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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10889 Wilshire Blvd.
Los Angeles, California
(Address of principal executive offices)
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90024
(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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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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¨
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Accelerated Filer
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¨
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Non-Accelerated Filer
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þ
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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 Elk Hills, LLC
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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 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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Tenby, Inc.
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California
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Thums Long Beach Company
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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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Item 1A
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Item 1B
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Item 2
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Determination of Identified Drilling Locations.................................................................................................
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Production, Price and Cost History................................................................................................................
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Productive Wells.............................................................................................................................................
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Acreage..........................................................................................................................................................
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Participation in Exploratory and Development Wells Being Drilled and Drilling Activity.................................
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Delivery Commitments...................................................................................................................................
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Our Infrastructure...........................................................................................................................................
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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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51
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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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Gross Acreage Held in Fee (%)
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Producing Wells, gross
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Average Working Interest (%)
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Identified Drilling Locations
(1)
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2015 Projected Gross Development Wells (2)
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2015
Projected
Development
Drilling
Capital
(3)
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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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58
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%
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6,379
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91
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%
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14,450
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12,600
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265
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96
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Los Angeles Basin
(4)
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<0.1
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<0.1
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49
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%
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1,476
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93
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%
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2,000
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1,900
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25
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54
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Ventura Basin
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0.3
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0.3
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67
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%
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757
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89
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%
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2,350
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1,800
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—
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—
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Sacramento Basin
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0.7
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0.5
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34
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%
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719
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80
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%
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1,000
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900
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—
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—
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Total
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2.9
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2.4
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53
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%
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9,331
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89
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%
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19,800
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17,200
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290
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150
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(1)
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Our total identified drilling locations include approximately 2,400 gross (2,300 net) locations associated with proved undeveloped reserves as of December 31, 2014 and 2,500 gross (2,400 net) injection well locations associated with our waterflood and steamflood projects. 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. Of our total identified drilling locations, we believe approximately 75% are attributable to acreage owned or held by production.
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(2)
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Includes 55 injection wells expected to be drilled in connection with our steamflood and waterflood projects.
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(3)
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Includes drilling and completion expenditures of $16 million associated with injection wells. Our total 2015 capital budget of $440 million also includes investments in support equipment, seismic, workovers and exploration.
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(4)
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We currently hold approximately 40,400 gross (34,400 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 2015 and beyond to the extent the oil-to-gas price relationship remains favorable. Approximately 90% of our drilling inventory is associated with oil-rich projects. We intend to focus on increasing cost efficiencies and developing profitable opportunities in our portfolio in order to maintain self-funding throughout the commodity price cycle. We intend to reinvest substantially all of our operating cash flow in our capital investment program, while considering any potential 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, while producing sufficient cash flow to self fund continued development. In the current commodity price environment, we intend to focus a greater portion of our capital investments in such projects, which we expect will result in lower decline rates in our production. Over time, we expect that this strategy will reduce the maintenance capital required to keep base production essentially flat. We have significant additional lower-risk conventional opportunities with over 15,000 identified drilling locations, 57% of which are associated with Improved Oil Recovery ("IOR") and Enhanced Oil Recovery ("EOR") projects. The remaining 43% 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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Continue to develop high-growth unconventional drilling opportunities.
Over the longer term and in a higher oil-price environment, we expect significant production growth to come from unconventional reservoirs such as tight sandstones and shales. 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 4,800 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 investment in unconventional projects is 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 our 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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Aggressively 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 to make significant use of proven modern technologies in drilling and completing wells, which we expect will substantially increase both our cost efficiency and production growth over time. We have developed an extensive 3D seismic library covering over 4,250 square miles in all four of our basins, representing approximately 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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Proactive and collaborative approach to safety, environmental protection, and community relations.
We are committed to developing our assets in a manner that safeguards people and protects the environment. For example, we seek to proactively engage with regulatory agencies, communities, other stakeholders and our workforce to pursue mutually beneficial outcomes. As a California company, helping our state meet its water needs during the drought 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 2014, our steamflood operations supplied a record 2 billion gallons of water to California's agriculture industry, providing more water for irrigation than the fresh water we purchased for our operations statewide. We continue to implement measures to further decrease our purchased fresh water, and are designing projects to expand the beneficial use of our produced water over the next few years.
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•
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Continued focus on our successful exploration program.
As market conditions warrant, 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.
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•
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Flexible asset base that works in different commodity price environments and preserves future value and growth potential.
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 90% of our 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 price environments and target drilling projects that are economically viable through commodity price cycles. The low base decline of our conventional assets allows our future cash flows to build as commodity pricing permits capital investments to resume at higher levels to achieve significant production growth rates over the longer term.
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•
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Favorable margins driven by California's deficit energy market.
We sell all of our crude oil into the California refining markets at prices we believe are among the most favorable in the United States. 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 that have exceeded West Texas Intermediate ("WTI") based prices for comparable grades in recent years. We believe that the limited crude transportation infrastructure from other parts of the country to California will contribute to higher realizations. In addition, we own the fee minerals on approximately 60% of our net acreage position. The returns on developed mineral fee acreage are greatly enhanced because we do not pay royalties and other lease payments.
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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 seventh 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
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•
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Significant growth potential from opportunity rich drilling portfolio.
Our drilling inventory at December 31, 2014 consisted of approximately 19,800 identified well locations, including 15,000 gross (12,700 net) conventional drilling locations and approximately 4,800 gross (4,400 net) unconventional drilling locations. We have a large inventory of conventional development opportunities that we expect will provide stable lower-risk, near-term production with attractive returns. We believe we can also achieve significant long-term production growth through the development of unconventional reservoirs.
