þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
(State or other jurisdiction of
incorporation or organization)
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46-5670947
(I.R.S. Employer
Identification No.)
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9200 Oakdale Ave.
Los Angeles, California
(Address of principal executive offices)
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91311
(Zip Code)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock
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New York Stock Exchange
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5% Senior Notes due 2020
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5 1/2% Senior Notes due 2021
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6% Senior Notes due 2024
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Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
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Yes
¨
No
þ
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Large Accelerated Filer
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þ
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Accelerated Filer
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¨
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Non-Accelerated Filer
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¨
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Smaller Reporting Company
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¨
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Name
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Jurisdiction of Formation
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California Heavy Oil, Inc.
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Delaware
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California Resources Coles Levee, LLC
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Delaware
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California Resources Coles Levee, L.P.
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Delaware
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California Resources Elk Hills, LLC
|
|
Delaware
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California Resources Long Beach, Inc.
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|
Delaware
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California Resources Petroleum Corporation
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Delaware
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California Resources Production Corporation
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Delaware
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California Resources Tidelands, Inc.
|
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Delaware
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California Resources Wilmington, LLC
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|
Delaware
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CRC Construction Services, LLC
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Delaware
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CRC Marketing, Inc.
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Delaware
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CRC Services, LLC
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Delaware
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Elk Hills Power, LLC
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Delaware
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Socal Holding, LLC
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Delaware
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Southern San Joaquin Production, Inc.
|
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Delaware
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Thums Long Beach Company
|
|
Delaware
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Tidelands Oil Production Company
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Texas
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Page
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Part I
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Items 1
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Business
.........................................................................................................................................................
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General
......................................................................................................................................................
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Business Operations
.................................................................................................................................
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Our Business Strategy
...............................................................................................................................
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Key Characteristics of our Operations
.......................................................................................................
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Portfolio Management and 2016 Capital Budge
t.......................................................................................
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Reserves and Production Information
.......................................................................................................
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Marketing Arrangements
...........................................................................................................................
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Regulation of the Oil and Natural Gas Industry
.........................................................................................
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Employees
.................................................................................................................................................
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Available Information
.................................................................................................................................
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Item 1A
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Item 1B
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Item 2
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Item 3
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Item 4
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Part II
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Item 5
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Item 6
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Item 7
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Item 7A
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Item 8
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Item 9
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Item 9A
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Item 9B
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Part III
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Item 10
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Item 11
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Item 12
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Item 13
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Item 14
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Part IV
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Item 15
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Item 1
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BUSINESS
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Acreage
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Average Net Acreage Held in Fee (%)
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Producing Wells, gross
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Average Working Interest
(1)
(%)
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Identified Drilling Locations
(2)
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|||||||||||
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Gross
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Net
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Gross
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Net
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||||||||||
San Joaquin Basin
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1.9
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1.6
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62
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%
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6,235
|
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91
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%
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19,150
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13,000
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Los Angeles Basin
(3)
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<0.1
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<0.1
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52
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%
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1,385
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89
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%
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1,650
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1,600
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Ventura Basin
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0.3
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0.3
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72
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%
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735
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90
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%
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1,500
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1,250
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Sacramento Basin
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0.6
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0.5
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36
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%
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712
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79
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%
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1,150
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900
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Total
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2.8
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2.4
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57
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%
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9,067
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88
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%
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23,450
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16,750
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(1)
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For our 2015 production, our net revenue interest (NRI) was approximately 79%.
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(2)
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Our total identified drilling locations include approximately 2,600 gross (2,250 net) locations associated with proved undeveloped reserves as of
December 31, 2015
. Our total identified drilling locations also include approximately 2,600 gross (2,300 net) injection well locations. Our total identified drilling locations exclude 6,400 gross (5,300 net) prospective resource drilling locations. Please see "—Our Reserves and Production Information" for more information regarding the processes and criteria through which we identified our drilling locations.
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(3)
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We currently hold approximately 42,800 gross (34,700 net) acres in the Los Angeles basin. Our Los Angeles basin operations are concentrated with pad drilling.
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•
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Focus on high-margin crude oil projects to generate sufficient cash flows to internally fund our capital budget.
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 in the near future to the extent the oil-to-gas price relationship remains favorable and capital is available. Approximately 96% of our identified drilling inventory is associated with oil-rich projects. At current prices, availability of capital will likely be constrained. In this environment, we intend to focus on continuing the cost efficiencies we delivered in 2015 and identifying additional value-creating opportunities in order to maintain self-funding as prices improve. To the extent we generate any free cash flow, we intend to fund our capital investment program while considering any deleveraging opportunities.
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•
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Increase the share of conventional projects in our production mix to achieve lower 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. When crude oil prices increase, we intend to focus the greater portion of our capital investments on such projects, which we expect will result in lower decline rates in our production. 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 21,150 gross (14,750 net) identified drilling locations, 41% of which are associated with Improved Oil Recovery (IOR) and Enhanced Oil Recovery (EOR) projects. The remaining 59% are associated with primary recovery methods, many of which we expect will develop into IOR and EOR projects in the future.
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•
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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 2015, our operations supplied more than 2.6 billion gallons of reclaimed water for irrigation, a 30% increase from 2014. 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.
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•
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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 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 2,300 gross (2,000 net) drilling locations on this acreage. As a result of our increased focus on these reservoirs over the past few years, a significant portion of our production now 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.
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•
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Apply proven modern technologies to enhance production growth.
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 exclusively on California, we intend, as capital becomes available, to make significant use of proven modern technologies in drilling and completing wells, as well as production methods, which we expect will substantially increase both our cost efficiency and production over time. We have developed an extensive 3D seismic library covering almost 4,700 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.
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•
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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. We are also actively pursuing joint venture partnership opportunities to implement our exploration programs.
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•
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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
137
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 acreage position, approximately 60% of which we hold in fee, 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). Approximately 96% 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 growth in a higher price environment while living within our means.
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•
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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 relatively favorable pricing compared to other U.S. regions. California imports over 60% of its oil and approximately 90% of its natural gas. A vast majority of the oil is imported via supertanker, with a minor amount arriving by rail. 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.
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•
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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 2.4 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 five of the 12 largest fields in the lower 48 states based on proved reserves as of 2009, and our portfolio includes interests in four of these fields. California is also the nation’s largest state economy, and the world's eighth 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.
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•
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Opportunity rich drilling portfolio.
Our drilling inventory at December 31, 2015 consisted of approximately 23,450 gross identified well locations, including 21,150 gross (14,750 net) conventional drilling locations and approximately 2,300 gross (2,000 net) unconventional drilling locations. Our drilling inventory count increased by about 16% from the prior year as a result of our technical teams' continued efforts. We have a large inventory of conventional development opportunities that we expect can provide stable lower-risk production with attractive returns based on capital availability. In a more favorable, sustained price environment, we believe we can also achieve 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, including in the current environment.
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•
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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 total field operating costs by approximately 13% on a per Boe basis in 2015 while increasing production in a challenging environment. Our teams are continuing to improve efficiencies across all our operations in 2016.
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Proved Reserves as of December 31, 2015
|
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Average Net Daily Production for the Year Ended December 31, 2015
|
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||||||||||||||||||||
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Oil (MMBbl)
|
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NGLs (MMBbl)
|
|
Natural Gas (Bcf)
|
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Total (MMBoe)
|
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Oil (%)
|
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Proved Developed (%)
|
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(MBoe/d)
|
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Oil (%)
|
|
R/P Ratio (Years)
(1)
|
||||||||
San Joaquin Basin
|
|
297
|
|
|
56
|
|
|
591
|
|
|
451
|
|
|
66
|
%
|
|
72
|
%
|
|
110
|
|
|
58
|
%
|
|
11.2
|
Los Angeles Basin
|
|
130
|
|
|
—
|
|
|
11
|
|
|
132
|
|
|
98
|
%
|
|
80
|
%
|
|
34
|
|
|
100
|
%
|
|
10.6
|
Ventura Basin
|
|
39
|
|
|
3
|
|
|
27
|
|
|
47
|
|
|
83
|
%
|
|
77
|
%
|
|
9
|
|
|
67
|
%
|
|
14.3
|
Sacramento Basin
|
|
—
|
|
|
—
|
|
|
86
|
|
|
14
|
|
|
—
|
|
|
100
|
%
|
|
7
|
|
|
—
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%
|
|
5.5
|
Total operations
|
|
466
|
|
|
59
|
|
|
715
|
|
|
644
|
|
|
72
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%
|
|
75
|
%
|
|
160
|
|
|
65
|
%
|
|
11.1
|
(1)
|
Calculated as total proved reserves as of
December 31, 2015
divided by annualized Average Net Daily Production for the year ended
December 31, 2015
.
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|
Q1 2016
|
Q2 2016
|
Q3 2016
|
Q4 2016
|
2017
|
2018
|
||||||||||||
Calls
|
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||||||||||||
Barrels per Day
|
35,500
|
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35,500
|
|
3,000
|
|
3,000
|
|
30,000
|
|
23,300
|
|
||||||
Wtd Avg Ceiling Price per Barrel
|
$
|
66.15
|
|
$
|
66.15
|
|
$
|
74.42
|
|
$
|
74.42
|
|
$
|
55.68
|
|
$
|
57.99
|
|
|
|
|
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||||||||||||
Puts
|
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||||||||||||
Barrels per Day
(a)
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33,800
|
|
55,500
|
|
28,000
|
|
3,000
|
|
—
|
|
—
|
|
||||||
Wtd Avg Floor Price per Barrel
(a)
|
$
|
51.75
|
|
$
|
50.14
|
|
$
|
50.65
|
|
$
|
50.00
|
|
$
|
—
|
|
$
|
—
|
|
|
|
|
|
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|
||||||||||||
Swap
|
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||||||||||||
Barrels per Day
|
—
|
|
—
|
|
1,000
|
|
1,000
|
|
—
|
|
—
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|
||||||
Weighted-Average Price per Barrel
|
$
|
—
|
|
$
|
—
|
|
$
|
61.25
|
|
$
|
61.25
|
|
$
|
—
|
|
$
|
—
|
|
•
|
oil and natural gas production including well spacing or density, on private and state lands;
|
•
|
methods of constructing, drilling and completing wells, including well stimulation techniques such as hydraulic fracturing and acid matrix stimulation;
|
•
|
design, construction, operation and maintenance of facilities, such as natural gas processing plants, power plants, compressors and pipelines;
|
•
|
improved or enhanced recovery techniques such as fluid injection for waterflooding or steamflooding;
|
•
|
sourcing and disposal of water used in the drilling, completion, stimulation and enhanced recovery processes;
|
•
|
imposition of taxes and fees with respect to our properties and operations;
|
•
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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 or operate wells and facilities; and
|
•
|
occupational health, safety and environmental matters and the transportation and sale of our products as described below.
|
•
|
additional permitting of defined well stimulation treatments;
|
•
|
prior notification to proximate property owners or lessees of proposed stimulation treatments, and pre- and post-stimulation groundwater sampling as requested by the owner or lessee;
|
•
|
monitoring of groundwater quality in areas where well stimulation treatments occur, or concurrence that monitoring is not warranted due to a lack of protected water as defined by SB 4; and
|
•
|
public disclosure of fluids used and other stimulation data, including data that may be considered proprietary or trade secret.
|
•
|
require various permits and approvals before drilling, workovers, 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 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;
|
•
|
establish standards for the closure, abandonment, cleanup or restoration of former operations, such as plugging of abandoned 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 or wastes 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 by governmental authorities, special interest groups and other claimants; and
|
•
|
may restrict our rate of oil, NGLs, natural gas and electricity production.
|
•
|
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, 5 and 10; 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, decreased funds available for capital investments as well as costs incurred to reduce our labor force and otherwise adjust our cost structure;
|
•
|
reduced proved oil and gas reserves and related cash flows;
|
•
|
further impairments of our oil and gas properties such as we experienced in 2014 and 2015; and
|
•
|
reduced borrowing base capacity under our credit facility as oil and gas reserves values fall, with the potential for a reduction of our liquidity, mandatory loan repayments and default and foreclosure by our banks on our secured assets.
|
•
|
jeopardizing our ability to continue executing our business plans;
|
•
|
increasing our vulnerability to adverse changes in our business and to general economic and industry conditions, 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, react to competitive pressures and adverse regulatory changes and engage in certain transactions that might otherwise be beneficial to us.
|
•
|
incur indebtedness;
|
•
|
make investments;
|
•
|
make restricted payments;
|
•
|
create liens on certain assets forming the borrowing base for our credit facilities;
|
•
|
sell assets that constitute borrowing base collateral;
|
•
|
engage in mergers or acquisitions; and
|
•
|
release collateral.
|
•
|
a change in price basis differentials;
|
•
|
the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements;
|
•
|
an event materially impacts oil and natural gas prices in the opposite direction of our derivative positions; and
|
•
|
our production is materially less than the notional volumes.
|
•
|
the sum of its debts, including contingent liabilities, were greater than the fair value of all its assets;
|
•
|
the present fair saleable value of its assets were less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or
|
ITEM 1B
|
Unresolved Staff Comments
|
ITEM 2
|
PROPERTIES
|
|
|
As of December 31, 2015
|
|||||||||||||
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
205
|
|
|
103
|
|
|
30
|
|
|
—
|
|
|
338
|
|
NGLs (MMBbl)
|
|
45
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
47
|
|
Natural Gas (Bcf)
|
|
456
|
|
|
9
|
|
|
24
|
|
|
86
|
|
|
575
|
|
Total (MMBoe)
(1)(2)
|
|
326
|
|
|
105
|
|
|
36
|
|
|
14
|
|
|
481
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
92
|
|
|
27
|
|
|
9
|
|
|
—
|
|
|
128
|
|
NGLs (MMBbl)
|
|
11
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
12
|
|
Natural Gas (Bcf)
|
|
135
|
|
|
2
|
|
|
3
|
|
|
—
|
|
|
140
|
|
Total (MMBoe)
(2)
|
|
125
|
|
|
27
|
|
|
11
|
|
|
—
|
|
|
163
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
297
|
|
|
130
|
|
|
39
|
|
|
—
|
|
|
466
|
|
NGLs (MMBbl)
|
|
56
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
59
|
|
Natural Gas (Bcf)
|
|
591
|
|
|
11
|
|
|
27
|
|
|
86
|
|
|
715
|
|
Total (MMBoe)
(2)
|
|
451
|
|
|
132
|
|
|
47
|
|
|
14
|
|
|
644
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Approximately 16% of proved developed oil reserves, 9% of proved developed NGLs reserves, 14% of proved developed natural gas reserves and 15% of total proved developed reserves are non-producing.
|
(2)
|
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
2015
, the average prices of Brent oil and NYMEX natural gas were
$53.64
per Bbl and
$2.75
per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 20 to 1.
|
|
At December 31,
2015
|
||
|
($ in millions)
|
||
PV-10 of proved reserves
(1)
|
$
|
5,059
|
|
Present value of future income taxes discounted at 10%
|
(1,035
|
)
|
|
Standardized measure of discounted future net cash flows
|
$
|
4,024
|
|
|
|
||
Organic reserves replacement ratio
(2)
|
140
|
%
|
(1)
|
PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an asset value measure to compare against our past reserves bases and the reserves bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the tax paying status of the entity.
|
(2)
|
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 provisions, divided by oil-equivalent production. Approximately 48% of the additions for 2015 were proved undeveloped. 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. The measure is limited in that reserves may be added and produced based on costs incurred in separate periods and other oil and gas producers may use different replacement ratios affecting comparability.
