|
|
|
|
||||
CURRENT ASSETS
|
|
|
|
||||
|
|
|
|
||||
Cash and cash equivalents
|
$
|
12
|
|
|
$
|
12
|
|
Trade receivables, net
|
232
|
|
|
200
|
|
||
Inventories
|
58
|
|
|
58
|
|
||
Other current assets
|
123
|
|
|
168
|
|
||
Total current assets
|
425
|
|
|
438
|
|
||
|
|
|
|
||||
PROPERTY, PLANT AND EQUIPMENT
|
20,915
|
|
|
20,996
|
|
||
Accumulated depreciation, depletion and amortization
|
(15,030
|
)
|
|
(14,684
|
)
|
||
Total property, plant, equipment
|
5,885
|
|
|
6,312
|
|
||
|
|
|
|
||||
OTHER ASSETS
|
44
|
|
|
303
|
|
||
|
|
|
|
||||
TOTAL ASSETS
|
$
|
6,354
|
|
|
$
|
7,053
|
|
CURRENT LIABILITIES
|
|
|
|
||||
|
|
|
|
||||
Current maturities of long-term debt
|
$
|
100
|
|
|
$
|
100
|
|
Accounts payable
|
219
|
|
|
257
|
|
||
Accrued liabilities
|
407
|
|
|
222
|
|
||
Current income taxes
|
—
|
|
|
26
|
|
||
Total current liabilities
|
726
|
|
|
605
|
|
||
|
|
|
|
||||
LONG-TERM DEBT - PRINCIPAL AMOUNT
|
5,168
|
|
|
6,043
|
|
||
|
|
|
|
||||
DEFERRED GAIN AND ISSUANCE COSTS, NET
|
397
|
|
|
491
|
|
||
|
|
|
|
||||
OTHER LONG-TERM LIABILITIES
|
620
|
|
|
830
|
|
||
|
|
|
|
||||
EQUITY
|
|
|
|
||||
|
|
|
|
||||
Preferred stock (20 million shares authorized at $0.01 par value) no shares outstanding at December 31, 2016 or 2015
|
—
|
|
|
—
|
|
||
Common stock (200 million shares authorized at $0.01 par value)
outstanding shares (2016 — 42,542,637 shares and 2015 — 38,818,048 shares)
|
—
|
|
|
—
|
|
||
Additional paid-in capital
|
4,861
|
|
|
4,782
|
|
||
Accumulated deficit
|
(5,404
|
)
|
|
(5,683
|
)
|
||
Accumulated other comprehensive loss
|
(14
|
)
|
|
(15
|
)
|
||
|
|
|
|
|
|||
Total equity
|
(557
|
)
|
|
(916
|
)
|
||
|
|
|
|
||||
TOTAL LIABILITIES AND EQUITY
|
$
|
6,354
|
|
|
$
|
7,053
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
REVENUES AND OTHER
|
|
|
|
|
|
||||||
Oil and gas net sales
|
$
|
1,621
|
|
|
$
|
2,134
|
|
|
$
|
1,447
|
|
Oil and gas sales to related parties
|
—
|
|
|
—
|
|
|
2,617
|
|
|||
Net derivative (losses) gains
|
(206
|
)
|
|
133
|
|
|
(5
|
)
|
|||
Other revenue
|
132
|
|
|
136
|
|
|
114
|
|
|||
Total revenues and other
|
1,547
|
|
|
2,403
|
|
|
4,173
|
|
|||
|
|
|
|
|
|
||||||
COSTS AND OTHER
|
|
|
|
|
|
||||||
Production costs
|
800
|
|
|
951
|
|
|
1,057
|
|
|||
General and administrative expenses
|
248
|
|
|
354
|
|
|
302
|
|
|||
Depreciation, depletion and amortization
|
559
|
|
|
1,004
|
|
|
1,198
|
|
|||
Asset impairments
|
—
|
|
|
4,852
|
|
|
3,402
|
|
|||
Taxes other than on income
|
144
|
|
|
180
|
|
|
217
|
|
|||
Exploration expense
|
23
|
|
|
36
|
|
|
139
|
|
|||
Other expenses, net
|
79
|
|
|
168
|
|
|
207
|
|
|||
Total costs and other
|
1,853
|
|
|
7,545
|
|
|
6,522
|
|
|||
OPERATING LOSS
|
(306
|
)
|
|
(5,142
|
)
|
|
(2,349
|
)
|
|||
|
|
|
|
|
|
||||||
NON-OPERATING INCOME (LOSS)
|
|
|
|
|
|
||||||
Interest and debt expense, net
|
(328
|
)
|
|
(326
|
)
|
|
(72
|
)
|
|||
Net gains on early extinguishment of debt
|
805
|
|
|
20
|
|
|
—
|
|
|||
Other non-operating income (expense)
|
30
|
|
|
(28
|
)
|
|
—
|
|
|||
INCOME (LOSS) BEFORE INCOME TAXES
|
201
|
|
|
(5,476
|
)
|
|
(2,421
|
)
|
|||
Income tax benefit
|
78
|
|
|
1,922
|
|
|
987
|
|
|||
NET INCOME (LOSS)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
|
|
|
|
|
||||||
Net income (loss) per share of common stock
|
|
|
|
|
|
||||||
Basic
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
Diluted
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
|
|
|
|
|
|
||||||
Dividends per common share
|
$
|
—
|
|
|
$
|
0.30
|
|
|
$
|
—
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
Other comprehensive income (loss) items:
|
|
|
|
|
|
||||||
Unrealized (losses) gains on derivatives
(a)
|
—
|
|
|
—
|
|
|
(2
|
)
|
|||
Pension and postretirement (losses) gains
(b)
|
(9
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|||
Reclassification to income of realized losses (gains) on derivatives
(c)
|
—
|
|
|
—
|
|
|
3
|
|
|||
Reclassification to income of realized losses (gains) on pensions
(d)
|
10
|
|
|
11
|
|
|
—
|
|
|||
Other comprehensive income, net of tax
|
1
|
|
|
9
|
|
|
—
|
|
|||
Comprehensive income (loss)
|
$
|
280
|
|
|
$
|
(3,545
|
)
|
|
$
|
(1,434
|
)
|
(a)
|
Net of tax of zero for 2016 and 2015, respectively, and $1 million for 2014.
|
(b)
|
Net of tax of zero, $1 million and $1 million for 2016, 2015 and 2014, respectively. See Note 13, Retirement and Postretirement Benefit Plans, for additional information.
|
(c)
|
Net of tax of zero for 2016 and 2015, respectively, and $(2) million in 2014.
|
(d)
|
Net of tax of zero, $(7) million and zero for 2016, 2015 and 2014, respectively. See Note 13, Retirement and Postretirement Benefit Plans, for additional information.
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Accumulated Deficit
|
|
Accumulated Other
Comprehensive
Income (Loss)
|
|
Net Parent
Company
Investment
|
|
Total Equity/Net Investment
|
||||||||||||
Balance, December 31, 2013
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(24
|
)
|
|
$
|
10,013
|
|
|
$
|
9,989
|
|
Net income (loss)
(a)
|
—
|
|
|
—
|
|
|
(2,117
|
)
|
|
—
|
|
|
683
|
|
|
(1,434
|
)
|
||||||
Net contributions from Occidental
(b)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56
|
|
|
56
|
|
||||||
Dividend to Occidental
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,000
|
)
|
|
(6,000
|
)
|
||||||
Issuance of common stock at Spin-off
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Reclassification of net parent company investment to additional paid-in capital
|
—
|
|
|
4,752
|
|
|
—
|
|
|
—
|
|
|
(4,752
|
)
|
|
—
|
|
||||||
Balance, December 31, 2014
|
$
|
—
|
|
|
$
|
4,752
|
|
|
$
|
(2,117
|
)
|
|
$
|
(24
|
)
|
|
$
|
—
|
|
|
$
|
2,611
|
|
Net income (loss)
|
—
|
|
|
—
|
|
|
(3,554
|
)
|
|
—
|
|
|
—
|
|
|
(3,554
|
)
|
||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
—
|
|
|
9
|
|
||||||
Dividends on common stock
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
||||||
Issuance of common stock and other, net
|
—
|
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30
|
|
||||||
Balance, December 31, 2015
|
$
|
—
|
|
|
$
|
4,782
|
|
|
$
|
(5,683
|
)
|
|
$
|
(15
|
)
|
|
$
|
—
|
|
|
$
|
(916
|
)
|
Net income (loss)
|
—
|
|
|
—
|
|
|
279
|
|
|
—
|
|
|
—
|
|
|
279
|
|
||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
||||||
Dividends on common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Issuance of common stock and other, net
|
—
|
|
|
79
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
79
|
|
||||||
Balance, December 31, 2016
|
$
|
—
|
|
|
$
|
4,861
|
|
|
$
|
(5,404
|
)
|
|
$
|
(14
|
)
|
|
$
|
—
|
|
|
$
|
(557
|
)
|
(a)
|
Net income of $683 million related to operations from January 1, 2014 through the spin-off date of November 30, 2014 was included in Net Parent Company Investment. The net loss of $2,117 million for the month ended December 31, 2014 reflected our accumulated deficit as of that date as a stand-alone company.
|
(b)
|
Net contributions from Occidental include non-cash contributions of approximately $400 million, predominantly trade receivables, partially offset by $335 million in cash distributions to Occidental.