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Proven operational management and technical teams with extensive experience operating in California.
Our experienced operational management team and technical staff have a proven track record of applying modern technologies and operating methods to develop our assets. The members of our operational management and technical teams have an average of over 26 years’ experience in the oil and natural gas industry, with an average of 17 years focused on California oil and gas operations.
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Total 2015 Capital
Investments Budget
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(in millions)
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Conventional:
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Primary recovery
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$
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40
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Waterfloods
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175
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Steamfloods
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155
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Total conventional
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370
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Unconventional
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35
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Exploration
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15
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Corporate and other
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20
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Total
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$
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440
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Proved Reserves as of December 31, 2014
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Average Net Daily Production for the Year Ended December 31, 2014
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Oil (MMBbl)
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NGLs (MMBbl)
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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 (%)
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R/P Ratio (Years)
(1)
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San Joaquin Basin
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340
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82
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621
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525
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65
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%
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70
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%
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112
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57
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%
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12.8
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Los Angeles Basin
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163
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—
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16
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166
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99
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%
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76
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%
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29
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100
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%
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15.7
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Ventura Basin
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48
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3
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37
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58
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83
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%
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72
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%
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9
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69
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%
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17.7
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Sacramento Basin
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—
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—
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116
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19
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—
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94
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%
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9
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—
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%
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5.8
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Total operations
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551
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85
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790
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768
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72
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%
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72
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%
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159
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63
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%
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13.2
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(1)
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Calculated as total proved reserves as of December 31, 2014 divided by annualized Average Net Daily Production for the year ended December 31, 2014.
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•
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the conservation of oil and natural gas, including provisions for the unitization or pooling of oil and natural gas properties;
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oil and natural gas production, including well spacing or density, on private and state lands;
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methods of drilling, constructing and completing wells;
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well stimulation techniques such as hydraulic fracturing and acid matrix stimulation;
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design, construction, operation and maintenance of facilities, such as natural gas processing plants, power plants, compressors and pipelines;
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improved or enhanced recovery techniques such as fluid injection for waterflooding or steamflooding;
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sourcing and disposal of water used in the drilling, completion, stimulation and enhanced recovery processes;
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posting of bonds or other financial assurance to drill or operate wells and facilities;
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•
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imposition of taxes and fees with respect to our properties and operations; and
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occupational health, safety and environmental matters and the transportation and sale of our products as described below.
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new permitting of defined well stimulation treatments;
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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;
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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;
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•
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public disclosure of stimulation data, including data that may be considered proprietary or trade secret; and
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•
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state agencies to prepare an environmental impact report and scientific studies regarding well stimulation.
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require various permits and approvals before drilling, workovers, production, underground fluid injection, or solid and hazardous waste disposal commences, or before facilities are constructed or put into operation;
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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;
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restrict the use, types or sources of water, energy, land surface, habitat or other natural resources, require conservation measures, and impose energy efficiency or renewable energy standards;
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restrict the types, quantities, and concentrations of regulated materials, including, without limitation, oil, natural gas, produced water or wastes, that can be released or discharged into the environment in connection with drilling, production, processing, power generation or transportation activities;
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limit or prohibit operations on lands lying within coastal, wilderness, wetlands, groundwater recharge, endangered species habitat, and other protected areas;
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establish standards for the closure, abandonment, cleanup or restoration of former operations, such as plugging of abandoned wells and decommissioning of facilities;
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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;
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require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state and private lands or leases;
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impose taxes or fees with respect to the foregoing matters;
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may expose us to litigation by governmental authorities, special interest groups and other claimants; and
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may restrict the rate of oil, NGLs, natural gas and electricity production below the rate that would otherwise be possible.
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•
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Forms 10-K, 10-Q, 8-K and amendments to these forms as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC);
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•
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Other SEC filings including Forms 3, 4, 5 and 10; and
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•
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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).
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ITEM 1A
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RISK FACTORS
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•
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increasing our vulnerability to adverse changes in our business and to general economic and industry conditions, and putting us at a disadvantage against other competitors that have lower fixed obligations and more cash flow to devote to their businesses;
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•
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limiting our ability to obtain additional financing for working capital, capital investments, general corporate and other purposes; and
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•
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limiting our flexibility in operating our business and preventing us from engaging in certain transactions that might otherwise be beneficial to us.
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•
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historical production from the area compared with production from similar areas;
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•
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the quality, quantity and interpretation of available relevant data;
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•
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commodity prices;
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•
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production and operating costs;
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•
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ad valorem, excise and income taxes;
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•
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development costs;
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•
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the effects of government regulations; and
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•
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future workover and remedial costs.
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•
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our production is less than the notional volumes;
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•
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a change in price basis differentials;
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•
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the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; and
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•
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an event materially impacts oil and natural-gas prices.
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•
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enhancing our ability to grow by reinvesting substantially all of our cash flow in our business;
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•
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enhancing growth and efficiency by enabling our management team to focus its attention on the development and execution of our business in a single state;
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•
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enhancing our focus on, and accelerating our technical expertise in, specific reservoirs and fields in California; and
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•
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enhancing our market recognition with investors because of our status as an industry leader in California.