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
Extensions and discoveries:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
8
|
|
|
12
|
|
|
5
|
|
|
—
|
|
|
25
|
|
NGLs (MMBbl)
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Natural Gas (Bcf)
|
|
27
|
|
|
1
|
|
|
—
|
|
|
6
|
|
|
34
|
|
Total (MMBoe)
|
|
15
|
|
|
12
|
|
|
5
|
|
|
1
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Improved recovery:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
NGLs (MMBbl)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total (MMBoe)
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|||||
Total reserves additions from capital program
|
|
18
|
|
|
12
|
|
|
5
|
|
|
1
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions related to performance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
5
|
|
|
50
|
|
|
(1
|
)
|
|
—
|
|
|
54
|
|
NGLs (MMBbl)
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(20
|
)
|
Natural Gas (Bcf)
|
|
42
|
|
|
3
|
|
|
1
|
|
|
19
|
|
|
65
|
|
Total (MMBoe)
|
|
(8
|
)
|
|
51
|
|
|
(1
|
)
|
|
3
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions related to price changes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
(40
|
)
|
|
(83
|
)
|
|
(11
|
)
|
|
—
|
|
|
(134
|
)
|
NGLs (MMBbl)
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
Natural Gas (Bcf)
|
|
(44
|
)
|
|
(8
|
)
|
|
(7
|
)
|
|
(39
|
)
|
|
(98
|
)
|
Total (MMBoe)
|
|
(50
|
)
|
|
(85
|
)
|
|
(12
|
)
|
|
(6
|
)
|
|
(153
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
NGLs (MMBbl)
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Natural Gas (Bcf)
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Total (MMBoe)
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
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)
|
7
|
|
|
9
|
|
|
3
|
|
|
—
|
|
|
19
|
|
NGLs (MMBbl)
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Natural Gas (Bcf)
|
19
|
|
|
1
|
|
|
4
|
|
|
2
|
|
|
26
|
|
Total (MMBoe)
|
12
|
|
|
9
|
|
|
4
|
|
|
—
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions related to performance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
3
|
|
|
20
|
|
|
(4
|
)
|
|
—
|
|
|
19
|
|
NGLs (MMBbl)
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8
|
)
|
Natural Gas (Bcf)
|
2
|
|
|
1
|
|
|
(2
|
)
|
|
—
|
|
|
1
|
|
Total (MMBoe)
|
(5
|
)
|
|
20
|
|
|
(4
|
)
|
|
—
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions related to price changes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
(12
|
)
|
|
(39
|
)
|
|
(4
|
)
|
|
—
|
|
|
(55
|
)
|
NGLs (MMBbl)
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
Natural Gas (Bcf)
|
(44
|
)
|
|
(5
|
)
|
|
(8
|
)
|
|
(8
|
)
|
|
(65
|
)
|
Total (MMBoe)
|
(22
|
)
|
|
(40
|
)
|
|
(6
|
)
|
|
(1
|
)
|
|
(69
|
)
|
|
|
|
|
|
|
|
|
|
|
|||||
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MMBbl)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Total (MMBoe)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Transfers to proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
(21
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Total (MMBoe)
|
(22
|
)
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
|
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
|
|
|
—
|
|
|
10,300
|
|
|
—
|
|
Steamflood
|
|
1,150
|
|
|
300
|
|
|
3,700
|
|
|
1,000
|
|
Waterflood
|
|
150
|
|
|
50
|
|
|
1,200
|
|
|
750
|
|
Unconventional
|
|
250
|
|
|
—
|
|
|
1,850
|
|
|
350
|
|
San Joaquin Basin subtotal
|
|
1,750
|
|
|
350
|
|
|
17,050
|
|
|
2,100
|
|
|
|
|
|
|
|
|
|
|
||||
Los Angeles Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
—
|
|
|
—
|
|
|
50
|
|
|
—
|
|
Steamflood
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Waterflood
|
|
250
|
|
|
100
|
|
|
1,200
|
|
|
400
|
|
Unconventional
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Los Angeles Basin subtotal
|
|
250
|
|
|
100
|
|
|
1,250
|
|
|
400
|
|
|
|
|
|
|
|
|
|
|
||||
Ventura Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
50
|
|
|
—
|
|
|
950
|
|
|
—
|
|
Steamflood
|
|
—
|
|
|
—
|
|
|
250
|
|
|
—
|
|
Waterflood
|
|
50
|
|
|
50
|
|
|
100
|
|
|
100
|
|
Unconventional
|
|
—
|
|
|
—
|
|
|
100
|
|
|
—
|
|
Ventura Basin subtotal
|
|
100
|
|
|
50
|
|
|
1,400
|
|
|
100
|
|
|
|
|
|
|
|
|
|
|
||||
Sacramento Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
1
|
|
|
—
|
|
|
1,150
|
|
|
—
|
|
Sacramento Basin subtotal
|
|
1
|
|
|
—
|
|
|
1,150
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
||||
Total Identified Drilling Locations
|
|
2,101
|
|
|
500
|
|
|
20,850
|
|
|
2,600
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2015
|
|
2014
|
|
2013
|
||||||
Production Data:
|
|
|
|
|
|
|
|
|
|
|||
Oil (MBbl/d)
|
|
104
|
|
|
99
|
|
|
90
|
|
|||
NGLs (MBbl/d)
|
|
18
|
|
|
19
|
|
|
20
|
|
|||
Natural gas (MMcf/d)
|
|
229
|
|
|
246
|
|
|
260
|
|
|||
Average daily combined production (MBoe/d)
|
|
160
|
|
|
159
|
|
|
154
|
|
|||
Total combined production (MMBoe)
|
|
58
|
|
|
58
|
|
|
56
|
|
|||
Average realized prices:
|
|
|
|
|
|
|
|
|
|
|||
Oil prices with hedge ($/Bbl)
|
|
$
|
49.19
|
|
|
$
|
92.30
|
|
|
$
|
104.16
|
|
Oil prices without hedge ($/Bbl)
|
|
$
|
47.15
|
|
|
$
|
92.30
|
|
|
$
|
104.16
|
|
NGLs prices ($/Bbl)
|
|
$
|
19.62
|
|
|
$
|
47.84
|
|
|
$
|
50.43
|
|
Natural gas prices ($/Mcf)
|
|
$
|
2.66
|
|
|
$
|
4.39
|
|
|
$
|
3.73
|
|
Average Benchmark prices:
|
|
|
|
|
|
|
|
|
|
|||
Brent oil ($/Bbl)
|
|
$
|
53.64
|
|
|
$
|
99.51
|
|
|
$
|
108.76
|
|
WTI oil ($/Bbl)
|
|
$
|
48.80
|
|
|
$
|
93.00
|
|
|
$
|
97.97
|
|
NYMEX gas ($/Mcf)
|
|
$
|
2.75
|
|
|
$
|
4.34
|
|
|
$
|
3.66
|
|
Average costs per Boe:
(a)
|
|
|
|
|
|
|
|
|
|
|||
Production costs
|
|
$
|
16.30
|
|
|
$
|
18.23
|
|
|
$
|
17.56
|
|
General and administrative expense, as adjusted
(b)
|
|
$
|
1.00
|
|
|
$
|
2.31
|
|
|
$
|
2.35
|
|
Other operating expenses, as adjusted
(c)
|
|
$
|
0.36
|
|
|
$
|
0.55
|
|
|
$
|
0.60
|
|
Depreciation, depletion and amortization
|
|
$
|
16.72
|
|
|
$
|
20.40
|
|
|
$
|
20.11
|
|
Taxes other than on income
|
|
$
|
2.67
|
|
|
$
|
3.50
|
|
|
$
|
3.05
|
|
(a)
|
For 2015 and 2014, the amount excludes asset impairment charges of $4.9 billion and $3.4 billion, respectively.
|
(b)
|
For 2015, the amount excludes unusual and infrequent costs of $0.31 per Boe related to early retirement and severance costs. For 2014, the amount excludes unusual and infrequent costs of $0.10 per Boe related to Spin-off and transition related costs.
|
(c)
|
For 2015, the amount excludes unusual and infrequent costs related to the write-down of certain assets and rig termination charges of $1.42 per Boe. For 2014, the amount excludes unusual and infrequent costs related to rig termination charges and Spin-off and transition related costs of $0.97 per Boe.
|
|
|
Elk Hills
|
|
Wilmington
|
||||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbl/d)
|
|
24
|
|
|
25
|
|
|
26
|
|
|
28
|
|
|
25
|
|
|
22
|
|
||||||
NGLs (MBbl/d)
|
|
15
|
|
|
16
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Natural gas (MMcf/d)
(a)
|
|
123
|
|
|
136
|
|
|
145
|
|
|
1
|
|
|
—
|
|
|
—
|
|
||||||
Average realized prices:
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbl/d)
|
|
$
|
52.78
|
|
|
$
|
97.27
|
|
|
$
|
106.32
|
|
|
$
|
45.50
|
|
|
$
|
90.37
|
|
|
$
|
103.29
|
|
NGLs (MBbl/d)
|
|
$
|
20.12
|
|
|
$
|
48.68
|
|
|
$
|
49.62
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Natural gas (MMcf/d)
(a)
|
|
$
|
2.67
|
|
|
$
|
4.47
|
|
|
$
|
3.67
|
|
|
$
|
2.05
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Production costs per Boe
|
|
$
|
11.11
|
|
|
$
|
14.31
|
|
|
$
|
12.34
|
|
|
$
|
21.87
|
|
|
$
|
28.98
|
|
|
$
|
31.56
|
|
(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. 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
2015
, the average prices of Brent oil and NYMEX natural gas were
$53.64
per Bbl and
$2.75
per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 20 to 1.
|
(b)
|
Excludes the effect of hedges.
|
|
|
Total Proved Reserves
|
|
Average Net Daily
Production(MBoe/d)
|
|||||
|
|
MMBoe
|
|
Oil (%)
|
|
Year ended December 31, 2015
|
|||
San Joaquin Basin
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
62
|
|
|
69
|
%
|
|
19
|
|
Waterfloods
|
|
60
|
|
|
78
|
%
|
|
8
|
|
Steamfloods
(a)
|
|
149
|
|
|
100
|
%
|
|
31
|
|
Unconventional
|
|
180
|
|
|
33
|
%
|
|
52
|
|
San Joaquin Basin subtotal
|
|
451
|
|
|
66
|
%
|
|
110
|
|
|
|
|
|
|
|
|
|||
Los Angeles Basin
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
1
|
|
|
100
|
%
|
|
1
|
|
Waterfloods
|
|
131
|
|
|
98
|
%
|
|
33
|
|
Steamfloods
|
|
—
|
|
|
—
|
%
|
|
—
|
|
Unconventional
|
|
—
|
|
|
—
|
%
|
|
—
|
|
Los Angeles Basin subtotal
|
|
132
|
|
|
98
|
%
|
|
34
|
|
|
|
|
|
|
|
|
|||
Ventura Basin
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
16
|
|
|
75
|
%
|
|
5
|
|
Waterfloods
|
|
31
|
|
|
84
|
%
|
|
4
|
|
Steamfloods
|
|
—
|
|
|
—
|
%
|
|
—
|
|
Unconventional
|
|
—
|
|
|
—
|
%
|
|
—
|
|
Ventura Basin subtotal
|
|
47
|
|
|
83
|
%
|
|
9
|
|
|
|
|
|
|
|
|
|||
Sacramento Basin
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
14
|
|
|
—
|
%
|
|
7
|
|
Sacramento Basin subtotal
|
|
14
|
|
|
—
|
%
|
|
7
|
|
|
|
|
|
|
|
|
|||
Total
|
|
644
|
|
|
72
|
%
|
|
160
|
|
(a)
|
Includes reserves and production from gas injection of 35% and 9%, respectively.
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||||||||||||
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(a)(b)
|
|
8,124
|
|
|
(963
|
)
|
|
1,752
|
|
|
(56
|
)
|
|
1,099
|
|
|
(61
|
)
|
|
—
|
|
|
—
|
|
|
10,975
|
|
|
(1,080
|
)
|
Net
(a)(c)
|
|
7,222
|
|
|
(742
|
)
|
|
1,654
|
|
|
(51
|
)
|
|
1,091
|
|
|
(59
|
)
|
|
—
|
|
|
—
|
|
|
9,967
|
|
|
(852
|
)
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(a)(b)
|
|
189
|
|
|
(92
|
)
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,273
|
|
|
(58
|
)
|
|
1,470
|
|
|
(150
|
)
|
Net
(a)(c)
|
|
161
|
|
|
(78
|
)
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,183
|
|
|
(56
|
)
|
|
1,352
|
|
|
(134
|
)
|
(a)
|
Numbers in parentheses indicate the number of wells with multiple completions.
|
(b)
|
The total number of wells in which interests are owned.
|
(c)
|
Includes fractional interests.