|
|
2016
|
|
2015
|
|
2014
|
||||||
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
559
|
|
|
1,004
|
|
|
1,198
|
|
|||
Asset impairments
|
—
|
|
|
4,852
|
|
|
3,402
|
|
|||
Deferred income tax benefit
|
(78
|
)
|
|
(2,258
|
)
|
|
(1,152
|
)
|
|||
Net derivative losses (gains)
|
206
|
|
|
(133
|
)
|
|
5
|
|
|||
Net proceeds (payments) on settled derivatives
|
77
|
|
|
81
|
|
|
(2
|
)
|
|||
Net gains on early extinguishment of debt
|
(805
|
)
|
|
(20
|
)
|
|
—
|
|
|||
Deferred gain and issuance costs amortization
|
(41
|
)
|
|
7
|
|
|
—
|
|
|||
Other non-cash tax provision
|
—
|
|
|
310
|
|
|
—
|
|
|||
Other non-cash losses in income, net
|
41
|
|
|
200
|
|
|
113
|
|
|||
Dry hole expenses
|
3
|
|
|
9
|
|
|
101
|
|
|||
Changes in operating assets and liabilities, net:
|
|
|
|
|
|
||||||
(Increase) decrease in receivables, net
|
(33
|
)
|
|
99
|
|
|
146
|
|
|||
(Increase) decrease in inventories
|
—
|
|
|
—
|
|
|
2
|
|
|||
(Increase) decrease in other current assets
|
25
|
|
|
18
|
|
|
(133
|
)
|
|||
Increase (decrease) in accounts payable and accrued liabilities
|
(103
|
)
|
|
(212
|
)
|
|
125
|
|
|||
Net cash provided by operating activities
|
130
|
|
|
403
|
|
|
2,371
|
|
|||
|
|
|
|
|
|
||||||
CASH FLOW FROM INVESTING ACTIVITIES
|
|
|
|
|
|
||||||
Capital investments
|
(75
|
)
|
|
(401
|
)
|
|
(2,089
|
)
|
|||
Changes in capital investment accruals
|
(6
|
)
|
|
(205
|
)
|
|
69
|
|
|||
Asset divestitures
|
20
|
|
|
—
|
|
|
—
|
|
|||
Acquisitions and other
|
—
|
|
|
(151
|
)
|
|
(292
|
)
|
|||
Net cash used by investing activities
|
(61
|
)
|
|
(757
|
)
|
|
(2,312
|
)
|
|||
|
|
|
|
|
|
||||||
CASH FLOW FROM FINANCING ACTIVITIES
|
|
|
|
|
|
||||||
Proceeds from revolving credit facility
|
2,218
|
|
|
2,035
|
|
|
515
|
|
|||
Repayments of revolving credit facility
|
(2,110
|
)
|
|
(1,656
|
)
|
|
(155
|
)
|
|||
Issuance of senior notes
|
—
|
|
|
—
|
|
|
5,000
|
|
|||
Issuance of term loans
|
990
|
|
|
—
|
|
|
1,000
|
|
|||
Debt repurchases
|
(770
|
)
|
|
(12
|
)
|
|
—
|
|
|||
Payments on first-lien first-out term loan
|
(350
|
)
|
|
—
|
|
|
—
|
|
|||
Debt transaction costs
|
(51
|
)
|
|
(11
|
)
|
|
(70
|
)
|
|||
Issuance of common stock
|
4
|
|
|
8
|
|
|
—
|
|
|||
Cash dividends paid
|
—
|
|
|
(12
|
)
|
|
—
|
|
|||
Distributions to Occidental, net
|
—
|
|
|
—
|
|
|
(335
|
)
|
|||
Dividends to Occidental
|
—
|
|
|
—
|
|
|
(6,000
|
)
|
|||
Net cash provided (used) by financing activities
|
(69
|
)
|
|
352
|
|
|
(45
|
)
|
|||
(Decrease) increase in cash and cash equivalents
|
—
|
|
|
(2
|
)
|
|
14
|
|
|||
Cash and cash equivalents—beginning of year
|
12
|
|
|
14
|
|
|
—
|
|
|||
Cash and cash equivalents—end of year
|
$
|
12
|
|
|
$
|
12
|
|
|
$
|
14
|
|
•
|
Our consolidated and combined statements of operations, comprehensive income and cash flows for the year ended December 31, 2014 consist of the consolidated results for the month ended December 31, 2014 and the combined results of the California business prior to the Spin-off.
|
•
|
Our consolidated and combined statement of changes in equity for the year ended December 31, 2014 consists of both the California business prior to the Spin-off and our consolidated activity subsequent to the Spin-off.
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Balance - beginning of year
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
18
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
1
|
|
|
16
|
|
|
3
|
|
|||
Reclassification to property, plant and equipment based on the determination of proved reserves
|
—
|
|
|
(5
|
)
|
|
(8
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
(3
|
)
|
|
(9
|
)
|
|
(9
|
)
|
|||
Balance - end of year
|
$
|
4
|
|
|
$
|
6
|
|
|
$
|
4
|
|
|
For the years ended December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
Beginning balance
|
$
|
357
|
|
|
$
|
415
|
|
Liabilities incurred - capitalized to PP&E
|
2
|
|
|
7
|
|
||
Liabilities settled and paid
|
(10
|
)
|
|
(18
|
)
|
||
Accretion expense
|
22
|
|
|
20
|
|
||
Disposition and other - changes in PP&E
|
(17
|
)
|
|
—
|
|
||
Revisions to estimated cash flows - changes in PP&E
|
57
|
|
|
(67
|
)
|
||
Ending balance
|
$
|
411
|
|
|
$
|
357
|
|
|
Balance at December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
Materials and supplies
|
$
|
55
|
|
|
$
|
55
|
|
Finished goods
|
3
|
|
|
3
|
|
||
Total
|
$
|
58
|
|
|
$
|
58
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
2014 First-Out Credit Facilities (Secured First Lien)
|
|
|
|
||||
Revolving Credit Facility
|
$
|
847
|
|
|
$
|
739
|
|
Term Loan Facility
|
650
|
|
|
1,000
|
|
||
2016 Second-Out Credit Agreement (Secured First Lien)
|
1,000
|
|
|
—
|
|
||
Senior Notes (Secured Second Lien)
|
|
|
|
||||
8% Notes Due 2022
|
2,250
|
|
|
2,250
|
|
||
Senior Unsecured Notes
|
|
|
|
||||
5% Notes Due 2020
|
193
|
|
|
433
|
|
||
5½% Notes Due 2021
|
135
|
|
|
829
|
|
||
6% Notes Due 2024
|
193
|
|
|
892
|
|
||
Total Debt - Principal Amount
|
5,268
|
|
|
6,143
|
|
||
Less Current Maturities of Long-Term Debt
|
(100
|
)
|
|
(100
|
)
|
||
Long-Term Debt - Principal Amount
|
$
|
5,168
|
|
|
$
|
6,043
|
|
2017
|
$
|
100
|
|
2018
|
100
|
|
|
2019
|
1,297
|
|
|
2020
|
193
|
|
|
2021
|
1,561
|
|
|
Thereafter
|
2,017
|
|
|
Total
(a)
|
$
|
5,268
|
|
(a)
|
For information on potential springing maturities, see the "Credit Facilities" and "Senior Notes" sections above.
|
|
Amount
|
||
|
(in millions)
|
||
2017
|
$
|
16
|
|
2018
|
16
|
|
|
2019
|
14
|
|
|
2020
|
8
|
|
|
2021
|
8
|
|
|
Thereafter
|
50
|
|
|
Total minimum lease payments
|
$
|
112
|
|
|
Q1 2017
|
|
Q2 2017
|
|
Q3 2017
|
|
Q4 2017
|
|
Q1 2018
|
|
Q2-Q4 2018
|
||||||||||||
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Calls:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
12,100
|
|
|
5,000
|
|
|
10,000
|
|
|
15,000
|
|
|
15,600
|
|
|
15,000
|
|
||||||
Weighted-average price per barrel
|
$
|
56.37
|
|
|
$
|
55.05
|
|
|
$
|
56.15
|
|
|
$
|
56.12
|
|
|
$
|
58.77
|
|
|
$
|
58.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Puts:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
22,100
|
|
|
20,000
|
|
|
17,000
|
|
|
10,000
|
|
|
—
|
|
|
—
|
|
||||||
Weighted-average price per barrel
|
$
|
49.10
|
|
|
$
|
50.25
|
|
|
$
|
50.88
|
|
|
$
|
48.00
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Swaps:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Barrels per day
|
20,000
|
|
|
20,000
|
|
|
20,000
|
|
|
20,000
|
|
|
—
|
|
|
—
|
|
||||||
Weighted-average price per barrel
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
53.98
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
December 31, 2016
|
||||||||||||
|
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
|
|
|
|
|
|
|
|
||||||
Commodity Contracts
|
Other current assets
|
|
$
|
88
|
|
|
$
|
(49
|
)
|
|
$
|
39
|
|
Commodity Contracts
|
Other assets
|
|
25
|
|
|
(6
|
)
|
|
19
|
|
|||
|
|
|
|
|
|
|
|
||||||
Liabilities
|
|
|
|
|
|
|
|
||||||
Commodity Contracts
|
Accrued liabilities
|
|
(152
|
)
|
|
49
|
|
|
(103
|
)
|
|||
Commodity Contracts
|
Other long-term liabilities
|
|
(58
|
)
|
|
6
|
|
|
(52
|
)
|
|||
Total derivatives
|
|
|
$
|
(97
|
)
|
|
$
|
—
|
|
|
$
|
(97
|
)
|
|
December 31, 2015
|
||||||||||||
|
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
|
|
|
|
|
|
|
|
||||||
Commodity Contracts
|
Other current assets
|
|
$
|
87
|
|
|
$
|
—
|
|
|
$
|
87
|
|
|
|
|
|
|
|
|
|
||||||
Liabilities
|
|
|
|
|
|
|
|
||||||
Commodity Contracts
|
Accrued liabilities
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|||
Total derivatives
|
|
|
$
|
86
|
|
|
$
|
—
|
|
|
$
|
86
|
|
For the years ended December 31,
|
United States
Federal
|
|
State
and Local
|
|
Total
|
||||||
|
(in millions)
|
||||||||||
2016
|
|
|
|
|
|
|
|
|
|||
Current
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Deferred
|
(66
|
)
|
|
(12
|
)
|
|
(78
|
)
|
|||
|
$
|
(66
|
)
|
|
$
|
(12
|
)
|
|
$
|
(78
|
)
|
|
|
|
|
|
|
||||||
2015
|
|
|
|
|
|
|
|
|
|||
Current
|
$
|
255
|
|
|
$
|
81
|
|
|
$
|
336
|
|
Deferred
|
(1,961
|
)
|
|
(297
|
)
|
|
(2,258
|
)
|
|||
|
$
|
(1,706
|
)
|
|
$
|
(216
|
)
|
|
$
|
(1,922
|
)
|
|
|
|
|
|
|
||||||
2014
|
|
|
|
|
|
|
|
|
|||
Current
|
$
|
66
|
|
|
$
|
99
|
|
|
$
|
165
|
|
Deferred
|
(840
|
)
|
|
(312
|
)
|
|
(1,152
|
)
|
|||
|
$
|
(774
|
)
|
|
$
|
(213
|
)
|
|
$
|
(987
|
)
|
|
For the years ended
December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
United States federal statutory tax rate
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
State income taxes, net of federal
|
6
|
|
|
5
|
|
|
6
|
|
Valuation allowance
|
199
|
|
|
(7
|
)
|
|
—
|
|
Cancellation of debt income
|
(288
|
)
|
|
—
|
|
|
—
|
|
Stock-based compensation
|
3
|
|
|
—
|
|
|
—
|
|
Federal effect of state taxes on the above items
|
5
|
|
|
2
|
|
|
—
|
|
Other
|
1
|
|
|
—
|
|
|
—
|
|
Effective tax rate
|
(39
|
)%
|
|
35
|
%
|
|
41
|
%
|
|
2016
|
|
2015
|
||||||||||||
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
||||||||
|
(in millions)
|
||||||||||||||
Debt
|
$
|
693
|
|
|
$
|
—
|
|
|
$
|
608
|
|
|
$
|
—
|
|
Property, plant and equipment differences
|
60
|
|
|
(335
|
)
|
|
132
|
|
|
(427
|
)
|
||||
Postretirement benefit accruals
|
45
|
|
|
—
|
|
|
41
|
|
|
—
|
|
||||
Deferred compensation and benefits
|
74
|
|
|
—
|
|
|
75
|
|
|
—
|
|
||||
Asset retirement obligations
|
183
|
|
|
—
|
|
|
156
|
|
|
—
|
|
||||
Federal effect of state income taxes
|
—
|
|
|
—
|
|
|
28
|
|
|
(24
|
)
|
||||
Net operating loss carryforward
|
61
|
|
|
—
|
|
|
7
|
|
|
—
|
|
||||
All other
|
39
|
|
|
(40
|
)
|
|
47
|
|
|
(3
|
)
|
||||
Subtotal
|
1,155
|
|
|
(375
|
)
|
|
1,094
|
|
|
(454
|
)
|
||||
Valuation allowance
|
(780
|
)
|
|
—
|
|
|
(382
|
)
|
|
—
|
|
||||
Total net deferred taxes
|
$
|
375
|
|
|
$
|
(375
|
)
|
|
$
|
712
|
|
|
$
|
(454
|
)
|
|
Stock-Settled
|
|
Cash-Settled
|
||||||
|
Number of Shares
(in thousands)
|
|
Weighted-Average Grant-Date Fair Value
|
|
Number of Shares