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ITEM 1B
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Unresolved Staff Comments
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ITEM 2
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PROPERTIES
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As of December 31, 2014
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|||||||||||||
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San Joaquin
Basin
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Los Angeles
Basin
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Ventura
Basin
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Sacramento
Basin
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Total
|
|||||
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
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Oil (MMBbl)
|
|
229
|
|
|
124
|
|
|
34
|
|
|
—
|
|
|
387
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|
NGLs (MMBbl)
|
|
62
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
64
|
|
Natural Gas (Bcf)
|
|
458
|
|
|
11
|
|
|
28
|
|
|
110
|
|
|
607
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|
Total (MMBoe)
(1)(2)
|
|
367
|
|
|
126
|
|
|
41
|
|
|
18
|
|
|
552
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Oil (MMBbl)
|
|
111
|
|
|
39
|
|
|
14
|
|
|
—
|
|
|
164
|
|
NGLs (MMBbl)
|
|
20
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
21
|
|
Natural Gas (Bcf)
|
|
163
|
|
|
5
|
|
|
9
|
|
|
6
|
|
|
183
|
|
Total (MMBoe)
(2)
|
|
158
|
|
|
40
|
|
|
17
|
|
|
1
|
|
|
216
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
340
|
|
|
163
|
|
|
48
|
|
|
—
|
|
|
551
|
|
NGLs (MMBbl)
|
|
82
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
85
|
|
Natural Gas (Bcf)
|
|
621
|
|
|
16
|
|
|
37
|
|
|
116
|
|
|
790
|
|
Total (MMBoe)
(2)
|
|
525
|
|
|
166
|
|
|
58
|
|
|
19
|
|
|
768
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Approximately 11% of proved developed oil reserves, 5% of proved developed NGLs reserves, 9% of proved developed natural gas reserves and 10% 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 2014, the average prices of Brent oil and NYMEX natural gas were $99.51 per Bbl and $4.34 per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 23 to 1.
|
|
At December 31,
2014
|
||
PV-10 of proved reserves (in millions)
(1)
|
$
|
16,091
|
|
Standardized measure (in millions)
|
$
|
10,828
|
|
(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 reserve bases and the reserve 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.
|
|
|
At December 31,
|
||
|
|
2014
|
||
|
|
(in millions)
|
||
PV-10
|
|
$
|
16,091
|
|
Present value of future income taxes discounted at 10%
|
|
(5,263
|
)
|
|
Standardized Measure of Discounted Future Net Cash Flows
|
|
$
|
10,828
|
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
Improved recovery:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
70
|
|
|
11
|
|
|
4
|
|
|
—
|
|
|
85
|
|
NGLs (MMBbl)
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
Natural Gas (Bcf)
|
|
107
|
|
|
—
|
|
|
2
|
|
|
5
|
|
|
114
|
|
Total (MMBoe)
|
|
101
|
|
|
11
|
|
|
4
|
|
|
1
|
|
|
117
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Extensions and discoveries:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
NGLs (MMBbl)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total (MMBoe)
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total reserve additions from capital program
|
|
102
|
|
|
11
|
|
|
4
|
|
|
1
|
|
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions of previous estimates
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
(41
|
)
|
|
8
|
|
|
(4
|
)
|
|
—
|
|
|
(37
|
)
|
NGLs (MMBbl)
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
Natural Gas (Bcf)
|
|
(91
|
)
|
|
—
|
|
|
4
|
|
|
7
|
|
|
(80
|
)
|
Total (MMBoe)
|
|
(48
|
)
|
|
8
|
|
|
(3
|
)
|
|
1
|
|
|
(42
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
1
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
6
|
|
NGLs (MMBbl)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Total (MMBoe)
|
|
1
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total proved reserve additions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
|
31
|
|
|
19
|
|
|
5
|
|
|
—
|
|
|
55
|
|
NGLs (MMBbl)
|
|
21
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
Natural Gas (Bcf)
|
|
16
|
|
|
—
|
|
|
8
|
|
|
12
|
|
|
36
|
|
Total (MMBoe)
|
|
55
|
|
|
19
|
|
|
6
|
|
|
2
|
|
|
82
|
|
(1)
|
Of these, (1) MMBoe were price-related.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
Improved recovery:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
56
|
|
|
8
|
|
|
2
|
|
|
—
|
|
|
66
|
|
NGLs (MMBbl)
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