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
|
|
(in thousands)
|
|||||||||||||
Developed
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(b)
|
|
436
|
|
|
25
|
|
|
71
|
|
|
268
|
|
|
800
|
|
Net
(c)
|
|
398
|
|
|
20
|
|
|
69
|
|
|
249
|
|
|
736
|
|
Undeveloped
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(b)
|
|
1,418
|
|
|
18
|
|
|
231
|
|
|
373
|
|
|
2,040
|
|
Net
(c)
|
|
1,159
|
|
|
14
|
|
|
193
|
|
|
287
|
|
|
1,653
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
|
10
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
11
|
|
Net
|
10
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
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
|
|
|
|
|
|
|
|
|
|
|
|
|||||
2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
2.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.0
|
|
Development
|
543.1
|
|
|
125.7
|
|
|
18.8
|
|
|
—
|
|
|
687.6
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Development
|
—
|
|
|
—
|
|
|
—
|
|
|
7.7
|
|
|
7.7
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
5.0
|
|
|
—
|
|
|
1.0
|
|
|
1.0
|
|
|
7.0
|
|
Development
|
2.5
|
|
|
0.9
|
|
|
—
|
|
|
—
|
|
|
3.4
|
|
ITEM 3
|
Legal Proceedings
|
ITEM 4
|
Mine Safety Disclosures
|
Name
|
|
Positions Held with CRC and Predecessor and Employment History
|
|
Age at February 29, 2016
|
William E. Albrecht
|
|
Executive Chairman since 2014; Occidental Vice President 2008 to 2014; Oxy Oil & Gas, Americas President 2012 to 2014; Oxy Oil & Gas, USA President 2008 to 2012.
|
|
64
|
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.
|
|
49
|
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.
|
|
56
|
Robert A. Barnes
|
|
Executive Vice President - Northern Operations since 2014; 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.
|
|
59
|
Frank E. Komin
|
|
Executive Vice President - Southern Operations since 2014; OXY Long Beach President and General Manager 2001 to 2014; Oxy THUMS President and General Manager 2001 to 2009.
|
|
61
|
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.
|
|
45
|
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.
|
|
53
|
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.
|
|
51
|
Charles F. Weiss
|
|
Executive Vice President - Public Affairs since 2014; Occidental Vice President, Health, Environment and Safety 2007 to 2014.
|
|
52
|
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.
|
|
44
|
ITEM 5
|
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
|
|
Stock Price
|
||||||||||||||
|
|
2015
|
|
2014
|
||||||||||||
|
|
High
|
|
Low
|
|
High
|
|
Low
|
||||||||
First Quarter
|
|
$
|
7.87
|
|
|
$
|
3.75
|
|
|
N/A
|
|
N/A
|
||||
Second Quarter
|
|
$
|
9.87
|
|
|
$
|
6.00
|
|
|
N/A
|
|
N/A
|
||||
Third Quarter
|
|
$
|
6.05
|
|
|
$
|
2.26
|
|
|
N/A
|
|
N/A
|
||||
Fourth Quarter
(a)
|
|
$
|
5.15
|
|
|
$
|
1.76
|
|
|
$
|
7.37
|
|
|
$
|
5.29
|
|
(a)
|
For 2014, this period covers the month ended December 31, 2014.
|
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))
|
12,621,340
(3)
|
|
$7.02
(1)
|
|
9,772,308
(2) (3)
|
(1)
|
Exercise price applies only to approximately 11.5 million options included in column (a) and not to any other awards.
|
(2)
|
Includes
2.9 million
shares subject to rights to purchase common stock under our 2014 Employee Stock Purchase Plan (ESPP) at 85% of the lower of the market price at (i) the start of a quarter and (ii) the end of a quarter. Shares first became subject to purchase at the end of the first quarter of 2015. The number of securities remaining available for future issuance under our ESPP, as reported above, excludes 568,457 shares of our common stock which were issued during 2015 in settlement of ESPP option exercises for the final purchase period, which concluded on December 31, 2015
.
|
(3)
|
Does not include awards issued in 2015 (7.2 million shares based on maximum payout or 4.5 million shares based on target payout) currently treated as cash-settled awards that are intended to be share-settled awards subject to shareholder approval of our 2014 Long-Term Incentive Plan at our annual meeting in May 2016.
|
ITEM 6
|
SELECTED FINANCIAL DATA
|
•
|
The selected statement of operations and cash flows data for the year ended December 31,
2015
consists of the stand-alone consolidated results of California Resources Corporation 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, 2012 and 2011 consists entirely of the combined results of the California business.
|
•
|
The selected balance sheet data at December 31, 2015 and 2014 consists of the consolidated balances of California Resources Corporation, while the selected balance sheet data at December 31, 2013, 2012 and 2011 consists of the combined balances of the California business.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues
|
|
$
|
2,403
|
|
|
$
|
4,173
|
|
|
$
|
4,284
|
|
|
$
|
4,073
|
|
|
$
|
3,934
|
|
Income / (loss) before income taxes
|
|
$
|
(5,476
|
)
|
|
$
|
(2,421
|
)
|
|
$
|
1,447
|
|
|
$
|
1,181
|
|
|
$
|
1,641
|
|
Net income / (loss)
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
|
$
|
971
|
|
Per common share
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
(9.27
|
)
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
$
|
1.80
|
|
|
$
|
2.50
|
|
Diluted
|
|
$
|
(9.27
|
)
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
$
|
1.80
|
|
|
$
|
2.50
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of Cash Flows Data
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
403
|
|
|
$
|
2,371
|
|
|
$
|
2,476
|
|
|
$
|
2,223
|
|
|
$
|
2,456
|
|
Capital investments
|
|
$
|
(401
|
)
|
|
$
|
(2,089
|
)
|
|
$
|
(1,669
|
)
|
|
$
|
(2,331
|
)
|
|
$
|
(2,164
|
)
|
Acquisitions
|
|
$
|
(141
|
)
|
|
$
|
(288
|
)
|
|
$
|
(48
|
)
|
|
$
|
(427
|
)
|
|
$
|
(1,405
|
)
|
Borrowings, net of costs
|
|
$
|
379
|
|
|
$
|
6,290
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Spin-off related dividends to Occidental
|
|
$
|
—
|
|
|
$
|
(6,000
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(Distributions to) contributions from Occidental, net
|
|
$
|
—
|
|
|
$
|
(335
|
)
|
|
$
|
(763
|
)
|
|
$
|
532
|
|
|
$
|
1,106
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Dividends per Common Share
|
|
$
|
0.03
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
As of December 31,
|
||||||||||||||||||
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total current assets
|
|
$
|
497
|
|
|
$
|
701
|
|
|
$
|
254
|
|
|
$
|
245
|
|
|
$
|
195
|
|
Property, plant and equipment, net
|
|
$
|
6,312
|
|
|
$
|
11,685
|
|
|
$
|
14,008
|
|
|
$
|
13,499
|
|
|
$
|
11,778
|
|
Total assets
|
|
$
|
7,053
|
|
|
$
|
12,429
|
|
|
$
|
14,297
|
|
|
$
|
13,764
|
|
|
$
|
11,989
|
|
Total current liabilities
|
|
$
|
605
|
|
|
$
|
922
|
|
|
$
|
689
|
|
|
$
|
551
|
|
|
$
|
664
|
|
Long-term debt - principal amount
|
|
$
|
6,043
|
|
|
$
|
6,360
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Deferred gain and issuance costs, net
|
|
$
|
491
|
|
|
$
|
(68
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Other long-term liabilities
|
|
$
|
830
|
|
|
$
|
549
|
|
|
$
|
497
|
|
|
$
|
511
|
|
|
$
|
454
|
|
Equity
|
|
$
|
(916
|
)
|
|
$
|
2,611
|
|
|
$
|
9,989
|
|
|
$
|
9,860
|
|
|
$
|
8,624
|
|
ITEM 7
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
2015
|
|
2014
|
|
2013
|
||||||
Brent oil ($/Bbl)
|
$
|
53.64
|
|
|
$
|
99.51
|
|
|
$
|
108.76
|
|
WTI oil ($/Bbl)
|
$
|
48.80
|
|
|
$
|
93.00
|
|
|
$
|
97.97
|
|
NYMEX gas ($/Mcf)
|
$
|
2.75
|
|
|
$
|
4.34
|
|
|
$
|
3.66
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
Pre-tax income/(loss)
|
$
|
(5,476
|
)
|
|
$
|
(2,421
|
)
|
|
$
|
1,447
|
|
Income tax (expense)/benefit
|
1,922
|
|
|
987
|
|
|
(578
|
)
|
|||
Net income/(loss)
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
Effective tax rate
|
35
|
%
|
|
41
|
%
|
|
40
|
%
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
Adjusted net income / (loss)
|
|
$
|
(311
|
)
|
|
$
|
650
|
|
|
$
|
869
|
|
Unusual and infrequent items:
|
|
|
|
|
|
|
||||||
Asset impairments
|
|
(4,852
|
)
|
|
(3,402
|
)
|
|
—
|
|
|||
Write-down of certain other assets
|
|
(71
|
)
|
|
|
|
|
|||||
Early retirement and severance costs
|
|
(67
|
)
|
|
—
|
|
|
—
|
|
|||
Rig terminations and other costs
|
|
(11
|
)
|
|
(52
|
)
|
|
—
|
|
|||
Debt transactions
|
|
(8
|
)
|
|
|
|
|
|||||
Non-cash hedge-related gains
|
|
52
|
|
|
—
|
|
|
—
|
|
|||
Spin-off and transition related costs
|
|
—
|
|
|
(55
|
)
|
|
—
|
|
|||
Valuation allowance for deferred tax assets
|
|
(294
|
)
|
|
|
|
|
|||||
Tax effects of these items and related adjustments
|
|
2,008
|
|
|
1,425
|
|
|
—
|
|
|||
Net income / (loss)
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
2015
|
|
2014
|
|
2013
|
|||
Oil (MBbl/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
64
|
|
|
64
|
|
|
58
|
|
Los Angeles Basin
|
34
|
|
|
29
|
|
|
26
|
|
Ventura Basin
|
6
|
|
|
6
|
|
|
6
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
104
|
|
|
99
|
|
|
90
|
|
|
|
|
|
|
|
|||
NGLs (MBbl/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
17
|
|
|
18
|
|
|
19
|
|
Los Angeles Basin
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin
|
1
|
|
|
1
|
|
|
1
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
18
|
|
|
19
|
|
|
20
|
|
|
|
|
|
|
|
|||
Natural gas (MMcf/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
172
|
|
|
180
|
|
|
182
|
|
Los Angeles Basin
|
2
|
|
|
1
|
|
|
2
|
|
Ventura Basin
|
11
|
|
|
11
|
|
|
11
|
|
Sacramento Basin
|
44
|
|
|
54
|
|
|
65
|
|
Total
|
229
|
|
|
246
|
|
|
260
|
|
|
|
|
|
|
|
|||
Total Production (MBoe/d)
(a)
|
160
|
|
|
159
|
|
|
154
|
|
(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,
2015
, the average prices of Brent oil and NYMEX natural gas were
$53.64
per barrel and
$2.75
per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 20 to 1.
|
|
2015
|
|
2014
|
|
2013
|
||||||
Oil prices with hedge ($ per Bbl)
|
$
|
49.19
|
|
|
$
|
92.30
|
|
|
$
|
104.16
|
|
|
|
|
|
|
|
||||||
Oil prices without hedge ($ per Bbl)
|
$
|
47.15
|
|
|
$
|
92.30
|
|
|
$
|
104.16
|
|
NGLs prices ($ per Bbl)
|
$
|
19.62
|
|
|
$
|
47.84
|
|
|
$
|
50.43
|
|
Gas prices with hedge ($ per Mcf)
|
$
|
2.66
|
|
|
$
|
4.39
|
|
|
$
|
3.73
|
|
|
2015
|
|
2014
|
|
2013
|
|||
Oil with hedge as a percentage of Brent
|
92
|
%
|
|
93
|
%
|
|
96
|
%
|
|
|
|
|
|
|
|||
Oil without hedge as a percentage of Brent
|
88
|
%
|
|
93
|
%
|
|
96
|
%
|
Oil without hedge as a percentage of WTI
|
97
|
%
|
|
99
|
%
|
|
106
|
%
|
Gas with hedge as a percentage of NYMEX
|
97
|
%
|
|
101
|
%
|
|
102
|
%
|
|
|
2015
|
|
2014
|
||||
|
|
(in millions)
|
||||||
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
12
|
|
|
$
|
14
|
|
Trade receivables, net
|
|
$
|
200
|
|
|
$
|
308
|
|
Inventories
|
|
$
|
58
|
|
|
$
|
71
|
|
Other current assets
|
|
$
|
227
|
|
|
$
|
308
|
|
Property, plant and equipment, net
|
|
$
|
6,312
|
|
|
$
|
11,685
|
|
Other assets
|
|
$
|
244
|
|
|
$
|
43
|
|
Current maturities of long-term debt
|
|
$
|
100
|
|
|
$
|
—
|
|
Accounts payable
|
|
$
|
257
|
|
|
$
|
588
|
|
Accrued liabilities
|
|
$
|
222
|
|
|
$
|
334
|
|
Current income taxes
|
|
$
|
26
|
|
|
$
|
—
|
|
Long-term debt - principal amount
|
|
$
|
6,043
|
|
|
$
|
6,360
|
|
Deferred gain and financing costs, net
|
|
$
|
491
|
|
|
$
|
(68
|
)
|
Deferred income taxes
|
|
$
|
—
|
|
|
$
|
2,055
|
|
Other long-term liabilities
|
|
$
|
830
|
|
|
$
|
549
|
|
Equity
|
|
$
|
(916
|
)
|
|
$
|
2,611
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Oil and natural gas sales
(a)
|
$
|
2,294
|
|
|
$
|
4,023
|
|
|
$
|
4,139
|
|
Other revenue
|
109
|
|
|
150
|
|
|
145
|
|
|||
Production costs
|
(951
|
)
|
|
(1,057
|
)
|
|
(986
|
)
|
|||
General and administrative expenses
|
(354
|
)
|
|
(302
|
)
|
|
(266
|
)
|
|||
Depreciation, depletion and amortization
|
(1,004
|
)
|
|
(1,198
|
)
|
|
(1,144
|
)
|
|||
Asset impairments
|
(4,852
|
)
|
|
(3,402
|
)
|
|
—
|
|
|||
Taxes other than on income
|
(180
|
)
|
|
(217
|
)
|
|
(185
|
)
|
|||
Exploration expense
|
(36
|
)
|
|
(139
|
)
|
|
(116
|
)
|
|||
Interest and debt expense, net
|
(326
|
)
|
|
(72
|
)
|
|
—
|
|
|||
Other expenses
|
(176
|
)
|
|
(207
|
)
|
|
(140
|
)
|
|||
Income tax (expense) / benefit
|
1,922
|
|
|
987
|
|
|
(578
|
)
|
|||
Net income / (loss)
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
|
|
|
|
|
||||||
EBITDAX
(b)
|
$
|
906
|
|
|
$
|
2,548
|
|
|
$
|
2,733
|
|
|
|
|
|
|
|
||||||
Effective tax rate
|
35
|
%
|
|
41
|
%
|
|
40
|
%
|
(a)
|
Includes related-party sales for 2014 and 2013.