(in thousands) |
||||
Unvested at January 1
|
132
|
|
|
$
|
79.39
|
|
|
904
|
|
Granted
|
453
|
|
|
$
|
15.40
|
|
|
1,273
|
|
Vested
|
(121
|
)
|
|
$
|
62.04
|
|
|
(344
|
)
|
Forfeited
|
(24
|
)
|
|
$
|
52.66
|
|
|
(88
|
)
|
Converted to stock-settled awards
|
165
|
|
|
$
|
18.50
|
|
|
(165
|
)
|
Unvested at December 31
|
605
|
|
|
$
|
22.08
|
|
|
1,580
|
|
|
Stock-Settled
|
|
Cash-Settled
|
||||||
|
Number of Shares
(in thousands) |
|
Weighted-Average Grant-Date Fair Value
|
|
Number of Shares
(in thousands) |
||||
Unvested at January 1
|
322
|
|
|
$
|
77.80
|
|
|
279
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
—
|
|
Vested
|
(118
|
)
|
|
$
|
77.26
|
|
|
—
|
|
Forfeited
|
(21
|
)
|
|
$
|
51.40
|
|
|
(3
|
)
|
Converted to stock-settled awards
|
276
|
|
|
$
|
18.50
|
|
|
(276
|
)
|
Unvested at December 31
|
459
|
|
|
$
|
44.34
|
|
|
—
|
|
|
|
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
|
|
|
Options
(000's)
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Grant-Date Fair Value
|
|
Aggregate Intrinsic Value
|
|||||||
Beginning balance, January 1
|
1,152
|
|
|
$
|
70.21
|
|
|
$
|
18.46
|
|
|
$
|
—
|
|
Granted
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Exercised
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Forfeited
|
(43
|
)
|
|
$
|
78.37
|
|
|
$
|
19.46
|
|
|
$
|
—
|
|
Expired or Canceled
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Ending balance, December 31
|
1,109
|
|
|
$
|
69.89
|
|
|
$
|
18.42
|
|
|
$
|
—
|
|
Exercisable at December 31
|
669
|
|
|
$
|
73.61
|
|
|
$
|
18.88
|
|
|
$
|
—
|
|
|
|
2015
|
|
2014
|
||||
Exercise price per share
|
|
$
|
42.00
|
|
|
$
|
81.10
|
|
Expected life (in years)
|
|
4.5
|
|
|
4.5
|
|
||
Expected volatility
|
|
44.7
|
%
|
|
35.4
|
%
|
||
Risk-free interest rate
|
|
1.56
|
%
|
|
1.40
|
%
|
||
Dividend yield
|
|
0.95
|
%
|
|
0.50
|
%
|
||
Grant date fair value of stock option awards granted
|
|
$
|
15.00
|
|
|
$
|
19.80
|
|
|
Common Stock
|
|
|
(in thousands)
|
|
Balance, December 31, 2014
|
38,564
|
|
Issued
|
254
|
|
Balance, December 31, 2015
|
38,818
|
|
Issued
|
3,725
|
|
Balance, December 31, 2016
|
42,543
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions, except per-share amounts)
|
||||||||||
Basic EPS calculation
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
Net loss allocated to participating securities
|
(6
|
)
|
|
—
|
|
|
—
|
|
|||
Net income (loss) available to common stockholders
|
$
|
273
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding - basic
|
40.4
|
|
|
38.3
|
|
|
38.2
|
|
|||
Basic EPS
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
|
|
|
|
|
|
||||||
Diluted EPS calculation
|
|
|
|
|
|
||||||
Net income (loss)
|
$
|
279
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
Net loss allocated to participating securities
|
(6
|
)
|
|
—
|
|
|
—
|
|
|||
Net income (loss) available to common stockholders
|
$
|
273
|
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding - basic
|
40.4
|
|
|
38.3
|
|
|
38.2
|
|
|||
Dilutive effect of potentially dilutive securities
|
—
|
|
|
—
|
|
|
—
|
|
|||
Weighted-average common shares outstanding - diluted
|
40.4
|
|
|
38.3
|
|
|
38.2
|
|
|||
Diluted EPS
|
$
|
6.76
|
|
|
$
|
(92.79
|
)
|
|
$
|
(37.54
|
)
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||
|
As of December 31,
|
||||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Amounts recognized in the balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accrued liabilities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2
|
)
|
|
$
|
(1
|
)
|
Other long-term liabilities
|
(26
|
)
|
|
(27
|
)
|
|
(75
|
)
|
|
(70
|
)
|
||||
|
$
|
(26
|
)
|
|
$
|
(27
|
)
|
|
$
|
(77
|
)
|
|
$
|
(71
|
)
|
Amounts recognized in accumulated other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
$
|
(18
|
)
|
|
$
|
(19
|
)
|
|
$
|
4
|
|
|
$
|
4
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||||||
Changes in the benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Benefit obligation—beginning of year
|
$
|
83
|
|
|
$
|
108
|
|
|
$
|
71
|
|
|
$
|
68
|
|
Service cost—benefits earned during the period
|
1
|
|
|
4
|
|
|
3
|
|
|
5
|
|
||||
Interest cost on projected benefit obligation
|
3
|
|
|
4
|
|
|
3
|
|
|
3
|
|
||||
Curtailment (gain) loss
|
—
|
|
|
(12
|
)
|
|
—
|
|
|
5
|
|
||||
Actuarial loss (gain)
|
7
|
|
|
24
|
|
|
1
|
|
|
(10
|
)
|
||||
Benefits paid
|
(24
|
)
|
|
(45
|
)
|
|
(1
|
)
|
|
—
|
|
||||
Benefit obligation—end of year
|
$
|
70
|
|
|
$
|
83
|
|
|
$
|
77
|
|
|
$
|
71
|
|
|
|
|
|
|
|
|
|
||||||||
Changes in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Fair value of plan assets—beginning of year
|
$
|
56
|
|
|
$
|
87
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
2
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
10
|
|
|
13
|
|
|
1
|
|
|
—
|
|
||||
Benefits paid
|
(24
|
)
|
|
(45
|
)
|
|
(1
|
)
|
|
—
|
|
||||
Fair value of plan assets—end of year
|
$
|
44
|
|
|
$
|
56
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Unfunded status
|
$
|
(26
|
)
|
|
$
|
(27
|
)
|
|
$
|
(77
|
)
|
|
$
|
(71
|
)
|
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
Projected Benefit Obligation
|
$
|
70
|
|
|
$
|
83
|
|
Accumulated Benefit Obligation
|
$
|
67
|
|
|
$
|
81
|
|
Fair Value of Plan Assets
|
$
|
44
|
|
|
$
|
56
|
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
|
(in millions)
|
||||||||||||||||||||||
Net periodic benefit costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Service cost—benefits earned during the period
|
$
|
1
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
5
|
|
|
$
|
4
|
|
Interest cost on projected benefit obligation
|
3
|
|
|
4
|
|
|
4
|
|
|
3
|
|
|
3
|
|
|
2
|
|
||||||
Expected return on plan assets
|
(3
|
)
|
|
(5
|
)
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of net actuarial loss (gain)
|
2
|
|
|
3
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||
Settlement cost
|
8
|
|
|
18
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Curtailment loss
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
||||||
Net periodic benefit cost
|
$
|
11
|
|
|
$
|
24
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
13
|
|
|
$
|
7
|
|
|
Pension
Benefits |
|
Postretirement
Benefits |
||||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
||||||||||||
|
(in millions)
|
||||||||||||||||||||||
Amounts recognized in other comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Net actuarial (loss) gain
|
$
|
(9
|
)
|
|
$
|
(28
|
)
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
1
|
|
Net prior service (cost) credit
|
—
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Settlement cost
|
8
|
|
|
18
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Transfer adjustment
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||||
Amortization of net actuarial gain/loss
|
2
|
|
|
3
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||
Total recognized in other comprehensive income (loss)
|
$
|
1
|
|
|
$
|
5
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
4
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
|
For the years ended
December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2016
|
|
2015
|
||||
Benefit Obligation Assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
3.88
|
%
|
|
3.99
|
%
|
|
4.58
|
%
|
|
4.81
|
%
|
Rate of compensation increase
|
4.00
|
%
|
|
4.00
|
%
|
|
—
|
|
|
—
|
|
Net Periodic Benefit Cost Assumptions:
|
|
|
|
|
|
|
|
||||
Discount rate
|
3.99
|
%
|
|
3.82
|
%
|
|
4.81
|
%
|
|
4.44
|
%
|
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, 2016 Using
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Asset Class:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Cash equivalents
|
$
|
3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3
|
|
Commingled funds:
|
|
|
|
|
|
|
|
||||||||
Fixed income
|
—
|
|
|
9
|
|
|
—
|
|
|
9
|
|
||||
U.S. equity
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||
International equity
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
|
|
||||||
Bond funds
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Blend funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Value funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Growth funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Guaranteed deposit account
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
||||
Total pension plan assets
|
$
|
13
|
|
|
$
|
25
|
|
|
$
|
6
|
|
|
$
|
44
|
|
|
Fair Value Measurements at
December 31, 2015 Using
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Asset Class:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Commingled funds:
|
|
|
|
|
|
|
|
||||||||
Fixed income
|
$
|
—
|
|
|
$
|
15
|
|
|
$
|
—
|
|
|
$
|
15
|
|
U.S. equity
|
—
|
|
|
16
|
|
|
—
|
|
|
16
|
|
||||
International equity
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
|
|
|
|||||
Bond funds
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
||||
Blend funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Value funds
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Growth funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Guaranteed deposit account
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
||||
Total pension plan assets
|
$
|
9
|
|
|
$
|
41
|
|
|
$
|
6
|
|
|
$
|
56
|
|
For the years ended December 31,
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||
|
(in millions)
|
||||||
2017
|
$
|
18
|
|
|
$
|
3
|
|
2018
|
$
|
9
|
|
|
$
|
3
|
|
2019
|
$
|
5
|
|
|
$
|
3
|
|
2020
|
$
|
5
|
|
|
$
|
3
|
|
2021
|
$
|
5
|
|
|
$
|
4
|
|
2022 - 2026
|
$
|
20
|
|
|
$
|
21
|
|
|
2014
|
||
|
(in millions)
|
||
Sales
(a)
|
$
|
2,706
|
|
Allocated costs for services provided by affiliates
|
$
|
126
|
|
Purchases
|
$
|
175
|
|
(a)
|
Amounts include related-party sales from our Elk Hills power plant of $89 million during 2014. These sales are included in other revenue in the statements of operations.