Natural Gas (Bcf)
|
80
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
81
|
|
Total (MMBoe)
|
79
|
|
|
8
|
|
|
2
|
|
|
—
|
|
|
89
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Extensions and discoveries:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total (MMBoe)
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revisions of previous estimates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
(13
|
)
|
|
(2
|
)
|
|
(4
|
)
|
|
—
|
|
|
(19
|
)
|
NGLs (MMBbl)
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
Natural Gas (Bcf)
|
(40
|
)
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(42
|
)
|
Total (MMBoe)
|
(18
|
)
|
|
(2
|
)
|
|
(4
|
)
|
|
—
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|||||
Acquisitions:
|
|
|
|
|
|
|
|
|
|
|||||
Oil (MMBbl)
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total (MMBoe)
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Transfers to proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
(39
|
)
|
|
(13
|
)
|
|
(2
|
)
|
|
—
|
|
|
(54
|
)
|
NGLs (MMBbl)
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11
|
)
|
Natural Gas (Bcf)
|
(93
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
(1
|
)
|
|
(97
|
)
|
Total (MMBoe)
|
(66
|
)
|
|
(13
|
)
|
|
(2
|
)
|
|
—
|
|
|
(81
|
)
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved undeveloped reserve changes, net of transfers:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbl)
|
5
|
|
|
(7
|
)
|
|
(3
|
)
|
|
—
|
|
|
(5
|
)
|
NGLs (MMBbl)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Natural Gas (Bcf)
|
(53
|
)
|
|
(2
|
)
|
|
(2
|
)
|
|
(1
|
)
|
|
(58
|
)
|
Total (MMBoe)
|
(4
|
)
|
|
(7
|
)
|
|
(3
|
)
|
|
—
|
|
|
(14
|
)
|
|
|
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
|
|
150
|
|
|
—
|
|
|
3,900
|
|
|
—
|
|
Steamflood
|
|
900
|
|
|
250
|
|
|
3,100
|
|
|
900
|
|
Waterflood
|
|
100
|
|
|
50
|
|
|
1,000
|
|
|
700
|
|
Unconventional
|
|
300
|
|
|
—
|
|
|
4,550
|
|
|
300
|
|
San Joaquin Basin subtotal
|
|
1,450
|
|
|
300
|
|
|
12,550
|
|
|
1,900
|
|
|
|
|
|
|
|
|
|
|
||||
Los Angeles Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
—
|
|
|
—
|
|
|
50
|
|
|
—
|
|
Steamflood
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Waterflood
|
|
300
|
|
|
150
|
|
|
1,300
|
|
|
650
|
|
Unconventional
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Los Angeles Basin subtotal
|
|
300
|
|
|
150
|
|
|
1,350
|
|
|
650
|
|
|
|
|
|
|
|
|
|
|
||||
Ventura Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
50
|
|
|
—
|
|
|
1,650
|
|
|
—
|
|
Steamflood
|
|
15
|
|
|
—
|
|
|
200
|
|
|
—
|
|
Waterflood
|
|
50
|
|
|
50
|
|
|
200
|
|
|
250
|
|
Unconventional
|
|
2
|
|
|
—
|
|
|
50
|
|
|
—
|
|
Ventura Basin subtotal
|
|
117
|
|
|
50
|
|
|
2,100
|
|
|
250
|
|
|
|
|
|
|
|
|
|
|
||||
Sacramento Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
1
|
|
|
—
|
|
|
1,000
|
|
|
—
|
|
Sacramento Basin subtotal
|
|
1
|
|
|
—
|
|
|
1,000
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
||||
Total Identified Drilling Locations
|
|
1,868
|
|
|
500
|
|
|
17,000
|
|
|
2,800
|
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2014
|
|
2013
|
|
2012
|
||||||
Production Data:
|
|
|
|
|
|
|
|
|
|
|||
Oil (MBbl/d)
|
|
99
|
|
|
90
|
|
|
88
|
|
|||
NGLs (MBbl/d)
|
|
19
|
|
|
20
|
|
|
17
|
|
|||
Natural gas (MMcf/d)
|
|
246
|
|
|
260
|
|
|
256
|
|
|||
Average daily combined production (MBoe/d)
|
|
159
|
|
|
154
|
|
|
148
|
|
|||
Total combined production (MMBoe)
|
|
58
|
|
|
56
|
|
|
54
|
|
|||
Average realized prices:
|
|
|
|
|
|
|
|
|
|
|||
Oil (per Bbl)
|
|
$
|
92.30
|
|
|
$
|
104.16
|
|
|
$
|
104.02
|
|
NGLs (per Bbl)
|
|
$
|
47.84
|
|
|
$
|
50.43
|
|
|
$
|
52.76
|
|
Natural gas (per Mcf)
|
|
$
|
4.39
|
|
|
$
|
3.73
|
|
|
$
|
2.94
|
|
Average Benchmark prices:
|
|
|
|
|
|
|
|
|
|
|||
WTI oil ($/Bbl)
|
|
$
|
93.00
|
|
|
$
|
97.97
|
|
|
$
|
94.21
|
|
Brent oil ($/Bbl)
|
|
$
|
99.51
|
|
|
$
|
108.76
|
|
|
$
|
111.70
|
|
NYMEX gas ($/Mcf)
|
|
$
|
4.34
|
|
|
$
|
3.66
|
|
|
$
|
2.81
|
|
Average costs per Boe:
|
|
|
|
|
|
|
|
|
|
|||
Production costs
|
|
$
|
17.64
|
|
|
$
|
17.10
|
|
|
$
|
22.58
|
|
General and administrative expenses
(a)
|
|
$
|
2.31
|
|
|
$
|
2.35
|
|
|
$
|
2.48
|
|
Other operating expenses
(b)
|
|
$
|
0.55
|
|
|
$
|
0.60
|
|
|
$
|
0.33
|
|
Depreciation, depletion and amortization
|
|
$
|
20.40
|
|
|
$
|
20.11
|
|
|
$
|
16.82
|
|
Taxes other than on income
|
|
$
|
3.50
|
|
|
$
|
3.05
|
|
|
$
|
3.09
|
|
(a)
|
For 2014, the amount excludes unusual and infrequent costs of $0.10 per Boe related to Spin-off and transition related costs.
|
(b)
|
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. For 2012, the amount excludes rig termination charges of $0.22 per Boe.