|
(b)
|
We define EBITDAX consistent with our Credit Facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and certain other non-cash items and unusual, infrequent charges. Our management believes EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and investment community. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. This measure is a material component of our financial covenants under our 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 EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
|
|
2015
|
|
2014
|
|
2013
|
||||||
Net income / (loss)
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
Interest expense
|
326
|
|
|
72
|
|
|
—
|
|
|||
Income tax expense / (benefit)
|
(1,922
|
)
|
|
(987
|
)
|
|
578
|
|
|||
Asset impairments
|
4,852
|
|
|
3,402
|
|
|
—
|
|
|||
Depreciation, depletion and amortization
|
1,004
|
|
|
1,198
|
|
|
1,144
|
|
|||
Exploration expense
|
36
|
|
|
139
|
|
|
116
|
|
|||
Other non-cash items
|
59
|
|
|
51
|
|
|
26
|
|
|||
Unusual and infrequent charges
(a)
|
105
|
|
|
107
|
|
|
—
|
|
|||
EBITDAX
|
$
|
906
|
|
|
$
|
2,548
|
|
|
$
|
2,733
|
|
(a)
|
For 2015, includes early retirement and severance costs, hedge related gains, debt related items and rig termination costs. For 2014, includes rig terminations and other price-related costs, and Spin-off and transition related costs.
|
|
2015
|
|
2014
|
|
2013
|
||||||
Production costs
|
$
|
16.30
|
|
|
$
|
18.23
|
|
|
$
|
17.56
|
|
General and administrative expense, as adjusted
(a)
|
$
|
1.00
|
|
|
$
|
1.47
|
|
|
$
|
1.46
|
|
Other operating expenses, as adjusted
(b)
|
$
|
0.36
|
|
|
$
|
0.55
|
|
|
$
|
0.60
|
|
Depreciation, depletion and amortization
|
$
|
16.72
|
|
|
$
|
20.40
|
|
|
$
|
20.11
|
|
Taxes other than on income
|
$
|
2.67
|
|
|
$
|
3.50
|
|
|
$
|
3.05
|
|
(a)
|
For 2015, the amount excludes unusual and infrequent costs of $0.31 per Boe related to early retirement and severance costs associated with field personnel. For 2014, the amount excludes unusual and infrequent costs of $0.10 per Boe related to Spin-off and transition related costs.
|
(b)
|
For 2015, the amount excludes unusual and infrequent costs related to the write-down of certain assets and rig termination charges of $1.42 per Boe. For 2014, the amount excludes unusual and infrequent costs related to rig termination charges and Spin-off and transition related costs of $0.97 per Boe.
|
|
2015
|
|
2014
|
|
2013
|
||||||
General and administrative expenses
|
$
|
354
|
|
|
$
|
302
|
|
|
$
|
266
|
|
Early retirement and severance costs
|
(67
|
)
|
|
—
|
|
|
—
|
|
|||
Adjusted general and administrative expenses
|
$
|
287
|
|
|
$
|
302
|
|
|
$
|
266
|
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in millions)
|
||||||||||
Net cash flows provided by operating activities
|
|
$
|
403
|
|
|
$
|
2,371
|
|
|
$
|
2,476
|
|
Net cash flows used in investing activities
|
|
$
|
(757
|
)
|
|
$
|
(2,312
|
)
|
|
$
|
(1,713
|
)
|
Net cash flows provided by (used in) financing activities
|
|
$
|
352
|
|
|
$
|
(45
|
)
|
|
$
|
(763
|
)
|
EBITDAX
(a)
|
|
$
|
906
|
|
|
$
|
2,548
|
|
|
$
|
2,733
|
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in millions)
|
||||||||||
Net cash provided by operating activities
|
|
$
|
403
|
|
|
$
|
2,371
|
|
|
$
|
2,476
|
|
Interest expense
|
|
326
|
|
|
72
|
|
|
—
|
|
|||
Current income taxes
|
|
—
|
|
|
165
|
|
|
318
|
|
|||
Cash exploration expenses
|
|
27
|
|
|
38
|
|
|
44
|
|
|||
Changes in operating assets and liabilities
|
|
147
|
|
|
(143
|
)
|
|
(103
|
)
|
|||
Other, net
|
|
3
|
|
|
45
|
|
|
(2
|
)
|
|||
EBITDAX
|
|
$
|
906
|
|
|
$
|
2,548
|
|
|
$
|
2,733
|
|
|
Conventional
|
|
Unconventional
|
|
Other
|
|
Total Capital Investments
|
||||||||||||||||||||
|
Primary
|
|
Waterflood
|
|
Steamflood
|
|
Total
|
|
Primary
|
|
|
||||||||||||||||
Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
San Joaquin
|
$
|
47
|
|
|
$
|
16
|
|
|
$
|
142
|
|
|
$
|
205
|
|
|
$
|
25
|
|
|
$
|
—
|
|
|
$
|
230
|
|
Los Angeles
|
—
|
|
|
95
|
|
|
—
|
|
|
95
|
|
|
—
|
|
|
—
|
|
|
95
|
|
|||||||
Ventura
|
18
|
|
|
8
|
|
|
2
|
|
|
28
|
|
|
—
|
|
|
—
|
|
|
28
|
|
|||||||
Sacramento
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Basin Total
|
65
|
|
|
119
|
|
|
144
|
|
|
328
|
|
|
25
|
|
|
—
|
|
|
353
|
|
|||||||
Exploration and Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48
|
|
|
48
|
|
|||||||
Total
|
$
|
65
|
|
|
$
|
119
|
|
|
$
|
144
|
|
|
$
|
328
|
|
|
$
|
25
|
|
|
$
|
48
|
|
|
$
|
401
|
|
|
|
Payments Due by Year
|
||||||||||||||||||
|
|
Total
|
|
2016
|
|
2017 and 2018
|
|
2019 and 2020
|
|
2021 and thereafter
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
On-Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt - principal amount (Note 5)
(a)
|
|
$
|
6,143
|
|
|
$
|
100
|
|
|
$
|
200
|
|
|
$
|
1,872
|
|
|
$
|
3,971
|
|
Other long-term liabilities
(b)
|
|
159
|
|
|
7
|
|
|
17
|
|
|
21
|
|
|
114
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Off-Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating leases
|
|
125
|
|
|
13
|
|
|
31
|
|
|
23
|
|
|
58
|
|
|||||
Purchase obligations
(c)
|
|
346
|
|
|
67
|
|
|
235
|
|
|
34
|
|
|
10
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total
|
|
$
|
6,773
|
|
|
$
|
187
|
|
|
$
|
483
|
|
|
$
|
1,950
|
|
|
$
|
4,153
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Excludes interest on the debt. As of December 31, 2015, interest on long-term debt totaling $2.2 billion is payable in the following years (in millions): 2016 - $348 million, 2017 and 2018 - $687 million, 2019 and 2020 - $616 million, 2021 and thereafter - $592 million. The calculation of interest payable on the variable interest debt assumes the interest rate at December 31, 2015 to be the applicable interest rate for the entire term. In performing the calculation, the Revolving Credit Facility borrowings outstanding at December 31, 2015 of
$739 million
were assumed to be outstanding for the entire term of the agreement.
|
(b)
|
Includes obligations under postretirement benefit and deferred compensation plans, as well as certain accrued liabilities.
|
(c)
|
Amounts include payments, which 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. These amounts were significantly reduced as a result of rig contract terminations in 2014. Long-term purchase contracts are discounted using a discount rate of 5.7%.
|
ITEM 7A
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
Year of Maturity
|
|
U.S. Dollar Fixed-Rate Debt
|
|
U.S. Dollar Variable-Rate Debt
|
|
Total
|
||||||
|
|
(amounts in millions)
|
||||||||||
2016
|
|
$
|
—
|
|
|
$
|
100
|
|
|
$
|
100
|
|
2017
|
|
—
|
|
|
100
|
|
|
100
|
|
|||
2018
|
|
—
|
|
|
100
|
|
|
100
|
|
|||
2019
|
|
—
|
|
|
1,439
|
|
|
1,439
|
|
|||
2020
|
|
433
|
|
|
—
|
|
|
433
|
|
|||
Thereafter
|
|
3,971
|
|
|
—
|
|
|
3,971
|
|
|||
Total
|
|
$
|
4,404
|
|
|
$
|
1,739
|
|
|
$
|
6,143
|
|
Weighted-average interest rate
|
|
6.83
|
%
|
|
2.75
|
%
|
|
5.67
|
%
|
|||
Fair Value
|
|
$
|
1,895
|
|
|
$
|
1,739
|
|
|
$
|
3,634
|
|
•
|
commodity pricing;
|
•
|
the ability of our lenders to limit our borrowing capacity;
|
•
|
other constraints on liquidity such as any inability to monetize assets;
|
•
|
the effect of our outstanding debt on our financial flexibility;
|
•
|
limits on our ability to hedge against price decreases and the effects of hedging on our ability to benefit from price increases;
|
•
|
insufficiency of our operating cash flow to fund planned capital investments;
|
•
|
inability to comply with minimum listing standards;
|
•
|
inability to implement our capital investment program profitably or at all;
|
•
|
inability to replace reserves;
|
•
|
regulations or changes in regulations and inability to comply or to obtain government permits and approvals;
|
•
|
tax law changes;
|
•
|
uncertainties associated with drilling for and producing oil and natural gas;
|
•
|
competition for and costs of oilfield equipment, services, qualified personnel and acquisitions;
|
•
|
the subjective nature of estimates of proved reserves and related future net cash flows;
|
•
|
risks related to our disposition and acquisition activities;
|
•
|
concentration of operations in a single geographic area;
|
•
|
restrictions on our ability to obtain, use, manage or dispose of water;
|
•
|
inability to drill identified locations when planned or at all;
|
•
|
concerns about climate change and other air quality issues;
|
•
|
catastrophic events for which we may be uninsured or underinsured;
|
•
|
effects of litigation;
|
•
|
cyber attacks;
|
•
|
operational issues that restrict market access; and
|
•
|
uncertainties related to the Spin-off and the agreements related thereto.
|
ITEM 8
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
|
|
|
/s/ KPMG LLP
|
|
|
|
|
|
/s/ KPMG LLP
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
||||
|
|
2015
|
|
2014
|
|
||||
|
|
|
|
|
|
||||
CURRENT ASSETS
|
|
|
|
|
|
||||
|
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
12
|
|
|
$
|
14
|
|
|
Trade receivables, net
|
|
200
|
|
|
308
|
|
|
||
Inventories
|
|
58
|
|
|
71
|
|
|
||
Other current assets
|
|
227
|
|
|
308
|
|
|
||
Total current assets
|
|
497
|
|
|
701
|
|
|
||
|
|
|
|
|
|
||||
PROPERTY, PLANT AND EQUIPMENT
|
|
20,996
|
|
|
20,536
|
|
|
||
Accumulated depreciation, depletion and amortization
|
|
(14,684
|
)
|
|
(8,851
|
)
|
|
||
|
|
6,312
|
|
|
11,685
|
|
|
||
|
|
|
|
|
|
||||
OTHER ASSETS
|
|
244
|
|
|
43
|
|
|
||
|
|
|
|
|
|
||||
TOTAL ASSETS
|
|
$
|
7,053
|
|
|
$
|
12,429
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
REVENUES
|
|
|
|
|
|
|
||||||
Oil and natural gas sales to third parties
|
|
$
|
2,294
|
|
|
$
|
1,406
|
|
|
$
|
85
|
|
Oil and natural gas sales to related parties
|
|
—
|
|
|
2,617
|
|
|
4,054
|
|
|||
Other revenue
|
|
109
|
|
|
150
|
|
|
145
|
|
|||
|
|
2,403
|
|
|
4,173
|
|
|
4,284
|
|
|||
COSTS AND OTHER DEDUCTIONS
|
|
|
|
|
|
|
||||||
Production costs
|
|
951
|
|
|
1,057
|
|
|
986
|
|
|||
General and administrative expenses
|
|
354
|
|
|
302
|
|
|
266
|
|
|||
Depreciation, depletion and amortization
|
|
1,004
|
|
|
1,198
|
|
|
1,144
|
|
|||
Asset impairments
|
|
4,852
|
|
|
3,402
|
|
|
—
|
|
|||
Taxes other than on income
|
|
180
|
|
|
217
|
|
|
185
|
|
|||
Exploration expense
|
|
36
|
|
|
139
|
|
|
116
|
|
|||
Interest and debt expense, net
|
|
326
|
|
|
72
|
|
|
—
|
|
|||
Other expenses
|
|
176
|
|
|
207
|
|
|
140
|
|
|||
|
|
7,879
|
|
|
6,594
|
|
|
2,837
|
|
|||
|
|
|
|
|
|
|
||||||
INCOME / (LOSS) BEFORE INCOME TAXES
|
|
(5,476
|
)
|
|
(2,421
|
)
|
|
1,447
|
|
|||
Income tax (expense) / benefit
|
|
1,922
|
|
|
987
|
|
|
(578
|
)
|
|||
NET INCOME / (LOSS)
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
|
|
|
|
|
|
||||||
Net income / (loss) per share of common stock
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
(9.27
|
)
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
Diluted
|
|
$
|
(9.27
|
)
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
|
|
|
|
|
|
||||||
Dividends per common share
|
|
$
|
0.03
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
Net income / (loss)
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
Other comprehensive income (loss) items:
|
|
|
|
|
|
|
||||||
Unrealized (losses) gains on derivatives
(a)
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
|||
Pension and postretirement (losses) gains
(b)
|
|
(2
|
)
|
|
(1
|
)
|
|
27
|
|
|||
Reclassification to income of realized losses (gains) on derivatives
(c)
|
|
—
|
|
|
3
|
|
|
(2
|
)
|
|||
Reclassification to income of realized losses (gains) on pensions
(d)
|
|
11
|
|
|
—
|
|
|
—
|
|
|||
Other comprehensive income, net of tax
|
|
9
|
|
|
—
|
|
|
23
|
|
|||
Comprehensive income / (loss)
|
|
$
|
(3,545
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
892
|
|
(a)
|
Net of tax of
zero
, $1 and $1 in 2015, 2014, and 2013, respectively.
|
(b)
|
Net of tax of
$1
, $1 and $(16) in 2015, 2014 and 2013, respectively. See Note 14, Retirement and Postretirement Benefit Plans, for additional information.
|
(c)
|
Net of tax of
zero
, $(2) and $1 in 2015, 2014 and 2013, respectively.
|
(d)
|
Net of tax of
$(7)
for 2015 and zero for 2014 and 2013, respectively. See Note 14, 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, 2012
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(47
|
)
|
|
$
|
9,907
|
|
|
$
|
9,860
|
|
Net income / (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
869
|
|
|
869
|
|
||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
—
|
|
|
23
|
|
||||||
Net distributions to Occidental
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(763
|
)
|
|
(763
|
)
|
||||||
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
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
||||||
Reclassification of net parent company investment to additional paid-in capital
|
—
|
|
|
4,748
|
|
|
—
|
|
|
—
|
|
|
(4,748
|
)
|
|
—
|
|
||||||
Balance, December 31, 2014
|
$
|
4
|
|
|
$
|
4,748
|
|
|
$
|
(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
|
|
|
$
|
4,778
|
|
|
$
|
(5,683
|
)
|
|
$
|
(15
|
)
|
|
$
|
—
|
|
|
$
|
(916
|
)
|
(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.