|
|
|
2016
|
|
2015
|
||||||||||||||||||||||||||||
Quarter
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||||||||||
|
|
(in millions, except per share amounts)
|
||||||||||||||||||||||||||||||
Revenues
(a)
|
|
$
|
322
|
|
|
$
|
317
|
|
|
$
|
456
|
|
|
$
|
452
|
|
|
$
|
577
|
|
|
$
|
634
|
|
|
$
|
626
|
|
|
$
|
566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Operating loss
|
|
$
|
(143
|
)
|
|
$
|
(141
|
)
|
|
$
|
(19
|
)
|
|
$
|
(3
|
)
|
|
$
|
(90
|
)
|
|
$
|
(31
|
)
|
|
$
|
(72
|
)
|
|
$
|
(4,949
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income (loss)
(b)(c)
|
|
$
|
(50
|
)
|
|
$
|
(140
|
)
|
|
$
|
546
|
|
|
$
|
(77
|
)
|
|
$
|
(100
|
)
|
|
$
|
(68
|
)
|
|
$
|
(104
|
)
|
|
$
|
(3,282
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Basic
(d)
|
|
$
|
(1.30
|
)
|
|
$
|
(3.51
|
)
|
|
$
|
13.04
|
|
|
$
|
(1.83
|
)
|
|
$
|
(2.62
|
)
|
|
$
|
(1.78
|
)
|
|
$
|
(2.72
|
)
|
|
$
|
(85.47
|
)
|
Diluted
(d)
|
|
$
|
(1.30
|
)
|
|
$
|
(3.51
|
)
|
|
$
|
13.04
|
|
|
$
|
(1.83
|
)
|
|
$
|
(2.62
|
)
|
|
$
|
(1.78
|
)
|
|
$
|
(2.72
|
)
|
|
$
|
(85.47
|
)
|
(a)
|
Revenues include net derivative gains (losses).
|
(b)
|
For the first quarter of 2016, amount included unusual and infrequent items consisting of
$81 million
of non-cash derivative losses on outstanding hedges,
$89 million
of net gains on early extinguishment of debt and
$21 million
of other non-recurring charges. The first quarter of 2016 also included a
$63 million
deferred tax valuation allowance. For the second quarter of 2016, amount included
$137 million
of non-cash derivative losses on outstanding hedges,
$44 million
of net gains on early extinguishment of debt,
$31 million
of gains from asset divestitures and
$6 million
of other non-recurring charges. For the third quarter of 2016, amount included
$660 million
of net gains on early extinguishment of debt,
$25 million
of non-cash derivative losses on outstanding hedges, a
$12 million
interest charge for the write-off of deferred debt issuance costs and
$6 million
of other non-recurring charges. For the fourth quarter of 2016, amount included
$40 million
of non-cash derivative losses on outstanding hedges,
$12 million
of net gains on early extinguishment of debt and
$26 million
of other non-recurring charges, net. There were no associated taxes for 2016.
|
(c)
|
For the first quarter of 2015, amount included after-tax unusual and infrequent items consisting of
$2 million
of non-cash derivative losses on outstanding hedges. For the second quarter of 2015, amount included after-tax items consisting of
$10 million
of derivative losses on outstanding hedges and
$6 million
in early retirement and severance costs. For the third quarter of 2015, amount included after-tax items consisting of
$36 million
of non-cash derivative gains on outstanding hedges, offset by
$42 million
in early retirement and severance costs. For the fourth quarter of 2015, amount included after-tax items consisting of $2.9 billion of asset impairments for proved and unproved properties, $42 million in write-down of certain other assets, $5 million in debt transaction costs and $3 million in rig termination and other costs, partially offset by $14 million in non-cash hedge-related gains and other. The fourth quarter of 2015 also included a $294 million deferred tax valuation allowance.
|
(d)
|
We changed our previously reported third quarter 2016 basic and diluted earnings per share from $13.45 to $13.04 and $13.06 to $13.04, respectively. These changes occurred because of the application of the two-class method of earnings allocation in a period with net income. Unlike other periods in the year, the third quarter of 2016 resulted in net income because of the non-recurring gain generated from the extinguishment of debt. This represents a 3% change from the previously reported basic earnings per share amount, which we believe is immaterial based on the absolute amount as well as the non-recurring nature of the third quarter gain, which did not affect any trends embedded in operating results.
|
|
San Joaquin Basin
|
|
Los Angeles Basin
(b)
|
|
Ventura Basin
|
|
Sacramento Basin
|
|
Total
|
|||||
|
(in MMBoe
(a)
)
|
|||||||||||||
PROVED DEVELOPED AND UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2013
|
511
|
|
|
158
|
|
|
55
|
|
|
20
|
|
|
744
|
|
Revisions of previous estimates
|
(48
|
)
|
|
8
|
|
|
(3
|
)
|
|
1
|
|
|
(42
|
)
|
Improved recovery
|
101
|
|
|
11
|
|
|
4
|
|
|
1
|
|
|
117
|
|
Extensions and discoveries
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Acquisitions
|
1
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
6
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(41
|
)
|
|
(11
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
(58
|
)
|
Balance at December 31, 2014
|
525
|
|
|
166
|
|
|
58
|
|
|
19
|
|
|
768
|
|
Revisions of previous estimates
|
(58
|
)
|
|
(34
|
)
|
|
(13
|
)
|
|
(3
|
)
|
|
(108
|
)
|
Improved recovery
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Extensions and discoveries
|
15
|
|
|
12
|
|
|
5
|
|
|
1
|
|
|
33
|
|
Acquisitions
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(40
|
)
|
|
(12
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
(58
|
)
|
Balance at December 31, 2015
|
451
|
|
|
132
|
|
|
47
|
|
|
14
|
|
|
644
|
|
Revisions of previous estimates
|
(5
|
)
|
|
(23
|
)
|
|
(18
|
)
|
|
(1
|
)
|
|
(47
|
)
|
Improved recovery
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Extensions and discoveries
|
16
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
20
|
|
Acquisitions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of proved reserves
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
Production
|
(36
|
)
|
|
(10
|
)
|
|
(3
|
)
|
|
(2
|
)
|
|
(51
|
)
|
Balance at December 31, 2016
|
429
|
|
|
99
|
|
|
29
|
|
|
11
|
|
|
568
|
|
|
|
|
|
|
|
|
|
|
|
|||||
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
349
|
|
|
110
|
|
|
35
|
|
|
20
|
|
|
514
|
|
December 31, 2014
|
367
|
|
|
126
|
|
|
41
|
|
|
18
|
|
|
552
|
|
December 31, 2015
|
326
|
|
|
105
|
|
|
36
|
|
|
14
|
|
|
481
|
|
December 31, 2016
(c)
|
287
|
|
|
83
|
|
|
25
|
|
|
11
|
|
|
406
|
|
|
|
|
|
|
|
|
|
|
|
|||||
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
162
|
|
|
48
|
|
|
20
|
|
|
—
|
|
|
230
|
|
December 31, 2014
|
158
|
|
|
40
|
|
|
17
|
|
|
1
|
|
|
216
|
|
December 31, 2015
|
125
|
|
|
27
|
|
|
11
|
|
|
—
|
|
|
163
|
|
December 31, 2016
|
142
|
|
|
16
|
|
|
4
|
|
|
—
|
|
|
162
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in
2016
, the average prices of Brent oil and NYMEX natural gas were
$45.04
per Bbl and
$2.42
per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately
19
to 1.
|
(b)
|
Includes proved reserves related to economic arrangements similar to PSCs of 85 MMBbl, 103 MMBbl, 116 MMBbl and 102 MMBbl at December 31,
2016
, 2015, 2014 and 2013, respectively.
|
(c)
|
Approximately
17%
of the proved developed reserves at December 31,
2016
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.