|
|
|
Elk Hills
|
|
Wilmington
|
||||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbl/d)
|
|
25
|
|
|
26
|
|
|
29
|
|
|
25
|
|
|
22
|
|
|
21
|
|
||||||
NGLs (MBbl/d)
|
|
16
|
|
|
18
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Natural gas (MMcf/d)
|
|
136
|
|
|
145
|
|
|
168
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Average realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Oil (MBbl/d)
|
|
$
|
97.27
|
|
|
$
|
106.32
|
|
|
$
|
101.19
|
|
|
$
|
90.37
|
|
|
$
|
103.29
|
|
|
$
|
102.15
|
|
NGLs (MBbl/d)
|
|
$
|
48.68
|
|
|
$
|
49.62
|
|
|
$
|
53.19
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Natural gas (MMcf/d)
|
|
$
|
4.47
|
|
|
$
|
3.67
|
|
|
$
|
2.86
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Production costs per Boe
|
|
$
|
14.31
|
|
|
$
|
12.34
|
|
|
$
|
16.46
|
|
|
$
|
28.98
|
|
|
$
|
31.56
|
|
|
$
|
35.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved Reserves
|
|
Average Net Daily
Production(MBoe/d)
|
|||||
|
|
MMBoe
|
|
Oil (%)
|
|
Year Ended
December 31, 2014
|
|||
San Joaquin Basin
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
70
|
|
|
72
|
%
|
|
18
|
|
Waterfloods
|
|
60
|
|
|
76
|
%
|
|
7
|
|
Steamfloods
(a)
|
|
181
|
|
|
100
|
%
|
|
30
|
|
Unconventional
|
|
214
|
|
|
33
|
%
|
|
57
|
|
San Joaquin Basin subtotal
|
|
525
|
|
|
65
|
%
|
|
112
|
|
|
|
|
|
|
|
|
|||
Los Angeles Basin
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
—
|
|
|
—
|
%
|
|
—
|
|
Waterfloods
|
|
166
|
|
|
99
|
%
|
|
29
|
|
Steamfloods
|
|
—
|
|
|
—
|
%
|
|
—
|
|
Unconventional
|
|
—
|
|
|
—
|
%
|
|
—
|
|
Los Angeles Basin subtotal
|
|
166
|
|
|
99
|
%
|
|
29
|
|
|
|
|
|
|
|
|
|||
Ventura Basin
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
31
|
|
|
80
|
%
|
|
6
|
|
Waterfloods
|
|
25
|
|
|
87
|
%
|
|
2
|
|
Steamfloods
|
|
—
|
|
|
—
|
%
|
|
—
|
|
Unconventional
|
|
2
|
|
|
61
|
%
|
|
1
|
|
Ventura Basin subtotal
|
|
58
|
|
|
83
|
%
|
|
9
|
|
|
|
|
|
|
|
|
|||
Sacramento Basin
|
|
|
|
|
|
|
|
|
|
Primary Conventional
|
|
19
|
|
|
—
|
%
|
|
9
|
|
Sacramento Basin subtotal
|
|
19
|
|
|
—
|
%
|
|
9
|
|
|
|
|
|
|
|
|
|||
Total
|
|
768
|
|
|
72
|
%
|
|
159
|
|
(a)
|
Includes reserves and production from gas injection of 9% and 5%, respectively.
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||||||||||||
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(a)(b)
|
|
10,106
|
|
|
(1,057
|
)
|
|
1,943
|
|
|
(56
|
)
|
|
1,602
|
|
|
(61
|
)
|
|
—
|
|
|
—
|
|
|
13,651
|
|
|
(1,174
|
)
|
Net
(a)(c)
|
|
8,994
|
|
|
(817
|
)
|
|
1,835
|
|
|
(51
|
)
|
|
1,590
|
|
|
(59
|
)
|
|
—
|
|
|
—
|
|
|
12,419
|
|
|
(927
|
)
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(a)(b)
|
|
293
|
|
|
(110
|
)
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,345
|
|
|
(52
|
)
|
|
1,646
|
|
|
(162
|
)
|
Net
(a)(c)
|
|
248
|
|
|
(84
|
)
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,260
|
|
|
(50
|
)
|
|
1,516
|
|
|
(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)
|
The sum of fractional interests.
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
|
|
(in thousands)
|
|||||||||||||
Developed
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(2)
|
|
416
|
|
|
24
|
|
|
70
|
|
|
271
|
|
|
781
|
|
Net
(3)
|
|
379
|
|
|
20
|
|
|
69
|
|
|
248
|
|
|
716
|
|
Undeveloped
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
(2)
|
|
1,460
|
|
|
16
|
|
|
232
|
|
|
386
|
|
|
2,094
|
|
Net
(3)
|
|
1,187
|
|
|
14
|
|
|
191
|
|
|
299
|
|
|
1,691
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Acres spaced or assigned to productive wells.
|
(2)
|
Total acres in which we hold an interest.
|
(3)
|
Sum of fractional interests owned based on working interests or interests under arrangements similar to production-sharing contracts.
|
(4)
|
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
|
3
|
|
|
8
|
|
|
—
|
|
|
1
|
|
|
12
|
|
Net
|
3
|
|
|
8
|
|
|
—
|
|
|
1
|
|
|
12
|
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
8.0
|
|
|
—
|
|
|
2.0
|
|
|
—
|
|
|
10.0
|
|
Development
|
|
485.7
|
|
|
121.4
|
|
|
63.9
|
|
|
—
|
|
|
671.0
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
Development
|
|
2.5
|
|
|
—
|
|
|
—
|
|
|
3.0
|
|
|
5.5
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory
|
|
11.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11.0
|
|
Development
|
|
4.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.0
|
|
ITEM 3
|
Legal Proceedings
|
ITEM 4
|
Mine Safety Disclosures
|
Name
|
|
Positions Held with CRC and Predecessor and Employment History
|
|
Age at February 26, 2015
|
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.
|
|
63
|
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.
|
|
48
|
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.
|
|
55
|
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.
|
|
58
|
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.