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
||||||||
Net income / (loss)
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
Adjustments to reconcile net income / (loss) to net cash provided by
operating activities:
|
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
|
1,004
|
|
|
1,198
|
|
|
1,144
|
|
|||
Asset impairments
|
|
4,852
|
|
|
3,402
|
|
|
—
|
|
|||
Deferred income tax expense / (benefit)
|
|
(2,258
|
)
|
|
(1,152
|
)
|
|
260
|
|
|||
Other noncash tax provision
|
|
310
|
|
|
—
|
|
|
—
|
|
|||
Other noncash charges to income, net
|
|
187
|
|
|
113
|
|
|
29
|
|
|||
Dry hole expenses
|
|
9
|
|
|
101
|
|
|
72
|
|
|||
Changes in operating assets and liabilities, net:
|
|
|
|
|
|
|
||||||
(Increase) decrease in receivables, net
|
|
47
|
|
|
146
|
|
|
(8
|
)
|
|||
(Increase) decrease in inventories
|
|
—
|
|
|
2
|
|
|
8
|
|
|||
(Increase) decrease in other current assets
|
|
18
|
|
|
(133
|
)
|
|
2
|
|
|||
Increase (decrease) in accounts payable and accrued liabilities
|
|
(212
|
)
|
|
128
|
|
|
100
|
|
|||
Net cash provided by operating activities
|
|
403
|
|
|
2,371
|
|
|
2,476
|
|
|||
|
|
|
|
|
|
|
||||||
CASH FLOW FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
||||||
Capital investments
|
|
(401
|
)
|
|
(2,089
|
)
|
|
(1,669
|
)
|
|||
Changes in capital investment accruals
|
|
(205
|
)
|
|
69
|
|
|
—
|
|
|||
Acquisitions and other
|
|
(151
|
)
|
|
(292
|
)
|
|
(44
|
)
|
|||
Net cash used by investing activities
|
|
(757
|
)
|
|
(2,312
|
)
|
|
(1,713
|
)
|
|||
|
|
|
|
|
|
|
||||||
CASH FLOW FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
||||||
Proceeds from revolving credit facility
|
|
2,035
|
|
|
515
|
|
|
—
|
|
|||
Repayments of revolving credit facility
|
|
(1,656
|
)
|
|
(155
|
)
|
|
—
|
|
|||
Issuance of senior notes
|
|
—
|
|
|
5,000
|
|
|
—
|
|
|||
Issuance of term loan
|
|
—
|
|
|
1,000
|
|
|
—
|
|
|||
Debt issuance costs
|
|
—
|
|
|
(70
|
)
|
|
|
|
|||
Debt repurchase and amendment costs
|
|
(23
|
)
|
|
—
|
|
|
—
|
|
|||
Issuance of common stock
|
|
8
|
|
|
—
|
|
|
—
|
|
|||
Cash dividends paid
|
|
(12
|
)
|
|
—
|
|
|
—
|
|
|||
(Distributions to) contributions from Occidental, net
|
|
—
|
|
|
(335
|
)
|
|
(763
|
)
|
|||
Dividends to Occidental
|
|
—
|
|
|
(6,000
|
)
|
|
—
|
|
|||
Net cash provided (used) by financing activities
|
|
352
|
|
|
(45
|
)
|
|
(763
|
)
|
|||
(Decrease) increase in cash and cash equivalents
|
|
(2
|
)
|
|
14
|
|
|
—
|
|
|||
Cash and cash equivalents—beginning of year
|
|
14
|
|
|
—
|
|
|
—
|
|
|||
Cash and cash equivalents—end of year
|
|
$
|
12
|
|
|
$
|
14
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
•
|
Our consolidated statements of operations, comprehensive income, cash flows, and changes in equity for the year ended December 31, 2015 consist of the stand-alone consolidated results of CRC post Spin-off.
|
•
|
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 statements of income, comprehensive income and cash flows for the years ended December 31, 2013 and 2012 consist entirely of the combined results of the California business.
|
•
|
Our consolidated balance sheets at December 31, 2015 and 2014 consist of the consolidated balances of CRC post 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 the consolidated activity for CRC subsequent to the Spin-off. Our statements of changes in equity for the years ended December 31, 2013 and 2012 consists entirely of the combined activity of the California business.
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in millions)
|
||||||||||
Balance - Beginning of Year
|
|
$
|
4
|
|
|
$
|
18
|
|
|
$
|
18
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
|
16
|
|
|
3
|
|
|
46
|
|
|||
Reclassification to property, plant and equipment based on the determination of proved reserves
|
|
(5
|
)
|
|
(8
|
)
|
|
(31
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
|
(9
|
)
|
|
(9
|
)
|
|
(15
|
)
|
|||
Balance - End of Year
|
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
18
|
|
|
|
For the years ended December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in millions)
|
||||||
Beginning balance
|
|
$
|
415
|
|
|
$
|
415
|
|
Liabilities incurred - capitalized to PP&E
|
|
7
|
|
|
19
|
|
||
Liabilities settled and paid
|
|
(18
|
)
|
|
(29
|
)
|
||
Accretion expense
|
|
20
|
|
|
22
|
|
||
Acquisitions, disposition and other - changes in PP&E
|
|
—
|
|
|
22
|
|
||
Revisions to estimated cash flows - changes in PP&E
|
|
(67
|
)
|
|
(34
|
)
|
||
Ending balance
|
|
$
|
357
|
|
|
$
|
415
|
|
|
|
Balance at December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in millions)
|
||||||
Materials and supplies
|
|
$
|
55
|
|
|
$
|
66
|
|
Finished goods
|
|
3
|
|
|
5
|
|
||
Total
|
|
$
|
58
|
|
|
$
|
71
|
|
|
|
December 31,
|
||||||
|
|
2015
|
|
2014
|
||||
|
|
(in millions)
|
||||||
Secured First Lien Bank Debt
|
|
|
|
|
||||
Revolving Credit Facility
|
|
$
|
739
|
|
|
$
|
360
|
|
Term Loan Facility
|
|
1,000
|
|
|
1,000
|
|
||
Senior Secured Second Lien Notes
|
|
|
|
|
||||
8% Notes Due 2022
|
|
2,250
|
|
|
—
|
|
||
Senior Unsecured Notes
|
|
|
|
|
||||
5% Notes Due 2020
|
|
433
|
|
|
1,000
|
|
||
5 1/2% Notes Due 2021
|
|
829
|
|
|
1,750
|
|
||
6% Notes Due 2024
|
|
892
|
|
|
2,250
|
|
||
Total Debt - Principal Amount
|
|
6,143
|
|
|
6,360
|
|
||
Less Current Maturities of Long-Term Debt
|
|
(100
|
)
|
|
—
|
|
||
Long-Term Debt - Principal Amount
|
|
$
|
6,043
|
|
|
$
|
6,360
|
|
2016
|
|
$
|
100
|
|
2017
|
|
100
|
|
|
2018
|
|
100
|
|
|
2019
|
|
1,439
|
|
|
2020
|
|
433
|
|
|
Thereafter
|
|
3,971
|
|
|
Total
|
|
$
|
6,143
|
|
|
|
Amount
|
||
|
|
(in millions)
|
||
2016
|
|
$
|
13
|
|
2017
|
|
16
|
|
|
2018
|
|
15
|
|
|
2019
|
|
14
|
|
|
2020
|
|
9
|
|
|
Thereafter
|
|
58
|
|
|
Total minimum lease payments
|
|
$
|
125
|
|
•
|
Brent-based puts for our first half 2016 oil production of 30,500 barrels per day with a weighted-average floor price of $52.38 per barrel and 3,000 barrels for the second half 2016 at $50.00 per barrel.
|
•
|
Brent-based calls for our first half 2016 oil production of 35,500 barrels per day at a weighted-average ceiling price of $66.15 per barrel and 3,000 barrels for the second half 2016 at $74.42 per barrel.
|
|
Q1 2016
|
Q2 2016
|
Q3 2016
|
Q4 2016
|
2017
|
2018
|
||||||||||||
Calls
|
|
|
|
|
|
|
||||||||||||
Barrels per Day
|
35,500
|
|
35,500
|
|
3,000
|
|
3,000
|
|
30,000
|
|
23,300
|
|
||||||
Wtd Avg Ceiling Price per Barrel
|
$
|
66.15
|
|
$
|
66.15
|
|
$
|
74.42
|
|
$
|
74.42
|
|
$
|
55.68
|
|
$
|
57.99
|
|
|
|
|
|
|
|
|
||||||||||||
Puts
|
|
|
|
|
|
|
||||||||||||
Barrels per Day
|
33,800
|
|
55,500
|
|
28,000
|
|
3,000
|
|
—
|
|
—
|
|
||||||
Wtd Avg Floor Price per Barrel
|
$
|
51.75
|
|
$
|
50.14
|
|
$
|
50.65
|
|
$
|
50.00
|
|
$
|
—
|
|
$
|
—
|
|
|
|
|
|
|
|
|
||||||||||||
Swap
|
|
|
|
|
|
|
||||||||||||
Barrels per Day
|
—
|
|
—
|
|
1,000
|
|
1,000
|
|
—
|
|
—
|
|
||||||
Weighted-Average Price per Barrel
|
$
|
—
|
|
$
|
—
|
|
$
|
61.25
|
|
$
|
61.25
|
|
$
|
—
|
|
$
|
—
|
|
|
|
Asset Derivatives
|
|
|
|
Liability Derivatives
|
|
|
||||
December 31, 2015
|
|
Balance Sheet Location
|
|
Fair Value
|
|
Balance Sheet Location
|
|
Fair Value
|
||||
Commodity contracts
|
|
Other current assets
|
|
$
|
87
|
|
|
Accrued Liabilities
|
|
$
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
||||
Total gross and net fair value
|
|
|
|
$
|
87
|
|
|
|
|
$
|
(1
|
)
|
|
|
December 31, 2015
|
||||||||||||||||||
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Collateral
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative instruments, other current assets
|
|
$
|
—
|
|
|
$
|
87
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
87
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative instruments, accrued liabilities
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
|
December 31, 2014
|
||||||||||||||||||
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Collateral
|
|
Total
|
||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity derivative instruments, other current assets
|
|
$
|
—
|
|
|
$
|
24
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24
|
|
For the years ended December 31,
|
United States
Federal
|
|
State
and Local
|
|
Total
|
||||||
|
(in millions)
|
||||||||||
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
|
)
|
|
|
|
|
|
|
||||||
2013
|
|
|
|
|
|
|
|
|
|||
Current
|
$
|
227
|
|
|
$
|
91
|
|
|
$
|
318
|
|
Deferred
|
222
|
|
|
38
|
|
|
260
|
|
|||
|
$
|
449
|
|
|
$
|
129
|
|
|
$
|
578
|
|
|
For the years ended
December 31,
|
|||||||
|
2015
|
|
2014
|
|
2013
|
|||
United States federal statutory tax rate
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
State income taxes, net of federal provision
|
5
|
|
|
6
|
|
|
6
|
|
Valuation allowance
|
(5
|
)
|
|
—
|
|
|
—
|
|
Other
|
—
|
|
|
—
|
|
|
(1
|
)
|
Effective tax rate
|
35
|
%
|
|
41
|
%
|
|
40
|
%
|
|
2015
|
|
2014
|
||||||||||||
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
||||||||
|
(in millions)
|
||||||||||||||
Long-term debt
|
$
|
608
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Property, plant and equipment differences
|
132
|
|
|
(427
|
)
|
|
—
|
|
|
(2,437
|
)
|
||||
Postretirement benefit accruals
|
41
|
|
|
—
|
|
|
39
|
|
|
—
|
|
||||
Deferred compensation and benefits
|
75
|
|
|
—
|
|
|
62
|
|
|
—
|
|
||||
Asset retirement obligations
|
156
|
|
|
—
|
|
|
184
|
|
|
—
|
|
||||
Federal effect of state income taxes
|
28
|
|
|
(24
|
)
|
|
68
|
|
|
—
|
|
||||
Net operating loss carryforward
|
7
|
|
|
—
|
|
|
64
|
|
|
—
|
|
||||
All other
|
47
|
|
|
(3
|
)
|
|
27
|
|
|
(1
|
)
|
||||
Subtotal
|
1,094
|
|
|
(454
|
)
|
|
444
|
|
|
(2,438
|
)
|
||||
Valuation allowance
|
(382
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Total net deferred taxes
|
$
|
712
|
|
|
$
|
(454
|
)
|
|
$
|
444
|
|
|
$
|
(2,438
|
)
|
|
Cash-Settled
|
|
Stock-Settled
|
||||||||||
|
RSUs (000's)
|
|
Weighted-Average Grant Date Fair Value
|
|
RSUs (000's)
|
|
Weighted-Average Grant-Date Fair Value
|
||||||
Unvested at January 1
|
4,548
|
|
|
$
|
7.37
|
|
|
2,773
|
|
|
$
|
7.84
|
|
Granted
|
7,497
|
|
|
$
|
4.20
|
|
|
—
|
|
|
$
|
—
|
|
Vested
|
(1,883
|
)
|
|
$
|
7.23
|
|
|
(1,176
|
)
|
|
$
|
7.67
|
|
Forfeited
|
(1,122
|
)
|
|
$
|
5.12
|
|
|
(276
|
)
|
|
$
|
7.99
|
|
Unvested at December 31
|
9,040
|
|
|
$
|
5.05
|
|
|
1,321
|
|
|
$
|
7.94
|
|
|
Cash-Settled
|
|
Stock-Settled
|
||||||||||
|
PSUs (000's)
|
|
Weighted-Average Grant Date Fair Value
|
|
PSUs (000's)
|
|
Weighted-Average Grant-Date Fair Value
|
||||||
Unvested at January 1
|
—
|
|
|
$
|
—
|
|
|
3,890
|
|
|
$
|
7.65
|
|
Granted
|
2,864
|
|
|
$
|
4.20
|
|
|
—
|
|
|
$
|
—
|
|
Vested
|
—
|
|
|
$
|
—
|
|
|
(670
|
)
|
|
$
|
7.03
|
|
Forfeited
|
(78
|
)
|
|
$
|
4.20
|
|
|
—
|
|
|
$
|
—
|
|
Unvested at December 31
|
2,786
|
|
|
$
|
4.20
|
|
|
3,220
|
|
|
$
|
7.78
|
|
|
|
December 31, 2015
|
|
Grant Date
|
||||
Risk-free interest rate
|
|
1.18
|
%
|
|
1.06
|
%
|
||
Dividend yield
|
|
—
|
|
|
0.95
|
%
|
||
Volatility factor
|
|
50.50
|
%
|
|
43.63
|
%
|
||
Expected life (years)
|
|
2.5
|
|
|
2.9
|
|
||
Fair value of underlying CRC stock
|
|
$
|
2.33
|
|
|
$
|
4.20
|
|
|
Options
(000's)
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Grant-Date Fair Value
|
|
Aggregate Intrinsic Value