|
|
San Joaquin Basin
|
|
Los Angeles
Basin
(a)
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
|
(in millions of barrels (MMBbl))
|
|||||||||||||
PROVED DEVELOPED AND UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2013
|
332
|
|
|
155
|
|
|
45
|
|
|
—
|
|
|
532
|
|
Revisions of previous estimates
|
(41
|
)
|
|
8
|
|
|
(4
|
)
|
|
—
|
|
|
(37
|
)
|
Improved recovery
|
70
|
|
|
11
|
|
|
4
|
|
|
—
|
|
|
85
|
|
Extensions and discoveries
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Acquisitions
|
1
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
6
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(23
|
)
|
|
(11
|
)
|
|
(2
|
)
|
|
—
|
|
|
(36
|
)
|
Balance at December 31, 2014
|
340
|
|
|
163
|
|
|
48
|
|
|
—
|
|
|
551
|
|
Revisions of previous estimates
|
(35
|
)
|
|
(33
|
)
|
|
(12
|
)
|
|
—
|
|
|
(80
|
)
|
Improved recovery
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Extensions and discoveries
|
8
|
|
|
12
|
|
|
5
|
|
|
—
|
|
|
25
|
|
Acquisitions
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(23
|
)
|
|
(12
|
)
|
|
(2
|
)
|
|
—
|
|
|
(37
|
)
|
Balance at December 31, 2015
|
297
|
|
|
130
|
|
|
39
|
|
|
—
|
|
|
466
|
|
Revisions of previous estimates
|
(3
|
)
|
|
(22
|
)
|
|
(15
|
)
|
|
—
|
|
|
(40
|
)
|
Improved recovery
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Extensions and discoveries
|
11
|
|
|
1
|
|
|
2
|
|
|
—
|
|
|
14
|
|
Acquisitions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of proved reserves
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
Production
|
(21
|
)
|
|
(10
|
)
|
|
(2
|
)
|
|
—
|
|
|
(33
|
)
|
Balance at December 31, 2016
|
287
|
|
|
98
|
|
|
24
|
|
|
—
|
|
|
409
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
226
|
|
|
109
|
|
|
28
|
|
|
—
|
|
|
363
|
|
December 31, 2014
|
229
|
|
|
124
|
|
|
34
|
|
|
—
|
|
|
387
|
|
December 31, 2015
|
205
|
|
|
103
|
|
|
30
|
|
|
—
|
|
|
338
|
|
December 31, 2016
(b)
|
177
|
|
|
82
|
|
|
20
|
|
|
—
|
|
|
279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
106
|
|
|
46
|
|
|
17
|
|
|
—
|
|
|
169
|
|
December 31, 2014
|
111
|
|
|
39
|
|
|
14
|
|
|
—
|
|
|
164
|
|
December 31, 2015
|
92
|
|
|
27
|
|
|
9
|
|
|
—
|
|
|
128
|
|
December 31, 2016
|
110
|
|
|
16
|
|
|
4
|
|
|
—
|
|
|
130
|
|
(a)
|
Includes proved reserves related to economic arrangements similar to PSCs of 85 MMBbl, 103 MMBbl, 116 MMBbl and 102 MMBbl at December 31, 2016, 2015, 2014 and 2013, respectively.
|
(b)
|
Approximately
20%
of the proved developed reserves at December 31, 2016 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.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
|
(in MMBbl)
|
|||||||||||||
PROVED DEVELOPED AND UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2013
|
68
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
71
|
|
Revisions of previous estimates
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Improved recovery
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
Extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Acquisitions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(7
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
Balance at December 31, 2014
|
82
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
85
|
|
Revisions of previous estimates
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Acquisitions
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Balance at December 31, 2015
|
56
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
59
|
|
Revisions of previous estimates
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
Improved recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Extensions and discoveries
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Acquisitions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Balance at December 31, 2016
|
53
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
47
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
48
|
|
December 31, 2014
|
62
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
64
|
|
December 31, 2015
|
45
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
47
|
|
December 31, 2016
(a)
|
42
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|||||
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2013
|
21
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
23
|
|
December 31, 2014
|
20
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
21
|
|
December 31, 2015
|
11
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
12
|
|
December 31, 2016
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11
|
|
(a)
|
Approximately
11%
of the proved developed reserves at December 31, 2016 are non-producing.
|
(a)
|
Approximately
14%
of the proved developed reserves at December 31, 2016 are non-producing.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
15,673
|
|
|
$
|
2,055
|
|
|
$
|
1,299
|
|
|
$
|
298
|
|
|
$
|
19,325
|
|
Unproved properties
|
544
|
|
|
106
|
|
|
172
|
|
|
289
|
|
|
1,111
|
|
|||||
Total capitalized costs
(a)
|
16,217
|
|
|
2,161
|
|
|
1,471
|
|
|
587
|
|
|
20,436
|
|
|||||
Accumulated depreciation, depletion and amortization
(b)
|
(11,671
|
)
|
|
(1,495
|
)
|
|
(1,168
|
)
|
|
(557
|
)
|
|
(14,891
|
)
|
|||||
Net capitalized costs
|
$
|
4,546
|
|
|
$
|
666
|
|
|
$
|
303
|
|
|
$
|
30
|
|
|
$
|
5,545
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
15,549
|
|
|
$
|
2,071
|
|
|
$
|
1,352
|
|
|
$
|
374
|
|
|
$
|
19,346
|
|
Unproved properties
|
544
|
|
|
106
|
|
|
172
|
|
|
289
|
|
|
1,111
|
|
|||||
Total capitalized costs
(a)
|
16,093
|
|
|
2,177
|
|
|
1,524
|
|
|
663
|
|
|
20,457
|
|
|||||
Accumulated depreciation, depletion and amortization
(b)
|
(11,166
|
)
|
|
(1,491
|
)
|
|
(1,208
|
)
|
|
(603
|
)
|
|
(14,468
|
)
|
|||||
Net capitalized costs
|
$
|
4,927
|
|
|
$
|
686
|
|
|
$
|
316
|
|
|
$
|
60
|
|
|
$
|
5,989
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
December 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
15,362
|
|
|
$
|
1,982
|
|
|
$
|
1,353
|
|
|
$
|
326
|
|
|
$
|
19,023
|
|
Unproved properties
|
469
|
|
|
106
|
|
|
113
|
|
|
323
|
|
|
1,011
|
|
|||||
Total capitalized costs
(a)
|
15,831
|
|
|
2,088
|
|
|
1,466
|
|
|
649
|
|
|
20,034
|
|
|||||
Accumulated depreciation, depletion and amortization
(b)
|
(6,846
|
)
|
|
(826
|
)
|
|
(495
|
)
|
|
(497
|
)
|
|
(8,664
|
)
|
|||||
Net capitalized costs
|
$
|
8,985
|
|
|
$
|
1,262
|
|
|
$
|
971
|
|
|
$
|
152
|
|
|
$
|
11,370
|
|
(a)
|
Includes acquisition costs, development costs and asset retirement obligations.
|
(b)
|
Includes accumulated valuation allowance for total unproved properties of $819 million, $819 million, and $715 million at December 31,
2016
, 2015 and 2014, respectively.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Proved properties
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Unproved properties
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Exploration costs
|
17
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
21
|
|
|||||
Development costs
(a)
|
49
|
|
|
23
|
|
|
26
|
|
|
4
|
|
|
102
|
|
|||||
Costs incurred
|
$
|
66
|
|
|
$
|
23
|
|
|
$
|
28
|
|
|
$
|
6
|
|
|
$
|
123
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
73
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
77
|
|
Unproved properties
|
65
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
65
|
|
|||||
Exploration costs
|
36
|
|
|
—
|
|
|
4
|
|
|
3
|
|
|
43
|
|
|||||
Development costs
(a)
|
191
|
|
|
89
|
|
|
10
|
|
|
—
|
|
|
290
|
|
|||||
Costs incurred
|
$
|
365
|
|
|
$
|
91
|
|
|
$
|
16
|
|
|
$
|
3
|
|
|
$
|
475
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
79
|
|
|
$
|
3
|
|
|
$
|
128
|
|
|
$
|
—
|
|
|
$
|
210
|
|
Unproved properties
|
21
|
|
|
—
|
|
|
81
|
|
|
—
|
|
|
102
|
|
|||||
Exploration costs
|
105
|
|
|
—
|
|
|
14
|
|
|
5
|
|
|
124
|
|
|||||
Development costs
|
1,356
|
|
|
495
|
|
|
99
|
|
|
12
|
|
|
1,962
|
|
|||||
Costs incurred
|
$
|
1,561
|
|
|
$
|
498
|
|
|
$
|
322
|
|
|
$
|
17
|
|
|
$
|
2,398
|
|
(a)
|
Total development costs include a $49 million increase, a $62 million decrease and a $13 million decrease in asset retirement obligations in 2016, 2015 and 2014, respectively.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
(a)
|
$
|
1,151
|
|
|
$
|
425
|
|
|
$
|
89
|
|
|
$
|
35
|
|
|
$
|
1,700
|
|
Production costs
(b)
|
469
|
|
|
241
|
|
|
70
|
|
|
20
|
|
|
800
|
|
|||||
General and administrative expenses
(c)
|
14
|
|
|
18
|
|
|
4
|
|
|
1
|
|
|
37
|
|
|||||
Other operating expenses
(d)
|
18
|
|
|
13
|
|
|
3
|
|
|
—
|
|
|
34
|
|
|||||
Depreciation, depletion and amortization
|
462
|
|
|
48
|
|
|
16
|
|
|
1
|
|
|
527
|
|
|||||
Taxes other than on income
|
69
|
|
|
38
|
|
|
8
|
|
|
6
|
|
|
121
|
|
|||||
Exploration expenses
|
19
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
23
|
|
|||||
Pretax income (loss)
|
100
|
|
|
67
|
|
|
(14
|
)
|
|
5
|
|
|
158
|
|
|||||
Income tax (expense) benefit
(g)
|
(41
|
)
|
|
(27
|
)
|
|
6
|
|
|
(2
|
)
|
|
(64
|
)
|
|||||
Results of operations
|
$
|
59
|
|
|
$
|
40
|
|
|
$
|
(8
|
)
|
|
$
|
3
|
|
|
$
|
94
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
(a)
|
$
|
1,484
|
|
|
$
|
569
|
|
|
$
|
123
|
|
|
$
|
46
|
|
|
$
|
2,222
|
|
Production costs
(b)
|
564
|
|
|
278
|
|
|
85
|
|
|
24
|
|
|
951
|
|
|||||
General and administrative expenses
(c)
|
28
|
|
|
21
|
|
|
7
|
|
|
2
|
|
|
58
|
|
|||||
Other operating expenses
(d)
|
15
|
|
|
2
|
|
|
2
|
|
|
2
|
|
|
21
|
|
|||||
Depreciation, depletion and amortization
|
808
|
|
|
100
|
|
|
48
|
|
|
20
|
|
|
976
|
|
|||||
Taxes other than on income
|
97
|
|
|
45
|
|
|
13
|
|
|
1
|
|
|
156
|
|
|||||
Asset impairments
(e)
|
3,554
|
|
|
571
|
|
|
613
|
|
|
114
|
|
|
4,852
|
|
|||||
Exploration expenses
|
30
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|
36
|
|
|||||
Pretax loss
|
(3,612
|
)
|
|
(448
|
)
|
|
(648
|
)
|
|
(120
|
)
|
|
(4,828
|
)
|
|||||
Income tax benefit
(g)
|
1,472
|
|
|
183
|
|
|
264
|
|
|
49
|
|
|
1,968
|
|
|||||
Results of operations
|
$
|
(2,140
|
)
|
|
$
|
(265
|
)
|
|
$
|
(384
|
)
|
|
$
|
(71
|
)
|
|
$
|
(2,860
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
(a)
|
$
|
2,735
|
|
|
$
|
956
|
|
|
$
|
244
|
|
|
$
|
88
|
|
|
$
|
4,023
|
|
Production costs
(b)
|
596
|
|
|
342
|
|
|
92
|
|
|
27
|
|
|
1,057
|
|
|||||
General and administrative expenses
(c)
|
37
|
|
|
31
|
|
|
9
|
|
|
8
|
|
|
85
|
|
|||||
Other operating expenses
(d)
|
21
|
|
|
2
|
|
|
3
|
|
|
4
|
|
|
30
|
|
|||||
Depreciation, depletion and amortization
|
875
|
|
|
148
|
|
|
79
|
|
|
81
|
|
|
1,183
|
|
|||||
Taxes other than on income
|
140
|
|
|
49
|
|
|
8
|
|
|
6
|
|
|
203
|
|
|||||
Asset impairments
(e)
|
1,266
|
|
|
1,110
|
|
|
437
|
|
|
589
|
|
|
3,402
|
|
|||||
Exploration expenses
(f)
|
104
|
|
|
—
|
|
|
9
|
|
|
5
|
|
|
118
|
|
|||||
Pretax loss
|
(304
|
)
|
|
(726
|
)
|
|
(393
|
)
|
|
(632
|
)
|
|
(2,055
|
)
|
|||||
Income tax benefit
(g)
|
124
|
|
|
296
|
|
|
161
|
|
|
258
|
|
|
839
|
|
|||||
Results of operations
|
$
|
(180
|
)
|
|
$
|
(430
|
)
|
|
$
|
(232
|
)
|
|
$
|
(374
|
)
|
|
$
|
(1,216
|
)
|
(a)
|
Revenues are net of royalty payments.