|
|
60
|
Shawn M. Kerns
|
|
Executive Vice President - Corporate Development since 2014; Vintage Production California President and General Manager 2012 to 2014; Occidental of Elk Hills General Manager 2010 to 2012; Occidental of Elk Hills Asset Development Manager 2008 to 2010.
|
|
44
|
Roy Pineci
|
|
Executive Vice President - Finance since 2014; Occidental Vice President and Controller 2008 to 2014.
|
|
52
|
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.
|
|
50
|
Charles F. Weiss
|
|
Executive Vice President - Public Affairs since 2014; Occidental Vice President, Health, Environment and Safety 2007 to 2014.
|
|
51
|
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.
|
|
43
|
ITEM 5
|
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
|
|
Stock Price
|
|
|
||||||
|
|
High
|
|
Low
|
|
|
||||
Fourth Quarter 2014 (starting December 1, 2014)
|
|
$
|
7.37
|
|
|
$
|
5.29
|
|
|
|
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))
|
|
|
|
|
|
|
|
|
8,481,337
(1)
|
|
$8.11
(2)
|
|
17,115,099
(3)
|
(1)
|
Includes shares reserved to be issued pursuant to stock options and performance-based awards. Shares for performance-based awards are included assuming maximum payout, based on the certification of such awards on February 26, 2015.
|
(2)
|
Price applies only to the Options included in column (a). Exercise price is not applicable to the other awards included in column (a).
|
(3)
|
Includes 5 million shares subject to rights to purchase common stock at 85% of the lower of the market price at (i) the start of a quarter and (ii) the end of a quarter. Shares will first become subject to purchase at the end of the first quarter of 2015.
|
ITEM 6
|
SELECTED FINANCIAL DATA
|
•
|
The selected statement of operations and cash flows data for the year ended December 31, 2014 consists of the stand-alone consolidated results of California Resources Corporation post Spin-off and the consolidated and 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, 2011, and 2010 consist entirely of the combined results of the California business.
|
•
|
The selected balance sheet data at December 31, 2014 consists of the consolidated balances of California Resources Corporation, while the selected balance sheet data at December 31, 2013, 2012, 2011 and 2010 consists of the combined balances of the California business.
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
Statement of Operations Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenues
|
|
$
|
4,173
|
|
|
$
|
4,284
|
|
|
$
|
4,073
|
|
|
$
|
3,934
|
|
|
$
|
2,912
|
|
Income / (loss) before income taxes
|
|
$
|
(2,421
|
)
|
|
$
|
1,447
|
|
|
$
|
1,181
|
|
|
$
|
1,641
|
|
|
$
|
1,129
|
|
Net income / (loss)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
|
$
|
971
|
|
|
$
|
719
|
|
Per common share
(a)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
$
|
1.80
|
|
|
$
|
2.50
|
|
|
$
|
1.85
|
|
Diluted
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
$
|
1.80
|
|
|
$
|
2.50
|
|
|
$
|
1.85
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Statement of Cash Flows Data
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by operating activities
|
|
$
|
2,371
|
|
|
$
|
2,476
|
|
|
$
|
2,223
|
|
|
$
|
2,456
|
|
|
$
|
1,751
|
|
Capital investments
|
|
$
|
(2,020
|
)
|
|
$
|
(1,669
|
)
|
|
$
|
(2,331
|
)
|
|
$
|
(2,164
|
)
|
|
$
|
(1,056
|
)
|
Acquisitions
|
|
$
|
(288
|
)
|
|
$
|
(48
|
)
|
|
$
|
(427
|
)
|
|
$
|
(1,405
|
)
|
|
$
|
(448
|
)
|
Borrowings, net of costs
|
|
$
|
6,290
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Spin-off related dividends to Occidental
|
|
$
|
(6,000
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(Distributions to) contributions from Occidental, net
|
|
$
|
(335
|
)
|
|
$
|
(763
|
)
|
|
$
|
532
|
|
|
$
|
1,106
|
|
|
$
|
(248
|
)
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
See Note 13 - Earnings Per Share, in the Notes to the Financial Statements.