|
|||||||
Beginning balance, January 1
|
8,481
|
|
|
$
|
8.11
|
|
|
$
|
1.98
|
|
|
$
|
—
|
|
Granted
|
3,208
|
|
|
$
|
4.20
|
|
|
$
|
1.50
|
|
|
$
|
—
|
|
Exercised
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Forfeited
|
(174
|
)
|
|
$
|
8.11
|
|
|
$
|
1.98
|
|
|
$
|
—
|
|
Expired or Canceled
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Ending balance, December 31
|
11,515
|
|
|
$
|
7.02
|
|
|
$
|
1.85
|
|
|
$
|
—
|
|
Exercisable at December 31
|
2,918
|
|
|
$
|
7.98
|
|
|
$
|
1.96
|
|
|
$
|
—
|
|
|
|
2015
|
|
2014
|
||||
Exercise price per share
|
|
$
|
4.20
|
|
|
$
|
8.11
|
|
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
|
|
$
|
1.50
|
|
|
$
|
1.98
|
|
|
|
Common Stock
|
|
|
|
(in 000's)
|
|
Balance, December 31, 2013
|
|
—
|
|
Issued
|
|
385,640
|
|
Balance, December 31, 2014
|
|
385,640
|
|
Issued
|
|
2,540
|
|
Balance, December 31, 2015
|
|
388,180
|
|
|
|
2015
|
|
2014
|
|
2013
|
||||||
|
|
(in millions, except per-share amounts)
|
||||||||||
Basic EPS calculation
|
|
|
|
|
|
|
||||||
Net income / (loss)
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
Net income / (loss) allocated to participating securities
|
|
—
|
|
|
—
|
|
|
(14
|
)
|
|||
Net income / (loss) available to common stockholders
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
855
|
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding - basic
|
|
383.2
|
|
|
381.9
|
|
|
381.8
|
|
|||
Basic EPS
|
|
$
|
(9.27
|
)
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
|
|
|
|
|
|
||||||
Diluted EPS calculation
|
|
|
|
|
|
|
||||||
Net income / (loss)
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
Net income / (loss) allocated to participating securities
|
|
—
|
|
|
—
|
|
|
(14
|
)
|
|||
Net income / (loss) available to common stockholders
|
|
$
|
(3,554
|
)
|
|
$
|
(1,434
|
)
|
|
$
|
855
|
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding - basic
|
|
383.2
|
|
|
381.9
|
|
|
381.8
|
|
|||
Dilutive effect of potentially dilutive securities
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Weighted-average common shares outstanding - diluted
|
|
383.2
|
|
|
381.9
|
|
|
381.8
|
|
|||
Diluted EPS
|
|
$
|
(9.27
|
)
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||
|
As of December 31,
|
||||||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
Amounts recognized in the balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accrued liabilities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
Other long-term liabilities
|
(27
|
)
|
|
(21
|
)
|
|
(70
|
)
|
|
(68
|
)
|
||||
|
$
|
(27
|
)
|
|
$
|
(21
|
)
|
|
$
|
(71
|
)
|
|
$
|
(68
|
)
|
AOCI included the following after-tax balances:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net loss (gain)
|
$
|
19
|
|
|
$
|
22
|
|
|
$
|
(4
|
)
|
|
$
|
2
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
Changes in the benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Benefit obligation—beginning of year
|
$
|
108
|
|
|
$
|
103
|
|
|
$
|
68
|
|
|
$
|
63
|
|
Service cost—benefits earned during the period
|
4
|
|
|
4
|
|
|
5
|
|
|
4
|
|
||||
Interest cost on projected benefit obligation
|
4
|
|
|
4
|
|
|
3
|
|
|
2
|
|
||||
Curtailment (gain) loss
|
(12
|
)
|
|
—
|
|
|
5
|
|
|
—
|
|
||||
Actuarial loss (gain)
|
24
|
|
|
6
|
|
|
(10
|
)
|
|
(1
|
)
|
||||
Benefits paid
|
(45
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
||||
Benefit obligation—end of year
|
$
|
83
|
|
|
$
|
108
|
|
|
$
|
71
|
|
|
$
|
68
|
|
|
|
|
|
|
|
|
|
||||||||
Changes in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Fair value of plan assets—beginning of year
|
$
|
87
|
|
|
$
|
91
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
1
|
|
|
5
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Benefits paid
|
(45
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
||||
Fair value of plan assets—end of year
|
$
|
56
|
|
|
$
|
87
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Unfunded status:
|
$
|
(27
|
)
|
|
$
|
(21
|
)
|
|
$
|
(71
|
)
|
|
$
|
(68
|
)
|
|
Accumulated Benefit Obligation in Excess of Plan Assets
|
|
Plan Assets in Excess of Accumulated Benefit Obligation
|
||||||||||||
|
As of December 31,
|
||||||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||||||
|
(in millions)
|
||||||||||||||
Projected Benefit Obligation
|
$
|
83
|
|
|
$
|
31
|
|
|
$
|
—
|
|
|
$
|
77
|
|
Accumulated Benefit Obligation
|
$
|
81
|
|
|
$
|
26
|
|
|
$
|
—
|
|
|
$
|
62
|
|
Fair Value of Plan Assets
|
$
|
56
|
|
|
$
|
19
|
|
|
$
|
—
|
|
|
$
|
68
|
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2015
|
|
2014
|
|
2013
|
||||||||||||
|
(in millions)
|
||||||||||||||||||||||
Net periodic benefit costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Service cost—benefits earned during the period
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
5
|
|
Interest cost on projected benefit obligation
|
4
|
|
|
4
|
|
|
3
|
|
|
3
|
|
|
2
|
|
|
3
|
|
||||||
Expected return on plan assets
|
(5
|
)
|
|
(6
|
)
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Recognized actuarial loss
|
3
|
|
|
2
|
|
|
4
|
|
|
—
|
|
|
1
|
|
|
2
|
|
||||||
Settlement cost
|
18
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Curtailment loss
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost
|
$
|
24
|
|
|
$
|
6
|
|
|
$
|
10
|
|
|
$
|
13
|
|
|
$
|
7
|
|
|
$
|
10
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
|
For the years ended
December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2015
|
|
2014
|
||||
Benefit Obligation Assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
3.99
|
%
|
|
3.82
|
%
|
|
4.81
|
%
|
|
4.44
|
%
|
Rate of compensation increase
|
4.00
|
%
|
|
4.00
|
%
|
|
—
|
|
|
—
|
|
Net Periodic Benefit Cost Assumptions:
|
|
|
|
|
|
|
|
||||
Discount rate
|
3.82
|
%
|
|
4.45
|
%
|
|
4.44
|
%
|
|
4.75
|
%
|
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, 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
|
|
|
Fair Value Measurements at
December 31, 2014 Using
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Asset Class:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Commingled funds:
|
|
|
|
|
|
|
|
||||||||
Fixed income
|
$
|
—
|
|
|
$
|
20
|
|
|
$
|
—
|
|
|
$
|
20
|
|
U.S. equity
|
—
|
|
|
31
|
|
|
—
|
|
|
31
|
|
||||
International equity
|
—
|
|
|
17
|
|
|
—
|
|
|
17
|
|
||||
Mutual funds:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Bond funds
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Blend funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Value funds
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
||||
Growth funds
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Guaranteed deposit account
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
||||
Total pension plan assets
|
$
|
12
|
|
|
$
|
68
|
|
|
$
|
7
|
|
|
$
|
87
|
|
For the years ended December 31,
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||
|
(in millions)
|
||||||
2016
|
$
|
22
|
|
|
$
|
1
|
|
2017
|
$
|
8
|
|
|
$
|
3
|
|
2018
|
$
|
9
|
|
|
$
|
3
|
|
2019
|
$
|
6
|
|
|
$
|
3
|
|
2020
|
$
|
6
|
|
|
$
|
4
|
|
2021 - 2025
|
$
|
25
|
|
|
$
|
22
|
|
|
2014
|
|
2013
|
||||
|
(in millions)
|
||||||
Sales
(a)
|
$
|
2,706
|
|
|
$
|
4,174
|
|
Allocated costs for services provided by affiliates
|
$
|
126
|
|
|
$
|
146
|
|
Purchases
|
$
|
175
|
|
|
$
|
164
|
|
(a)
|
Amounts include related-party sales from our Elk Hills power plant of $89 million and $120 million during 2014 and 2013, respectively. These sales are included in other revenue in the statements of operations.
|
Quarterly Financial Data
(Unaudited)
|
|
|
|
|
2015
|
|
2014
|
||||||||||||||||||||||||||||
Quarter
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||||||||||
|
|
(in millions, except per share amounts)
|
||||||||||||||||||||||||||||||
Revenues
|
|
$
|
577
|
|
|
$
|
634
|
|
|
$
|
626
|
|
|
$
|
566
|
|
|
$
|
1,121
|
|
|
$
|
1,140
|
|
|
$
|
1,092
|
|
|
$
|
820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Gross profit
|
|
$
|
335
|
|
|
$
|
392
|
|
|
$
|
380
|
|
|
$
|
345
|
|
|
$
|
857
|
|
|
$
|
870
|
|
|
$
|
821
|
|
|
$
|
568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income / (loss)
(a)
|
|
$
|
(100
|
)
|
|
$
|
(68
|
)
|
|
$
|
(104
|
)
|
|
$
|
(3,282
|
)
|
|
$
|
223
|
|
|
$
|
246
|
|
|
$
|
188
|
|
|
$
|
(2,091
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income / (loss) per share
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Basic
|
|
$
|
(0.26
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
(0.27
|
)
|
|
$
|
(8.54
|
)
|
|
$
|
0.57
|
|
|
$
|
0.63
|
|
|
$
|
0.48
|
|
|
$
|
(5.47
|
)
|
Diluted
|
|
$
|
(0.26
|
)
|
|
$
|
(0.18
|
)
|
|
$
|
(0.27
|
)
|
|
$
|
(8.54
|
)
|
|
$
|
0.57
|
|
|
$
|
0.63
|
|
|
$
|
0.48
|
|
|
$
|
(5.47
|
)
|
(a)
|
For the second quarter of 2015, amount included non-cash after-tax charges consisting of $10 million in hedge-related losses and $6 million in early retirement and severance costs. For the third quarter of 2015, amount included non-cash after-tax gains of $36 million for hedges, offset by $42 million in early retirement and severance costs. For the fourth quarter of 2015, amount included unusual and infrequent after-tax charges 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. For the fourth quarter of 2014, amount included unusual and infrequent after-tax charges consisting of $2.0 billion of asset impairments, $31 million of rig termination and other price-related costs, and $33 million of Spin-off and transition related costs.
|
(b)
|
For comparative purposes, and to provide a more meaningful calculation for weighted-average shares, we assumed the shares distributed to Occidental stockholders in conjunction with the Spin-off were outstanding at the beginning of each period prior to the Spin-off.
|
|
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, 2012
|
312
|
|
|
138
|
|
|
47
|
|
|
—
|
|
|
497
|
|
Revisions of previous estimates
|
(8
|
)
|
|
3
|
|
|
(3
|
)
|
|
—
|
|
|
(8
|
)
|
Improved recovery
|
49
|
|
|
24
|
|
|
3
|
|
|
—
|
|
|
76
|
|
Extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Acquisitions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(21
|
)
|
|
(10
|
)
|
|
(2
|
)
|
|
—
|
|
|
(33
|
)
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
221
|
|
|
104
|
|
|
30
|
|
|
—
|
|
|
355
|
|
December 31, 2013
|
226
|
|
|
109
|
|
|
28
|
|
|
—
|
|
|
363
|
|
December 31, 2014
|
229
|
|
|
124
|
|
|
34
|
|
|
—
|
|
|
387
|
|
December 31, 2015
(b)
|
205
|
|
|
103
|
|
|
30
|
|
|
—
|
|
|
338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
91
|
|
|
34
|
|
|
17
|
|
|
—
|
|
|
142
|
|
December 31, 2013
|
106
|
|
|
46
|
|
|
17
|
|
|
—
|
|
|
169
|
|
December 31, 2014
|
111
|
|
|
39
|
|
|
14
|
|
|
—
|
|
|
164
|
|
December 31, 2015
|
92
|
|
|
27
|
|
|
9
|
|
|
—
|
|
|
128
|
|
(a)
|
Includes proved reserves related to economic arrangements similar to PSCs of 103 MMBbl, 116 MMBbl, 102 MMBbl and 98 MMBbl at December 31, 2015, 2014, 2013 and 2012, respectively.
|
(b)
|
Approximately 16% of the proved developed reserves at December 31, 2015 are nonproducing.
|
(a)
|
Approximately 9% of the proved developed reserves at December 31, 2015 are nonproducing.
|
(a)
|
Approximately 14% of the proved developed reserves at December 31, 2015 are nonproducing.