|
(b)
|
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, but do not include DD&A, royalties, income taxes and general and administrative expenses.
|
(c)
|
For 2016, the amount excludes unusual and infrequent charges related to severance and early retirement costs associated with field personnel totaling $6 million. For 2015, the amount excludes charges of $18 million related to early retirement and severance costs. For 2014, the amount excludes charges of $6 million related to Spin-off and transition-related costs.
|
(d)
|
For 2016, the amount excludes net unusual and infrequent gains of $18 million that include refunds, partially offset by plant turnaround charges and other items. For 2015, the amount excludes charges related to the write-down of certain assets and rig termination charges of $82 million. For 2014, the amount excludes charges related to rig termination charges and Spin-off and transition-related costs of $55 million.
|
(e)
|
At year end 2015 and 2014, we recorded pre-tax asset impairment charges of $4.9 billion and $3.4 billion, respectively, on certain proved and unproved properties in the San Joaquin, Los Angeles, Ventura and Sacramento basins.
|
(f)
|
Excludes $21 million of unusual and infrequent costs related to dry holes and seismic charges.
|
(g)
|
Income taxes are calculated on the basis of a stand-alone tax filing entity.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenue from each barrel of oil equivalent
($/Boe)
(a)(b)
|
$
|
32.43
|
|
|
$
|
39.24
|
|
|
$
|
32.58
|
|
|
$
|
16.00
|
|
|
$
|
33.17
|
|
Production costs
|
13.21
|
|
|
22.25
|
|
|
25.62
|
|
|
9.14
|
|
|
15.61
|
|
|||||
General and administrative expenses
(c)
|
0.39
|
|
|
1.66
|
|
|
1.46
|
|
|
0.46
|
|
|
0.72
|
|
|||||
Other operating expenses
(d)
|
0.51
|
|
|
1.20
|
|
|
1.10
|
|
|
—
|
|
|
0.67
|
|
|||||
Depreciation, depletion and amortization
|
13.02
|
|
|
4.43
|
|
|
5.86
|
|
|
0.46
|
|
|
10.28
|
|
|||||
Taxes other than on income
|
1.94
|
|
|
3.51
|
|
|
2.93
|
|
|
2.74
|
|
|
2.36
|
|
|||||
Exploration expenses
|
0.54
|
|
|
—
|
|
|
0.73
|
|
|
0.91
|
|
|
0.45
|
|
|||||
Pretax income (loss)
|
2.82
|
|
|
6.19
|
|
|
(5.12
|
)
|
|
2.29
|
|
|
3.08
|
|
|||||
Income tax (expense) benefit
(f)
|
(1.16
|
)
|
|
(2.49
|
)
|
|
2.20
|
|
|
(0.91
|
)
|
|
(1.25
|
)
|
|||||
Results of operations
|
$
|
1.66
|
|
|
$
|
3.70
|
|
|
$
|
(2.92
|
)
|
|
$
|
1.38
|
|
|
$
|
1.83
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenue from each barrel of oil equivalent
($/Boe)
(a)(b)
|
$
|
37.04
|
|
|
$
|
46.69
|
|
|
$
|
36.10
|
|
|
$
|
17.07
|
|
|
$
|
38.07
|
|
Production costs
|
14.08
|
|
|
22.81
|
|
|
24.95
|
|
|
8.91
|
|
|
16.30
|
|
|||||
General and administrative expenses
(c)
|
0.70
|
|
|
1.72
|
|
|
2.05
|
|
|
0.74
|
|
|
1.00
|
|
|||||
Other operating expenses
(d)
|
0.37
|
|
|
0.16
|
|
|
0.59
|
|
|
0.74
|
|
|
0.36
|
|
|||||
Depreciation, depletion and amortization
|
20.16
|
|
|
8.21
|
|
|
14.09
|
|
|
7.42
|
|
|
16.72
|
|
|||||
Taxes other than on income
|
2.42
|
|
|
3.69
|
|
|
3.82
|
|
|
0.37
|
|
|
2.67
|
|
|||||
Asset impairments
(e)
|
88.69
|
|
|
46.85
|
|
|
179.92
|
|
|
42.30
|
|
|
83.14
|
|
|||||
Exploration expenses
|
0.75
|
|
|
—
|
|
|
0.88
|
|
|
1.11
|
|
|
0.62
|
|
|||||
Pretax loss
|
(90.13
|
)
|
|
(36.75
|
)
|
|
(190.20
|
)
|
|
(44.52
|
)
|
|
(82.74
|
)
|
|||||
Income tax benefit
(f)
|
36.74
|
|
|
15.02
|
|
|
77.49
|
|
|
18.18
|
|
|
33.72
|
|
|||||
Results of operations
|
$
|
(53.39
|
)
|
|
$
|
(21.73
|
)
|
|
$
|
(112.71
|
)
|
|
$
|
(26.34
|
)
|
|
$
|
(49.02
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenue from each barrel of oil equivalent
($/Boe)
(a)(b)
|
$
|
67.32
|
|
|
$
|
88.96
|
|
|
$
|
75.73
|
|
|
$
|
26.11
|
|
|
$
|
69.40
|
|
Production costs
|
14.66
|
|
|
31.82
|
|
|
28.68
|
|
|
7.92
|
|
|
18.23
|
|
|||||
General and administrative expenses
(c)
|
0.91
|
|
|
2.88
|
|
|
2.79
|
|
|
2.37
|
|
|
1.47
|
|
|||||
Other operating expenses
(d)
|
0.52
|
|
|
0.19
|
|
|
0.93
|
|
|
1.19
|
|
|
0.55
|
|
|||||
Depreciation, depletion and amortization
|
21.52
|
|
|
13.77
|
|
|
24.52
|
|
|
24.04
|
|
|
20.40
|
|
|||||
Taxes other than on income
|
3.44
|
|
|
4.56
|
|
|
2.48
|
|
|
1.78
|
|
|
3.50
|
|
|||||
Asset impairments
(e)
|
31.14
|
|
|
103.29
|
|
|
135.63
|
|
|
174.78
|
|
|
58.66
|
|
|||||
Exploration expenses
|
2.56
|
|
|
—
|
|
|
2.79
|
|
|
1.48
|
|
|
2.03
|
|
|||||
Pretax loss
|
(7.43
|
)
|
|
(67.55
|
)
|
|
(122.09
|
)
|
|
(187.45
|
)
|
|
(35.44
|
)
|
|||||
Income tax benefit
(f)
|
3.05
|
|
|
27.55
|
|
|
49.97
|
|
|
76.85
|
|
|
14.47
|
|
|||||
Results of operations
|
$
|
(4.38
|
)
|
|
$
|
(40.00
|
)
|
|
$
|
(72.12
|
)
|
|
$
|
(110.60
|
)
|
|
$
|
(20.97
|
)
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one Bbl of oil.
|
(b)
|
Revenues are net of royalty payments.
|
(c)
|
For 2016, the amount excludes unusual and infrequent charges related to severance and early retirement costs associated with field personnel totaling $0.12 per Boe. For 2015, the amount excludes charges of $0.31 per Boe related to early retirement and severance costs. For 2014, the amount excludes charges of $0.10 per Boe related to Spin-off and transition-related costs.
|
(d)
|
For 2016, the amount excludes net unusual and infrequent gains of $0.35 per Boe that include refunds partially offset by plant turnaround charges and other items. For 2015, the amount excludes charges related to the write-down of certain assets and rig termination charges of totaling $1.42 per Boe. For 2014, the amount excludes charges related to rig termination charges and Spin-off and transition-related costs totaling $0.97 per Boe.
|
(e)
|
At year end 2015 and 2014, we recorded pre-tax asset impairment charges of $4.9 billion and $3.4 billion, respectively, on certain proved and unproved properties in the San Joaquin, Los Angeles, Ventura and Sacramento basins.
|
(f)
|
Income taxes are calculated on the basis of a stand-alone tax filing entity.
|
(a)
|
Includes general and administrative expenses and taxes other than on income.
|
(b)
|
Includes asset retirement costs.
|
|
For the years ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Beginning of year
|
$
|
4,024
|
|
|
$
|
10,828
|
|
|
$
|
9,223
|
|
Sales and transfers of oil and natural gas produced, net of production costs and other operating expenses
|
(742
|
)
|
|
(1,038
|
)
|
|
(2,658
|
)
|
|||
Net change in prices received per Bbl, production costs and other operating expenses
|
(2,297
|
)
|
|
(12,362
|
)
|
|
567
|
|
|||
Extensions, discoveries and improved recovery, net of future production and development costs
|
117
|
|
|
292
|
|
|
2,593
|
|
|||
Change in estimated future development costs
|
89
|
|
|
792
|
|
|
75
|
|
|||
Revisions of quantity estimates
(a)
|
(247
|
)
|
|
(872
|
)
|
|
(925
|
)
|
|||
Previously estimated development costs incurred during the period
|
62
|
|
|
394
|
|
|
1,440
|
|
|||
Accretion of discount
|
458
|
|
|
1,474
|
|
|
1,324
|
|
|||
Net change in income taxes
|
854
|
|
|
4,228
|
|
|
(468
|
)
|
|||
Purchases and sales of reserves in place, net
|
(4
|
)
|
|
45
|
|
|
125
|
|
|||
Changes in production rates and other
|
353
|
|
|
243
|
|
|
(468
|
)
|
|||
Net change
|
(1,357
|
)
|
|
(6,804
|
)
|
|
1,605
|
|
|||
End of year
|
$
|
2,667
|
|
|
$
|
4,024
|
|
|
$
|
10,828
|
|
(a)
|
Includes revisions related to performance and price changes.