|
|
|
As of December 31,
|
||||||||||||||||||
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Total current assets
|
|
$
|
701
|
|
|
$
|
254
|
|
|
$
|
245
|
|
|
$
|
195
|
|
|
$
|
148
|
|
Property, plant and equipment, net
|
|
$
|
11,685
|
|
|
$
|
14,008
|
|
|
$
|
13,499
|
|
|
$
|
11,778
|
|
|
$
|
8,823
|
|
Total assets
|
|
$
|
12,497
|
|
|
$
|
14,297
|
|
|
$
|
13,764
|
|
|
$
|
11,989
|
|
|
$
|
8,987
|
|
Total current liabilities
|
|
$
|
906
|
|
|
$
|
689
|
|
|
$
|
551
|
|
|
$
|
664
|
|
|
$
|
471
|
|
Long-term debt
|
|
$
|
6,360
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Equity / Net Investment
|
|
$
|
2,611
|
|
|
$
|
9,989
|
|
|
$
|
9,860
|
|
|
$
|
8,624
|
|
|
$
|
6,557
|
|
ITEM 7
|
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
|
2014
|
|
2013
|
|
2012
|
||||||
WTI oil ($/Bbl)
|
$
|
93.00
|
|
|
$
|
97.97
|
|
|
$
|
94.21
|
|
Brent oil ($/Bbl)
|
$
|
99.51
|
|
|
$
|
108.76
|
|
|
$
|
111.70
|
|
NYMEX gas ($/Mcf)
|
$
|
4.34
|
|
|
$
|
3.66
|
|
|
$
|
2.81
|
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
Pre-tax income/(loss)
|
|
$
|
(2,421
|
)
|
|
$
|
1,447
|
|
|
$
|
1,181
|
|
Income tax (expense)/benefit
|
|
987
|
|
|
(578
|
)
|
|
(482
|
)
|
|||
Net income/(loss)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
Effective tax rate
|
|
41
|
%
|
|
40
|
%
|
|
41
|
%
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
Net income / (loss)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
Unusual and infrequent items:
|
|
|
|
|
|
|
||||||
Asset impairments
|
|
3,402
|
|
|
—
|
|
|
29
|
|
|||
Rig terminations and other price-related costs
|
|
52
|
|
|
—
|
|
|
12
|
|
|||
Spin-off and transition related costs
|
|
55
|
|
|
—
|
|
|
—
|
|
|||
|
|
3,509
|
|
|
—
|
|
|
41
|
|
|||
Tax effect of pre-tax adjustments
|
|
(1,425
|
)
|
|
—
|
|
|
17
|
|
|||
Core income
|
|
$
|
650
|
|
|
$
|
869
|
|
|
$
|
675
|
|
|
2014
|
|
2013
|
|
2012
|
|||
Oil (MBbl/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
64
|
|
|
58
|
|
|
58
|
|
Los Angeles Basin
|
29
|
|
|
26
|
|
|
24
|
|
Ventura Basin
|
6
|
|
|
6
|
|
|
6
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
99
|
|
|
90
|
|
|
88
|
|
|
|
|
|
|
|
|||
NGLs (MBbl/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
18
|
|
|
19
|
|
|
16
|
|
Los Angeles Basin
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin
|
1
|
|
|
1
|
|
|
1
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
19
|
|
|
20
|
|
|
17
|
|
|
|
|
|
|
|
|||
Natural gas (MMcf/d)
|
|
|
|
|
|
|||
San Joaquin Basin
|
180
|
|
|
182
|
|
|
204
|
|
Los Angeles Basin
|
1
|
|
|
2
|
|
|
3
|
|
Ventura Basin
|
11
|
|
|
11
|
|
|
12
|
|
Sacramento Basin
|
54
|
|
|
65
|
|
|
37
|
|
Total
|
246
|
|
|
260
|
|
|
256
|
|
|
|
|
|
|
|
|||
Total Production (MBoe/d) (a)
|
159
|
|
|
154
|
|
|
148
|
|
Note:
|
MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent per day.
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas to 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, 2014, the average prices of Brent oil and NYMEX natural gas were $99.51 per barrel and $4.34 per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 23 to 1.
|
|
2014
|
|
2013
|
|
2012
|
||||||
Oil Prices ($ per Bbl)
|
$
|
92.30
|
|
|
$
|
104.16
|
|
|
$
|
104.02
|
|
NGLs Prices ($ per Bbl)
|
$
|
47.84
|
|
|
$
|
50.43
|
|
|
$
|
52.76
|
|
Gas Prices ($ per Mcf)
|
$
|
4.39
|
|
|
$
|
3.73
|
|
|
$
|
2.94
|
|
|
|
2014
|
|
2013
|
||||
|
|
(in millions)
|
||||||
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
14
|
|
|
$
|
—
|
|
Trade receivables, net
|
|
$
|
308
|
|
|
$
|
30
|
|
Inventories
|
|
$
|
71
|
|
|
$
|
75
|
|
Other current assets
|
|
$
|
308
|
|
|
$
|
149
|
|
Property, plant and equipment, net
|
|
$
|
11,685
|
|
|
$
|
14,008
|
|
Other assets
|
|
$
|
111
|
|
|
$
|
35
|
|
Accounts payable
|
|
$
|
588
|
|
|
$
|
448
|
|
Accrued liabilities
|
|
$
|
318
|
|
|
$
|
241
|
|
Long-term debt
|
|
$
|
6,360
|
|
|
$
|
—
|
|
Deferred income taxes
|
|
$
|
2,055
|
|
|
$
|
3,122
|
|
Other long-term liabilities
|
|
$
|
565
|
|
|
$
|
497
|
|
Equity / Net investment
|
|
$
|
2,611
|
|
|
$
|
9,989
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in millions)
|
||||||||||
Oil and natural gas sales (including related parties)
|
$
|
4,023
|
|
|
$
|
4,139
|
|
|
$
|
3,967
|
|
Other revenue
|
150
|
|
|
145
|
|
|
106
|
|
|||
Production costs
|
(1,023
|
)
|
|
(960
|
)
|
|
(1,219
|
)
|
|||
Selling, general and administrative expenses
|
(336
|
)
|
|
(292
|
)
|
|
(273
|
)
|
|||
Depreciation, depletion and amortization
|
(1,198
|
)
|
|
(1,144
|
)
|
|
(926
|
)
|
|||
Asset impairments
|
(3,402
|
)
|
|
—
|
|
|
(29
|
)
|
|||
Taxes other than on income
|
(217
|
)
|
|
(185
|
)
|
|
(167
|
)
|
|||
Exploration expense
|
(139
|
)
|
|
(116
|
)
|
|
(148
|
)
|
|||
Interest and debt expense, net
|
(72
|
)
|
|
—
|
|
|
—
|
|
|||
Other expenses
|
(207
|
)
|
|
(140
|
)
|
|
(130
|
)
|
|||
Income tax (expense) / benefit
|
987
|
|
|
(578
|
)
|
|
(482
|
)
|
|||
Net income / (loss)
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
|
|
|
|
|
|
||||||
EBITDAX
(1)
|
$
|
2,548
|
|
|
$
|
2,733
|
|
|
$
|
2,296
|
|
|
|
|
|
|
|
||||||
Effective tax rate
|
41
|
%
|
|
40
|
%
|
|
41
|
%
|
|
2014
|
|
2013
|
|
2012
|
||||||
Net income / (loss)
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
Interest expense
|
72
|
|
|
—
|
|
|
—
|
|
|||
Income tax expense / (benefit)
|
(987
|
)
|
|
578
|
|
|
482
|
|
|||
Asset impairments
|
3,402
|
|
|
—
|
|
|
29
|
|
|||
Depreciation, depletion and amortization
|
1,198
|
|
|
1,144
|
|
|
926
|
|
|||
Exploration expense
|
139
|
|
|
116
|
|
|
148
|
|
|||
Other non-cash items
|
51
|
|
|
26
|
|
|
—
|
|
|||
Unusual and infrequent charges
(a)
|
107
|
|
|
—
|
|
|
12
|
|
|||
EBITDAX
|
$
|
2,548
|
|
|
$
|
2,733
|
|
|
$
|
2,296
|
|
(a)
|
Includes rig terminations and other price-related costs, and Spin-off and transition related costs.