|
|
San Joaquin Basin
|
|
Los Angeles Basin
|
|
Ventura Basin
|
|
Sacramento Basin
|
|
Total
|
|||||
|
(in MMBoe
(a)
)
|
|||||||||||||
PROVED DEVELOPED AND UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2012
|
486
|
|
|
141
|
|
|
58
|
|
|
29
|
|
|
714
|
|
Revisions of previous estimates
|
4
|
|
|
2
|
|
|
(3
|
)
|
|
(6
|
)
|
|
(3
|
)
|
Improved recovery
|
61
|
|
|
25
|
|
|
3
|
|
|
—
|
|
|
89
|
|
Extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Acquisitions
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(40
|
)
|
|
(10
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
(56
|
)
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|||||
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
341
|
|
|
105
|
|
|
38
|
|
|
24
|
|
|
508
|
|
December 31, 2013
|
349
|
|
|
110
|
|
|
35
|
|
|
20
|
|
|
514
|
|
December 31, 2014
|
367
|
|
|
126
|
|
|
41
|
|
|
18
|
|
|
552
|
|
December 31, 2015
(c)
|
326
|
|
|
105
|
|
|
36
|
|
|
14
|
|
|
481
|
|
|
|
|
|
|
|
|
|
|
|
|||||
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2012
|
145
|
|
|
36
|
|
|
20
|
|
|
5
|
|
|
206
|
|
December 31, 2013
|
162
|
|
|
48
|
|
|
20
|
|
|
—
|
|
|
230
|
|
December 31, 2014
|
158
|
|
|
40
|
|
|
17
|
|
|
1
|
|
|
216
|
|
December 31, 2015
|
125
|
|
|
27
|
|
|
11
|
|
|
—
|
|
|
163
|
|
(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
2015
, the average prices of Brent oil and NYMEX natural gas were
$53.64
per Bbl and
$2.75
per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 20 to 1.
|
(b)
|
Includes proved reserves related to economic arrangements similar to PSCs of 103 MMBbl, 116 MMBbl, 102 MMBbl and 98 MMBbl at December 31,
2015
, 2014, 2013 and 2012 respectively.
|
(c)
|
Approximately 15% of the proved developed reserves at December 31,
2015
are nonproducing.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
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
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
December 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
15,120
|
|
|
$
|
2,487
|
|
|
$
|
1,479
|
|
|
$
|
542
|
|
|
$
|
19,628
|
|
Unproved properties
|
589
|
|
|
105
|
|
|
95
|
|
|
110
|
|
|
899
|
|
|||||
Total capitalized costs
(a)
|
15,709
|
|
|
2,592
|
|
|
1,574
|
|
|
652
|
|
|
20,527
|
|
|||||
Accumulated depreciation, depletion and amortization
(b)
|
(5,764
|
)
|
|
(571
|
)
|
|
(346
|
)
|
|
(146
|
)
|
|
(6,827
|
)
|
|||||
Net capitalized costs
|
$
|
9,945
|
|
|
$
|
2,021
|
|
|
$
|
1,228
|
|
|
$
|
506
|
|
|
$
|
13,700
|
|
(a)
|
Includes acquisition costs, development costs and asset retirement obligations.
|
(b)
|
Includes accumulated valuation allowance for total unproved properties of $819 million, $715 million and $27 million at December 31,
2015
, 2014 and 2013, respectively.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
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
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
14
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
20
|
|
Unproved properties
|
23
|
|
|
9
|
|
|
1
|
|
|
—
|
|
|
33
|
|
|||||
Exploration costs
|
127
|
|
|
—
|
|
|
1
|
|
|
3
|
|
|
131
|
|
|||||
Development costs
|
1,078
|
|
|
371
|
|
|
110
|
|
|
15
|
|
|
1,574
|
|
|||||
Costs incurred
|
$
|
1,242
|
|
|
$
|
381
|
|
|
$
|
112
|
|
|
$
|
23
|
|
|
$
|
1,758
|
|
(a)
|
Total development costs includes a $62 million reduction in asset retirement obligations.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2015
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
(a)
|
$
|
1,518
|
|
|
$
|
582
|
|
|
$
|
126
|
|
|
$
|
47
|
|
|
$
|
2,273
|
|
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 income / (loss)
|
(3,578
|
)
|
|
(435
|
)
|
|
(645
|
)
|
|
(119
|
)
|
|
(4,777
|
)
|
|||||
Income tax benefit
|
(1,458
|
)
|
|
(177
|
)
|
|
(263
|
)
|
|
(48
|
)
|
|
(1,946
|
)
|
|||||
Results of operations
|
$
|
(2,120
|
)
|
|
$
|
(258
|
)
|
|
$
|
(382
|
)
|
|
$
|
(71
|
)
|
|
$
|
(2,831
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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 income / (loss)
|
(304
|
)
|
|
(726
|
)
|
|
(393
|
)
|
|
(632
|
)
|
|
(2,055
|
)
|
|||||
Income tax benefit
|
(124
|
)
|
|
(296
|
)
|
|
(161
|
)
|
|
(258
|
)
|
|
(839
|
)
|
|||||
Results of operations
|
$
|
(180
|
)
|
|
$
|
(430
|
)
|
|
$
|
(232
|
)
|
|
$
|
(374
|
)
|
|
$
|
(1,216
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2013
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
(a)
|
$
|
2,823
|
|
|
$
|
968
|
|
|
$
|
259
|
|
|
$
|
89
|
|
|
$
|
4,139
|
|
Production costs
(b)
|
565
|
|
|
315
|
|
|
78
|
|
|
28
|
|
|
986
|
|
|||||
General and administrative expenses
|
37
|
|
|
28
|
|
|
7
|
|
|
10
|
|
|
82
|
|
|||||
Other operating expenses
|
21
|
|
|
8
|
|
|
3
|
|
|
2
|
|
|
34
|
|
|||||
Depreciation, depletion and amortization
|
851
|
|
|
108
|
|
|
73
|
|
|
97
|
|
|
1,129
|
|
|||||
Taxes other than on income
|
109
|
|
|
43
|
|
|
9
|
|
|
10
|
|
|
171
|
|
|||||
Exploration expenses
|
94
|
|
|
1
|
|
|
13
|
|
|
8
|
|
|
116
|
|
|||||
Pretax income / (loss)
|
1,146
|
|
|
465
|
|
|
76
|
|
|
(66
|
)
|
|
1,621
|
|
|||||
Income tax expense / (benefit)
|
456
|
|
|
185
|
|
|
30
|
|
|
(26
|
)
|
|
645
|
|
|||||
Results of operations
|
$
|
690
|
|
|
$
|
280
|
|
|
$
|
46
|
|
|
$
|
(40
|
)
|
|
$
|
976
|
|
(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 2015, the amounts exclude unusual and infrequent costs related to early retirement and severance costs associated with personnel totaling $18 million. For 2014, the amounts exclude unusual and infrequent costs related to Spin-off and transition related costs totaling $6 million.
|
(d)
|
For 2015, the amounts exclude unusual and infrequent costs related to write down of certain assets and rig termination charges totaling $82 million. For 2014, the amounts exclude unusual and infrequent costs related to rig termination charges and Spin-off and transition related costs totaling $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 $21 million of unusual and infrequent costs related to dry holes and seismic charges.
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenue from each barrel of oil equivalent ($/Boe)
(a)(b)
|
|
$
|
37.88
|
|
|
$
|
47.76
|
|
|
$
|
36.98
|
|
|
$
|
17.44
|
|
|
$
|
38.95
|
|
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 income / (loss)
|
|
(89.29
|
)
|
|
(35.68
|
)
|
|
(189.32
|
)
|
|
(44.15
|
)
|
|
(81.86
|
)
|
|||||
Income tax benefit
|
|
(36.39
|
)
|
|
(14.52
|
)
|
|
(77.19
|
)
|
|
(17.81
|
)
|
|
(33.35
|
)
|
|||||
Results of operations
|
|
$
|
(52.90
|
)
|
|
$
|
(21.16
|
)
|
|
$
|
(112.13
|
)
|
|
$
|
(26.34
|
)
|
|
$
|
(48.51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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 income / (loss)
|
|
(7.43
|
)
|
|
(67.55
|
)
|
|
(122.09
|
)
|
|
(187.45
|
)
|
|
(35.44
|
)
|
|||||
Income tax benefit
|
|
(3.05
|
)
|
|
(27.55
|
)
|
|
(49.97
|
)
|
|
(76.85
|
)
|
|
(14.47
|
)
|
|||||
Results of operations
|
|
$
|
(4.38
|
)
|
|
$
|
(40.00
|
)
|
|
$
|
(72.12
|
)
|
|
$
|
(110.60
|
)
|
|
$
|
(20.97
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenue from each barrel of oil equivalent ($/Boe)
(a)(b)
|
|
$
|
71.86
|
|
|
$
|
101.17
|
|
|
$
|
79.28
|
|
|
$
|
22.09
|
|
|
$
|
73.72
|
|
Production costs
|
|
14.38
|
|
|
32.93
|
|
|
23.75
|
|
|
7.02
|
|
|
17.56
|
|
|||||
General and administrative expenses
|
|
0.94
|
|
|
2.93
|
|
|
2.14
|
|
|
2.48
|
|
|
1.46
|
|
|||||
Other operating expenses
|
|
0.53
|
|
|
0.83
|
|
|
0.92
|
|
|
0.50
|
|
|
0.60
|
|
|||||
Depreciation, depletion and amortization
|
|
21.66
|
|
|
11.29
|
|
|
22.34
|
|
|
24.08
|
|
|
20.11
|
|
|||||
Taxes other than on income
|
|
2.77
|
|
|
4.49
|
|
|
2.75
|
|
|
2.48
|
|
|
3.05
|
|
|||||
Exploration expenses
|
|
2.39
|
|
|
0.10
|
|
|
3.98
|
|
|
1.99
|
|
|
2.07
|
|
|||||
Pretax income / (loss)
|
|
29.19
|
|
|
48.60
|
|
|
23.40
|
|
|
(16.46
|
)
|
|
28.87
|
|
|||||
Income tax expense / (benefit)
|
|
11.61
|
|
|
19.34
|
|
|
9.18
|
|
|
(6.45
|
)
|
|
11.49
|
|
|||||
Results of operations
|
|
$
|
17.58
|
|
|
$
|
29.26
|
|
|
$
|
14.22
|
|
|
$
|
(10.01
|
)
|
|
$
|
17.38
|
|
(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, in
2015
, the average prices of Brent oil and NYMEX natural gas were
$53.64
per Bbl and
$2.75
per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 20 to 1.
|
(b)
|
Revenues are net of royalty payments.
|
(c)
|
For 2015, the amounts exclude unusual and infrequent costs related to early retirement and severance costs associated with field personnel totaling $0.31 per Boe. For 2014, the amounts exclude unusual and infrequent costs related to Spin-off and transition related costs totaling $0.10 per Boe.
|
(d)
|
For 2015, the amounts exclude unusual and infrequent costs related to the write-down of certain assets and rig termination charges of totaling $1.42 per Boe. For 2014, the amounts exclude unusual and infrequent costs 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.
|
(a)
|
Includes general and administrative expenses and taxes other than on income.
|
(b)
|
Includes asset retirement costs.
|
|
For the years ended December 31,
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
|
(in millions)
|
||||||||||
Beginning of year
|
$
|
10,828
|
|
|
$
|
9,223
|
|
|
$
|
9,073
|
|
Sales and transfers of oil and natural gas produced, net of production costs and other operating expenses
|
(1,038
|
)
|
|
(2,658
|
)
|
|
(3,082
|
)
|
|||
Net change in prices received per Bbl, production costs and other operating expenses
|
(12,362
|
)
|
|
567
|
|
|
575
|
|
|||
Extensions, discoveries and improved recovery, net of future production and development costs
|
292
|
|
|
2,593
|
|
|
1,914
|
|
|||
Change in estimated future development costs
|
792
|
|
|
75
|
|
|
(688
|
)
|
|||
Revisions of quantity estimates
|
(872
|
)
|
|
(925
|
)
|
|
(62
|
)
|
|||
Previously estimated development costs incurred during the period
|
394
|
|
|
1,440
|
|
|
1,185
|
|
|||
Accretion of discount
|
1,474
|
|
|
1,324
|
|
|
1,292
|
|
|||
Net change in income taxes
|
4,228
|
|
|
(468
|
)
|
|
(95
|
)
|
|||
Purchases and sales of reserves in place, net
|
45
|
|
|
125
|
|
|
4
|
|
|||
Changes in production rates and other
|
243
|
|
|
(468
|
)
|
|
(893
|
)
|
|||
Net change
|
(6,804
|
)
|
|
1,605
|
|
|
150
|
|
|||
End of year
|
$
|
4,024
|
|
|
$
|
10,828
|
|
|
$
|
9,223
|
|
|
2015
|
|
2014
|
|
2013
|
|||
Oil (MBbl/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
64
|
|
|
64
|
|
|
58
|
|
Los Angeles Basin
(c)
|
34
|
|
|
29
|
|
|
26
|
|
Ventura Basin
|
6
|
|
|
6
|
|
|
6
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
104
|
|
|
99
|
|
|
90
|
|
|
|
|
|
|
|
|
||
NGLs (MBbl/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
17
|
|
|
18
|
|
|
19
|
|
Los Angeles Basin
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin
|
1
|
|
|
1
|
|
|
1
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
18
|
|
|
19
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
172
|
|
|
180
|
|
|
182
|
|
Los Angeles Basin
(c)
|
2
|
|
|
1
|
|
|
2
|
|
Ventura Basin
|
11
|
|
|
11
|
|
|
11
|
|
Sacramento Basin
|
44
|
|
|
54
|
|
|
65
|
|
Total
|
229
|
|
|
246
|
|
|
260
|
|
|
|
|
|
|
|
|||
Total Production (MBoe/d)
(a)
|
160
|
|
|
159
|
|
|
154
|
|
(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, in
2015
, the average prices of Brent oil and NYMEX natural gas were
$53.64
per Bbl and
$2.75
per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 20 to 1.
|
(b)
|
Includes daily production from Elk Hills field of
24
MBbl oil,
15
MBbl NGLs and
123
MMcf natural gas in 2015; 25 MBbl oil, 16 MBbl NGLs and 136 MMcf natural gas in 2014; and 26 MBbl oil, 18 MBbl NGLs and 145 MMcf natural gas in 2013.
|
(c)
|
Includes daily production from Wilmington field of
28
MBbl Oil and
1
MMcf natural gas in 2015; 25 MBbl Oil in 2014; and 22 MBbl Oil in 2013.
|
Schedule II - Valuation and Qualifying Accounts
|
|
(in millions)
|
|
|
|
Balance at Beginning of Period
|
|
Charged to Costs and Expenses
|
|
Charged to Other Accounts
|
|
Deductions
(a)
|
|
Balance at End of Period
|
||||||||||
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
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
2013
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Environmental reserves
|
|
$
|
11
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
(4
|
)
|
|
$
|
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 4.1 to the Registrant’s Registration Statement on Form S-8 filed November 26, 2014 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
|
|
Stockholder's and Registration Rights Agreement (filed as Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed December 1, 2014 and incorporated herein by reference).