|
|
2016
|
|
2015
|
|
2014
|
|||
Oil (MBbl/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
57
|
|
|
64
|
|
|
64
|
|
Los Angeles Basin
(c)
|
29
|
|
|
34
|
|
|
29
|
|
Ventura Basin
|
5
|
|
|
6
|
|
|
6
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
91
|
|
|
104
|
|
|
99
|
|
|
|
|
|
|
|
|||
NGLs (MBbl/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
15
|
|
|
17
|
|
|
18
|
|
Los Angeles Basin
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin
|
1
|
|
|
1
|
|
|
1
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
16
|
|
|
18
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
150
|
|
|
172
|
|
|
180
|
|
Los Angeles Basin
(c)
|
3
|
|
|
2
|
|
|
1
|
|
Ventura Basin
|
8
|
|
|
11
|
|
|
11
|
|
Sacramento Basin
|
36
|
|
|
44
|
|
|
54
|
|
Total
|
197
|
|
|
229
|
|
|
246
|
|
|
|
|
|
|
|
|||
Total Production (MBoe/d)
(a)
|
140
|
|
|
160
|
|
|
159
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one Bbl of oil.
|
(b)
|
Includes daily production from Elk Hills field of
21
MBbl oil,
13
MBbl NGLs and
106
MMcf natural gas in 2016; 24 MBbl oil, 15 MBbl NGLs and 123 MMcf natural gas in 2015; and 25 MBbl oil, 16 MBbl NGLs and 136 MMcf natural gas in 2014.
|
(c)
|
Includes daily production from Wilmington field of
25
MBbl oil in 2016; 28 MBbl oil and 1 MMcf natural gas in 2015; and 25 MBbl oil in 2014.
|
|
Balance at Beginning of Period
|
|
Charged (Credited) to Costs and Expenses
|
|
Charged to Other Accounts
|
|
Deductions
(a)
|
|
Balance at End of Period
|
||||||||||
2016
|
|
|
|
|
|
|
|
|
|
||||||||||
Deferred tax valuation allowance
|
$
|
382
|
|
|
$
|
398
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
780
|
|
Other asset valuation allowance
|
$
|
68
|
|
|
$
|
(12
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
56
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Environmental reserves
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Deferred tax valuation allowance
(b)
|
$
|
—
|
|
|
$
|
294
|
|
|
$
|
88
|
|
|
$
|
—
|
|
|
$
|
382
|
|
Other asset valuation allowance
|
$
|
10
|
|
|
$
|
58
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Environmental reserves
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Other asset valuation allowance
|
$
|
—
|
|
|
$
|
10
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Environmental reserves
|
$
|
8
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
8
|
|
(a)
|
Consists of payments.
|
(b)
|
Our 2015 deferred tax liabilities were net of $88 million, which represented the federal benefit for the state-related portion of the deferred tax valuation allowance.
|
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 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
|
|
Separation and Distribution Agreement between Occidental Petroleum Corporation and California Resources Corporation (filed as Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
|
|
|
|
3.1
|
|
Amended and Restated Certificate of Incorporation of California Resources Corporation (filed as Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed June 3, 2016 and incorporated herein by reference).
|
|
|
|
3.2
|
|
Amended and Restated Bylaws of California Resources Corporation (filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed November 10, 2015 and incorporated herein by reference).
|
|
|
|
4.1
|
|
Indenture, dated October 1, 2014, by and among California Resources Corporation, the Guarantors and Wells Fargo Bank, National Association (filed as Exhibit 4.2 to Amendment No. 4 to the Registrant’s Information Statement on Form 10 filed October 8, 2014 and incorporated herein by reference).
|
|
|
|
4.2
|
|
Indenture, dated December 15, 2015, by and among California Resources Corporation, the Guarantors and the Bank of New York Mellon Trust Company, N.A. (filed as Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed December 18, 2015 and incorporated herein by reference).
|
|
|
|
4.3
|
|
Guarantor Supplemental Indenture dated as of March 5, 2015, among California Resources Corporation, CRC Construction Services, LLC, certain other guarantors and Wells Fargo Bank, National Association (filed as Exhibit 4.2 to Registrant’s Registration Statement on Form S-4 filed March 12, 2015 and incorporated herein by reference).
|
|
|
|
4.4
|
|
Guarantor Supplemental Indenture dated as of March 4, 2016, among California Resources Corporation, California Resources Coles Levee, LLC, certain other guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q filed August 4, 2016 and incorporated herein by reference).
|
|
|
|
4.5
|
|
Guarantor Supplement Indenture dated as of March 4, 2016, among California Resources Corporation, California Resources Coles Levee, L.P., certain other guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee (filed as Exhibit 4.2 to Registrant’s Quarterly Report on Form 10-Q filed August 4, 2016 and incorporated herein by reference).
|
|
|
|
4.6
|
|
Guarantor Supplemental Indenture No. 2, dated as of April 29, 2016, among California Resources Corporation, California Resources Coles Levee, L.P. and California Resources Coles Levee, LLC, certain other guarantors and Wilmington Trust, National Association, as trustee (filed as Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q filed August 4, 2016 and incorporated herein by reference).
|
|
|
|
4.7
|
|
Assumption Agreement dated as of March 6, 2015, among CRC Construction Services, LLC and JP Morgan Chase Bank, N.A., as Administrative Agent for lenders (filed as Exhibit 10.31 to Registrant’s Registration Statement on Form S-4 filed March 12, 2015 and incorporated herein by reference).
|
|
|
|
4.8
|
|
Registration Rights Agreement, dated October 1, 2014, by and among California Resources Corporation, the Guarantors and the Initial Purchasers (filed as Exhibit 4.3 to Amendment No. 4 to the Registrant’s Information Statement on Form 10 filed October 8, 2014 and incorporated herein by reference).
|
|
|
|
4.9
|
|
Form of 5% Senior Note due 2020 (included in Exhibit 4.2).
|
|
|
|
4.10
|
|
Form of 5½% Senior Note due 2021 (included in Exhibit 4.2).
|
|
|
|
4.11
|
|
Form of 6% Senior Note due 2024 (included in Exhibit 4.2).
|
|
|
|
4.12
|
|
Form of 8% Senior Secured Second Lien Note due 2022 (included in Exhibit 4.1).
|
|
|
|
10.1
|
|
Credit Agreement, dated as of September 24, 2014, among California Resources Corporation, the Lenders and JPMorgan Chase Bank, N.A. as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A. as Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as Exhibit 10.25 to Amendment No. 5 to the Company's Registration Statement on Form 10 filed October 14, 2014, and incorporated herein by reference).
|
|
|
|
10.2
|
|
First Amendment to Credit Agreement, dated as of February 25, 2015, among California Resources Corporation, the Lenders and JPMorgan Chase Bank, N.A. as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A. as Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as Exhibit 10.35 to the Registrant’s Annual Report on Form 10-K filed February 27, 2015, and incorporated herein by reference).
|
|
|
|
10.3
|
|
Second Amendment to Credit Agreement, dated November 2, 2015, among California Resources Corporation, the Lenders and JPMorgan Chase Bank, N.A. as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A. as Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q filed November 6, 2015, and incorporated herein by reference).
|
|
|
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10.4
|
|
Third Amendment to Credit Agreement, dated February 23, 2016, among California Resources Corporation and JP Morgan Chase Bank, N.A., as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A. as Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as Exhibit 99.1to the Registrant's Current Report on Form 8-K filed February 23, 2016, and incorporated herein by reference).
|
|
|
|
10.5
|
|
Fourth Amendment to Credit Agreement dated as of April 22, 2016, among California Resources Corporation, as the Borrower and JP Morgan Chase Bank, N.A., as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A., as Syndication Agent, Swingline Lender and a Letter of Credit Issuer (filed as Exhibit 99.1 to the Registrant’s Current Report on Form 8-K filed April 22, 2016, and incorporated herein by reference).
|
|
|
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10.6
|
|
Fifth Amendment to Credit Agreement, dated August 12, 2016, among California Resources Corporation, as the Borrower and JP Morgan Chase Bank, N.A., as Administrative Agent, a Swingline Lender and a Letter of Credit Issuer and Bank of America, N.A., as Syndication Agent, a Swingline Lender and a Letter of Credit Issuer (filed as Exhibit 10.2 to the Registration’s Current Report on Form 8-K filed August 17, 2016 and incorporated herein by reference).
|
|
|
|
10.7
|
|
Credit Agreement, dated August 12, 2016, among California Resources Corporation, as the Borrower, the several Lenders from time to time parties thereto, Goldman Sachs Bank USA, as Lead Arranger and Bookrunner, and The Bank of New York Mellon Trust Company, N.A., as Administrative Agent and Collateral Agent (filed as Exhibit 10.1 to the Registration’s Current Report on Form 8-K filed August 17, 2016 and incorporated herein by reference).
|
|
|
|
10.8
|
|
Omnibus Amendment, dated September 12 2016, among California Resources Corporation, the Guarantors party thereto, the Collateral Trustee and the other party lien representatives party thereto (filed as Exhibit 10.3 to the Registration’s Quarterly Report on Form 10-Q filed November 3, 2016 and incorporated herein by reference).
|
|
|
|
10.9
|
|
Intercreditor Agreement, dated December 15, 2015 between JP Morgan Chase Bank, N.A., as Priority Lien Agent and The Bank of New York Mellon Trust Company, N.A., as Second Lien Collateral Agent for the Second Lien Secured Parties (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q filed November 3, 2016 and incorporated herein by reference).
|
|
|
|
10.10
|
|
Transition Services Agreement between Occidental Petroleum Corporation and California Resources Corporation (filed as Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
|
|
|
|
10.11
|
|
Tax Sharing Agreement between Occidental Petroleum Corporation and California Resources Corporation (filed as Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
|
|
|
|
10.12
|
|
Employee Matters Agreement between Occidental Petroleum Corporation and California Resources Corporation (filed as Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
|
|
|
|
10.13
|
|
Intellectual Property License Agreement between Occidental Petroleum Corporation and California Resources Corporation (filed as Exhibit 10.7 to Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
|
|
|
|
10.14
|
|
Area of Mutual Interest Agreement between Occidental Petroleum Corporation and California Resources Corporation (filed as Exhibit 10.5 to Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
|
|
|
|
10.15
|
|
Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated November 5, 1991, by and among the State of California, by and through the State Lands Commission, the City of Long Beach, Atlantic Richfield Company and ARCO Long Beach, Inc. (filed as Exhibit 10.10 to Amendment No. 2 to the Company's Registration Statement on Form 10 filed August 20, 2014, and incorporated herein by reference).