|
|
|
|
4.2
|
|
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).
|
|
|
|
4.3
|
|
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 therein by reference).
|
|
|
|
4.4
|
|
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).
|
|
|
|
4.5
|
|
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).
|
|
|
|
4.6
|
|
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).
|
|
|
|
4.7
|
|
Form of 5% Senior Note due 2020 (included in Exhibit 4.2).
|
|
|
|
4.8
|
|
Form of 5 1/2% Senior Note due 2021 (included in Exhibit 4.2).
|
|
|
|
4.9
|
|
Form of 6% Senior Note due 2024 (included in Exhibit 4.2).
|
|
|
|
4.10
|
|
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).
|
|
|
|
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 10.1 to the Registrant's Current Report on Form 8-K filed February 23, 2016, and incorporated herein by reference).
|
|
|
|
10.5
|
|
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).
|
|
|
|
10.6
|
|
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).
|
|
|
|
10.7
|
|
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).
|
|
|
|
10.8
|
|
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).
|
|
|
|
10.9
|
|
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).
|
|
|
|
10.10
|
|
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).
|
|
|
|
10.11
|
|
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).
|
|
|
|
10.12
|
|
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).
|
|
|
|
10.13
|
|
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.
|
|
|
|
10.14
|
|
California Resources Corporation Long-Term Incentive Plan Performance Stock Unit Award Terms and Conditions (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 10-Q filed November 6, 2015, and incorporated herein by reference).
|
|
|
|
10.15
|
|
California Resources Corporation Long-Term Incentive Plan Restricted Stock Unit Award Terms and Conditions (filed as Exhibit 10.3 to the Registrant’s Current Report Form 10-Q filed November 6, 2015, and incorporated herein by reference).
|
|
|
|
10.16
|
|
California Resources Corporation Long-Term Incentive Plan Nonstatutory Stock Option Award Terms and Conditions (filed as Exhibit 10.4 to the Registrant’s Current Report Form 10-Q filed November 6, 2015, and incorporated herein by reference).
|
|
|
|
10.17
|
|
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).
|
|
|
|
10.18*
|
|
First Amendment to California Resources Corporation Supplemental Savings Plan.
|
|
|
|
10.19
|
|
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).
|
|
|
|
10.20
|
|
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).
|
|
|
|
10.21
|
|
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).
|
|
|
|
10.22*
|
|
Acknowledgment of Amendment to Long-Term Incentive Award Terms and Conditions with William E. Albrecht
|
|
|
|
10.23
|
|
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).
|
|
|
|
10.24
|
|
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).
|
|
|
|
10.25
|
|
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).
|
|
|
|
10.26
|
|
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).
|
|
|
|
10.27
|
|
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).
|
|
|
|
10.28
|
|
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).
|
|
|
|
10.29
|
|
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).
|
|
|
|
10.30
|
|
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).
|
|
|
|
10.31
|
|
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).
|
|
|
|
10.32
|
|
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).
|
|
|
|
10.33
|
|
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).
|
|
|
|
10.34
|
|
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).
|
|
|
|
10.35
|
|
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).
|
|
|
|
10.36
|
|
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).
|
|
|
|
10.37
|
|
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, 2015.
|
|
|
|
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 29, 2016
|
By:
|
/s/ Todd A. Stevens
|
|
|
Todd A. Stevens
|
|
|
President
|
|
|
and Chief Executive Officer
|
|
|
|
Title
|
Date
|
|
|
|
|
|
|
/s/ Todd A. Stevens
|
|
President,
|
February 29, 2016
|
|
Todd A. Stevens
|
|
Chief Executive Officer and Director
|
|
|
|
|
|
|
|
/s/ Marshall D. Smith
|
|
Senior Executive Vice President and
|
February 29, 2016
|
|
Marshall D. Smith
|
|
Chief Financial Officer
|
|
|
|
|
|
|
|
/s/ Roy Pineci
|
|
Executive Vice President - Finance and
|
February 29, 2016
|
|
Roy Pineci
|
|
Principal Accounting Officer
|
|
|
|
|
|
|
|
/s/ William E. Albrecht
|
|
Executive Chairman of the Board
|
February 29, 2016
|
|
William E. Albrecht
|
|
||
|
|
|
|
|
|
/s/ Justin A. Gannon
|
|
Director
|
February 29, 2016
|
|
Justin A. Gannon
|
|
||
|
|
|
|
|
|
/s/ Ronald L. Havner
|
|
Director
|
February 29, 2016
|
|
Ronald L. Havner
|
|
||
|
|
|
|
|
|
/s/ Catherine Kehr
|
|
Director
|
February 29, 2016
|
|
Catherine Kehr
|
|
||
|
|
|
|
|
|
/s/ Harold M. Korell
|
|
Director
|
February 29, 2016
|
|
Harold M. Korell
|
|
||
|
|
|
|
|
|
/s/ Richard W. Moncrief
|
|
Director
|
February 29, 2016
|
|
Richard W. Moncrief
|
|
||
|
|
|
|
|
|
/s/ Avedick B. Poladian
|
|
Director
|
February 29, 2016
|
|
Avedick B. Poladian
|
|
||
|
|
|
|
|
|
/s/ Robert V. Sinnott
|
|
Director
|
February 29, 2016
|
|
Robert V. Sinnott
|
|
||
|
|
|
|
|
|
/s/ Timothy J. Sloan
|
|
Director
|
|
|
Timothy J. Sloan
|
|
February 29, 2016
|
10.18
|
|
First Amendment to California Resources Corporation Supplemental Savings Plan.
|
|
|
|
10.22
|
|
Acknowledgment of Amendment to Long-Term Incentive Award Terms and Conditions with William E. Albrecht.
|
|
|
|
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, 2015.
|
|
|
|
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)
|
the product of (i) the Participant’s Compensation in excess of the amount specified in Code section 401(a)(17) as adjusted and in effect for the Plan Year
multiplied by
(ii) the sum of (x) the percentage rate (expressed as a percentage of compensation) of Employer Matching Contribution under the Savings Plan as in effect from time to time for the Plan Year (determined as if the Participant had elected to make Deferral Contributions under the Savings Plan at the minimum rate that would produce the maximum Employer Matching Contribution under the Savings Plan) and (y) the percentage rate of Employer Fixed Nonelective Contribution (which rate shall be determined based on the rate that applies to compensation above any Social Security integration level, if applicable) as in effect under the Savings Plan from time to time for the Plan Year; provided, however, that if the rate described in subclause (x) or (y) above changes during the Plan Year, then the amount described in this clause (1) shall be determined by prorating the amount determined under subclause (i) above among the different periods during which different rates of Employer Matching Contribution and Employer Fixed Nonelective Contribution are in effect for such Plan Year. By way of example, if, for the Plan Year that begins on January 1, 2016, a Participant’s Compensation in excess of the amount specified in Code section 401(a)(17) equals $100,000, the Employer Matching Contribution rate for such Plan Year changes from 7% to 2% effective as of March 7, 2016, and the Employer Fixed Nonelective Contribution rate for such Plan Year changes from 12% to 0% effective as of March 7, 2016, then the allocation pursuant to this clause (1) for such Plan Year shall equal $5,065.57, which is the sum of $3,426.23 ($100,000 x 66/366 x 19%) plus $1,639.34 ($100,000 x 300/366 x 2%); and”
|
•
|
Restricted Stock Incentive Award granted on December 1, 2014 as a substitute for the Total Shareholder Return Incentive Award granted by Occidental on July 22, 2013
|
•
|
Restricted Stock Incentive Award granted on December 1, 2014 as a substitute for the Restricted Stock Incentive Award granted by Occidental on July 22, 2013
|
•
|
Restricted Stock Incentive Awards granted on December 1, 2014 as a substitute for the Return on Assets Incentive Awards granted by Occidental on July 22, 2013
|
•
|
Restricted Stock Incentive Award granted on December 1, 2014 as a substitute for the Restricted Stock Incentive Award granted by Occidental on July 9, 2014
|
•
|
Stock Option Award granted on December 1, 2014
|
•
|
Restricted Stock Unit Award granted on August 5, 2015
|
•
|
Performance Stock Unit Award granted on August 5, 2015
|
•
|
Stock Option Award granted on August 5, 2015
|
|
|
|
|
EXHIBIT 12
|
|
|
Year Ended December 31,
|
|||||||||||||||||||||
|
|
2015
|
|
2014
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
||||||
Income / (loss) before income taxes
(a)
|
|
$
|
(5,476
|
)
|
$
|
(2,421
|
)
|
|
$
|
1,447
|
|
|
$
|
1,181
|
|
|
$
|
1,641
|
|
|
$
|
1,129
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense and amortization of debt issuance costs and deferred gain
|
|
326
|
|
72
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Portion of lease rentals representative of the interest factor
|
|
4
|
|
3
|
|
|
4
|
|
|
4
|
|
|
3
|
|
|
3
|
|
||||||
Earnings before fixed charges
|
|
$
|
(5,146
|
)
|
$
|
(2,346
|
)
|
|
$
|
1,451
|
|
|
$
|
1,185
|
|
|
$
|
1,644
|
|
|
$
|
1,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Interest expense and amortization of debt issuance costs and deferred gain, including capitalized interest
|
|
$
|
335
|
|
$
|
76
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Portion of lease rentals representative of the interest factor
|
|
4
|
|
3
|
|
|
4
|
|
|
4
|
|
|
3
|
|
|
3
|
|
||||||
Total fixed charges
|
|
$
|
339
|
|
$
|
79
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Ratio of earnings to fixed charges
(b)
|
|
n/a
|
|
n/a
|
|
|
363
|
|
|
296
|
|
|
548
|
|
|
377
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Insufficient coverage
|
|
$
|
5,485
|
|
$
|
2,425
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Note: Had we been a stand-alone company for the full year 2014, and had the same level of debt throughout the year as we did on December 31, 2014, of approximately $6.4 billion, we would have incurred $314 million of pre-tax interest expense, on a pro-forma basis, for the year ended December 31, 2014, compared to the $72 million pre-tax interest expense reported on our statement of operations for the year then ended. Therefore, the insufficient coverage on a pro-forma basis would have been approximately $2,437 million.
|
||
(a)
|
The 2015 amount includes non-cash charges consisting of $4.9 billion of asset impairments, $71 million of write-down of certain assets, $67 million of early retirement and severance costs, $11 million of rig termination and other costs, and $8 million of debt transactions costs, partially offset by $52 million in hedge related gains. Excluding these items, our income/(loss) before income taxes for the year ended December 31, 2015 would have been approximately $(519) million. Therefore, the insufficient coverage would have been approximately $858 million. The 2014 amount includes non-cash charges consisting of $3.4 billion of asset impairments, $52 million of rig termination and other price-related costs, and $55 million of Spin-off and transition related costs. Excluding these items, our income before income taxes for the year ended December 31, 2014 would have been approximately $1.1 billion, and the ratio of earnings to fixed charges would have been 14.
|
|
(b)
|
The 2014 ratio takes into consideration interest on the debt associated with the Spin-off which we entered into during the last half of 2014.
|
|
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
|
1.
|
I have reviewed this annual report on Form 10-K of California Resources Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
|
|
|
|
/s/ Todd A. Stevens
|
|
|
|
|
Todd A. Stevens
|
|
|
|
|
President and Chief Executive Officer
|
|
|
|
|
(Principal Executive Officer)
|
1.
|
I have reviewed this annual report on Form 10-K of California Resources Corporation;
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
|
|
|
|
|
/s/ Marshall D. Smith
|
|
|
|
|
Marshall D. Smith
|
|
|
|
|
Senior Executive Vice President and
|
|
|
|
|
Chief Financial Officer
|
|
|
|
|
(Principal Financial Officer)
|
1.
|
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
2.
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
|
/s/ Todd A. Stevens
|
|
|
||
Name:
|
|
Todd A. Stevens
|
|
|
Title:
|
|
President and Chief Executive Officer
|
|
|
Date:
|
|
February 29, 2016
|
|
|
/s/ Marshall D. Smith
|
|
|
||
Name:
|
|
Marshall D. Smith
|
|
|
Title:
|
|
Senior Executive Vice President and Chief Financial Officer
|
|
|
Date:
|
|
February 29, 2016
|
|
|
\s\ Jeffrey D. Wilson
|
Jeffrey D. Wilson, P.E.
|
TBPE License No. 86426
|
Managing Senior Vice President
|
As of December 31, 2015
|
|
|
Proved
|
|||||||||||
|
|
Developed
|
|
|
|
|
|||||||
|
|
Producing
|
|
Non-Producing
|
|
Undeveloped
|
|
Total
|
|||||
Audited by Ryder Scott
Net Reserves
|
|
|
|
|
|
|
|
|
|||||
Oil/Condensate – MMBarrels
|
|
246
|
|
35
|
|
105
|
|
386
|
|||||
Plant Products – MMBarrels
|
|
35
|
|
3
|
|
10
|
|
48
|
|||||
Gas – BCF
|
|
361
|
|
26
|
|
116
|
|
503
|
|||||
MMBOE
|
|
341
|
|
42
|
|
134
|
|
517
|
|||||
Not Audited by Ryder Scott
Net Reserves
|
|
|
|
|
|
|
|
|
|||||
Oil/Condensate – MMBarrels
|
|
39
|
|
18
|
|
23
|
|
80
|
|||||
Plant Products – MMBarrels
|
|
8
|
|
1
|
|
2
|
|
11
|
|||||
Gas – BCF
|
|
137
|
|
52
|
|
24
|
|
213
|
|||||
MMBOE
|
|
70
|
|
28
|
|
29
|
|
127
|
|||||
Total
Net Reserves
|
|
|
|
|
|
|
|
|
|||||
Oil/Condensate – MMBarrels
|
|
285
|
|
53
|
|
128
|
|
466
|
|||||
Plant Products – MMBarrels
|
|
43
|
|
4
|
|
12
|
|
59
|
|||||
Gas – BCF
|
|
498
|
|
78
|
|
140
|
|
716
|
|||||
MMBOE
|
|
411
|
|
70
|
|
163
|
|
644
|
(1)
|
completion intervals which are open at the time of the estimate, but which have not started producing;
|
(2)
|
wells which were shut-in for market conditions or pipeline connections; or
|
(3)
|
wells not capable of production for mechanical reasons.
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
|