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|
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10.16
|
|
Amendment to the Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated January 16, 2009, by and among the State of California, by and through the State Lands Commission, the City of Long Beach, and Oxy Long Beach, Inc. (filed as Exhibit 10.11 to Amendment No. 2 to the Company's Registration Statement on Form 10 filed August 20, 2014, and incorporated herein by reference).
|
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|
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10.17
|
|
Contractors' Agreement, by and between the City of Long Beach, Humble Oil & Refining Company, Shell Oil Company, Socony Mobil Oil Company, Inc., Texaco, Inc., Union Oil Company of California, Pauley Petroleum, Inc., Allied Chemical Corporation, Richfield Oil Corporation and Standard Oil Company of California (filed as Exhibit 10.12 to Amendment No. 2 to the Company's Registration Statement on Form 10 filed August 20, 2014, and incorporated herein by reference).
|
|
|
|
10.18
|
|
Confidentiality and Trade Secret Protection Agreement by and between Occidental Petroleum Corporation and California Resources Corporation, dated November 24, 2014 (filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed on December 1, 2014, and incorporated herein by reference).
|
|
|
|
|
|
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.
|
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|
|
10.19
|
|
California Resources Corporation Long-Term Incentive Plan Restricted Stock Unit Award Terms and Conditions (filed as Exhibit 10.3 to the Registrant’s Quarterly Report Form 10-Q filed November 6, 2015, and incorporated herein by reference).
|
10.20
|
|
California Resources Corporation Long-Term Incentive Plan, 2016 Annual Incentive Award Summary (filed as Exhibit 10.5 on Registrant’s Quarterly Report on Form 10-Q filed August 4, 2016 and incorporated herein by reference).
|
|
|
|
10.21
|
|
California Resources Corporation Long-Term Incentive Plan Performance Stock Unit Award Terms and Conditions (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q filed November 6, 2015, and incorporated herein by reference).
|
|
|
|
10.22
|
|
California Resources Corporation Long-Term Incentive Plan Nonstatutory Stock Option Award Terms and Conditions (filed as Exhibit 10.4 to the Registrant’s Quarterly Report Form 10-Q filed November 6, 2015, and incorporated herein by reference).
|
|
|
|
10.23
|
|
California Resources Corporation Supplemental Savings Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 2, 2014, and incorporated herein by reference).
|
|
|
|
10.24
|
|
First Amendment to California Resources Corporation Supplemental Savings Plan (filed as Exhibit 10.18 to the Registrant's Annual Report on Form 10–K filed February 29, 2016, and incorporated herein by reference).
|
|
|
|
10.25
|
|
California Resources Corporation Supplemental Retirement Plan II (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on December 2, 2014, and incorporated herein by reference).
|
|
|
|
10.26
|
|
California Resources Corporation Deferred Compensation Plan (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 2, 2014, and incorporated herein by reference).
|
|
|
|
10.27
|
|
California Resources Corporation Long-Term Incentive Plan (filed as Exhibit 4.3 to the Registrant’s related Registration Statement on Form S-8 filed November 26, 2014 and incorporated herein by reference).
|
|
|
|
10.28
|
|
Acknowledgment of Amendment to Long-Term Incentive Award Terms and Conditions with William E. Albrecht (filed as Exhibit 10.22 to the Registrant's Annual Report on Form 10–K filed February 29, 2016, and incorporated herein by reference).
|
|
|
|
10.29
|
|
Form of Nonstatutory Stock Option Award Terms and Conditions (filed as Exhibit 10.6 to Amendment No. 3 to the Registrant’s Information Statement on Form 10 filed September 22, 2014 and incorporated herein by reference).
|
|
|
|
10.30
|
|
Form of California Resources Corporation Long-Term Incentive Plan Restricted Stock Unit Award Terms and Conditions (filed as Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q filed August 4, 2016 and incorporated herein by reference).
|
|
|
|
10.31
|
|
Form of 2016 Nonstatutory Stock Option Award Terms and Conditions (filed as Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q filed November 3, 2016, and incorporated herein by reference).
|
|
|
|
10.32
|
|
Form of Performance Incentive Award Terms and Conditions (filed as Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q filed November 3, 2016, and incorporated herein by reference).
|
|
|
|
10.33
|
|
Form of Restricted Stock Incentive Award Terms and Conditions (Not Performance-Based) (filed as Exhibit 10.8 to Amendment No. 3 to the Registrant’s Information Statement on Form 10 filed September 22, 2014 and incorporated herein by reference).
|
|
|
|
10.34
|
|
Form of Restricted Stock Incentive Award Terms and Conditions (Performance-Based) (filed as Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed February 10, 2015, and incorporated herein by reference).
|
|
|
|
10.35
|
|
Form of Restricted Stock Unit Award for Non-Employee Directors Grant Agreement (filed as Exhibit 10.9 to Amendment No. 3 to the Registrant’s Information Statement on Form 10 filed September 22, 2014 and incorporated herein by reference).
|
|
|
|
10.36
|
|
Form of Long-Term Incentive Award Terms and Conditions (Cash-based, Equity, and Cash-settled Award) (filed as Exhibit 10.10 to Amendment No. 3 to the Registrant’s Information Statement on Form 10 filed September 22, 2014 and incorporated herein by reference).
|
|
|
|
10.37
|
|
Form of Restricted Stock Incentive Award Terms and Conditions (Replacement Award-Performance-Based) (filed as Exhibit 10.11 to Amendment No. 3 to the Registrant’s Information Statement on Form 10 filed September 22, 2014 and incorporated herein by reference).
|
|
|
|
10.38
|
|
Form of Restricted Stock Incentive Award Terms and Conditions (Replacement Award-Not Performance-Based) (filed as Exhibit 10.12 to Amendment No. 3 to the Registrant’s Information Statement on Form 10 filed September 22, 2014 and incorporated herein by reference).
|
|
|
|
10.39
|
|
Form of Phantom Share Unit Award Terms and Conditions (Replacement Award) (filed as Exhibit 10.13 to Amendment No. 3 to the Registrant’s Information Statement on Form 10 filed September 22, 2014 and incorporated herein by reference).
|
|
|
|
10.40
|
|
California Resources Corporation 2014 Employee Stock Purchase Plan (filed as Exhibit 4.3 to the Registrant’s related Registration Statement on Form S-8 filed November 26, 2014 and incorporated herein by reference).
|
|
|
|
10.41
|
|
Form of Indemnification Agreements (filed as Exhibit 10.14 to Amendment No. 3 Registrant’s Information Statement on Form 10 filed September 22, 2014 and incorporated herein by reference).
|
|
|
|
10.42
|
|
First Amendment to the California Resources Corporation 2014 Employee Stock Purchase Plan effective May 4, 2016 (filed as Annex C-1 to the Registrant’s Definitive Proxy Statement on Schedule 14A filed March 23, 2016 and incorporated herein by reference).
|
|
|
|
10.43
|
|
Form of Retention Letter Assignment and Assumption Agreement (filed as Exhibit 10.20 to Amendment No. 3 to the Company's Registration Statement on Form 10 filed September 22, 2014, and incorporated herein by reference).
|
|
|
|
10.44
|
|
Bonus Acknowledgement Agreement between Occidental Petroleum Corporation and William E. Albrecht (filed as Exhibit 10.21 to Amendment No. 3 to the Company's Registration Statement on Form 10 filed September 22, 2014, and incorporated herein by reference).
|
|
|
|
10.45
|
|
Retention and Separation Arrangement with Todd A. Stevens (filed as Exhibit 10.22 to Amendment No. 3 to the Company's Registration Statement on Form 10 filed September 22, 2014, and incorporated herein by reference).
|
|
|
|
10.46
|
|
Retention and Separation Arrangement with William E. Albrecht (filed as Exhibit 10.23 to Amendment No. 3 to the Company's Registration Statement on Form 10 filed September 22, 2014, and incorporated herein by reference).
|
|
|
|
10.47
|
|
Retention and Separation Arrangement with Robert A. Barnes (filed as Exhibit 10.24 to Amendment No. 3 to the Company's Registration Statement on Form 10 filed September 22, 2014, and incorporated herein by reference).
|
|
|
|
12*
|
|
Computation of Ratio of Earnings to Fixed Charges.
|
|
|
|
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, 2016.
|
|
|
|
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 24, 2017
|
By:
|
/s/ Todd A. Stevens
|
|
|
Todd A. Stevens
|
|
|
President
|
|
|
and Chief Executive Officer
|
|
|
|
Title
|
Date
|
|
|
|
|
|
|
/s/ Todd A. Stevens
|
|
President,
|
February 24, 2017
|
|
Todd A. Stevens
|
|
Chief Executive Officer and Director
|
|
|
|
|
|
|
|
/s/ Marshall D. Smith
|
|
Senior Executive Vice President and
|
February 24, 2017
|
|
Marshall D. Smith
|
|
Chief Financial Officer
|
|
|
|
|
|
|
|
/s/ Roy Pineci
|
|
Executive Vice President - Finance and
|
February 24, 2017
|
|
Roy Pineci
|
|
Principal Accounting Officer
|
|
|
|
|
|
|
|
/s/ William E. Albrecht
|
|
Chairman of the Board
|
February 24, 2017
|
|
William E. Albrecht
|
|
||
|
|
|
|
|
|
/s/ Justin A. Gannon
|
|
Director
|
February 24, 2017
|
|
Justin A. Gannon
|
|
||
|
|
|
|
|
|
/s/ Ronald L. Havner
|
|
Director
|
February 24, 2017
|
|
Ronald L. Havner
|
|
||
|
|
|
|
|
|
/s/ Catherine Kehr
|
|
Director
|
February 24, 2017
|
|
Catherine Kehr
|
|
||
|
|
|
|
|
|
/s/ Harold M. Korell
|
|
Director
|
February 24, 2017
|
|
Harold M. Korell
|
|
||
|
|
|
|
|
|
/s/ Richard W. Moncrief
|
|
Director
|
February 24, 2017
|
|
Richard W. Moncrief
|
|
||
|
|
|
|
|
|
/s/ Avedick B. Poladian
|
|
Director
|
February 24, 2017
|
|
Avedick B. Poladian
|
|
||
|
|
|
|
|
|
/s/ Robert V. Sinnott
|
|
Director
|
February 24, 2017
|
|
Robert V. Sinnott
|
|
||
|
|
|
|
|
|
/s/ Timothy J. Sloan
|
|
Director
|
February 24, 2017
|
|
Timothy J. Sloan
|
|
12
|
|
Computation of Ratio of Earnings to Fixed Charges.
|
|
|
|
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, 2016.
|
|
|
|
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.
|
1 Year California Resources Chart |
1 Month California Resources Chart |
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