|
|
2014
|
|
2013
|
|
2012
|
||||||
Production costs
|
$
|
17.64
|
|
|
$
|
17.10
|
|
|
$
|
22.58
|
|
General and administrative expenses
(a)
|
$
|
2.31
|
|
|
$
|
2.35
|
|
|
$
|
2.48
|
|
Other operating expenses
(b)
|
$
|
0.55
|
|
|
$
|
0.60
|
|
|
$
|
0.33
|
|
Depreciation, depletion and amortization
|
$
|
20.40
|
|
|
$
|
20.11
|
|
|
$
|
16.82
|
|
Taxes other than on income
|
$
|
3.50
|
|
|
$
|
3.05
|
|
|
$
|
3.09
|
|
(a)
|
For 2014, the amount excludes unusual and infrequent costs of $0.10 per Boe related to Spin-off and transition related costs.
|
(b)
|
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. For 2012, the amount excludes rig termination charges of $0.22 per Boe.
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in millions)
|
||||||||||
Net cash flows provided by operating activities
|
|
$
|
2,371
|
|
|
$
|
2,476
|
|
|
$
|
2,223
|
|
Net cash flows used in investing activities
|
|
$
|
(2,312
|
)
|
|
$
|
(1,713
|
)
|
|
$
|
(2,755
|
)
|
Net cash flows (used in) provided by financing activities
|
|
$
|
(45
|
)
|
|
$
|
(763
|
)
|
|
$
|
532
|
|
EBITDAX
(1)
|
|
$
|
2,548
|
|
|
$
|
2,733
|
|
|
$
|
2,296
|
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in millions)
|
||||||||||
Net cash provided by operating activities
|
|
$
|
2,371
|
|
|
$
|
2,476
|
|
|
$
|
2,223
|
|
Interest expense
|
|
72
|
|
|
—
|
|
|
—
|
|
|||
Current income taxes
|
|
165
|
|
|
318
|
|
|
(121
|
)
|
|||
Cash exploration expenses
|
|
38
|
|
|
44
|
|
|
20
|
|
|||
Changes in operating assets and liabilities
|
|
(143
|
)
|
|
(103
|
)
|
|
202
|
|
|||
Other, net
|
|
45
|
|
|
(2
|
)
|
|
(28
|
)
|
|||
EBITDAX
|
|
$
|
2,548
|
|
|
$
|
2,733
|
|
|
$
|
2,296
|
|
|
Conventional
|
|
Unconventional
|
|
Other
|
|
Total Capital Investments
|
||||||||||||||||||||
|
Primary
|
|
Waterflood
|
|
Steamflood
|
|
Total
|
|
Primary
|
|
|
||||||||||||||||
Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
San Joaquin
|
$
|
280
|
|
|
$
|
129
|
|
|
$
|
381
|
|
|
$
|
790
|
|
|
$
|
604
|
|
|
$
|
—
|
|
|
$
|
1,394
|
|
Los Angeles
|
3
|
|
|
466
|
|
|
—
|
|
|
469
|
|
|
—
|
|
|
—
|
|
|
469
|
|
|||||||
Ventura
|
82
|
|
|
13
|
|
|
8
|
|
|
103
|
|
|
1
|
|
|
—
|
|
|
104
|
|
|||||||
Sacramento
|
14
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
1
|
|
|
—
|
|
|
15
|
|
|||||||
Basin Total
|
379
|
|
|
608
|
|
|
389
|
|
|
1,376
|
|
|
606
|
|
|
—
|
|
|
1,982
|
|
|||||||
Exploration and Other
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
107
|
|
|
107
|
|
|||||||
Total
|
$
|
379
|
|
|
$
|
608
|
|
|
$
|
389
|
|
|
$
|
1,376
|
|
|
$
|
606
|
|
|
$
|
107
|
|
|
$
|
2,089
|
|
|
|
Payments Due by Year
|
||||||||||||||||||
|
|
Total
|
|
2015
|
|
2016 and 2017
|
|
2018 and 2019
|
|
2020 and thereafter
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
On-Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt (Note 5)
(a)
|
|
$
|
6,360
|
|
|
$
|
—
|
|
|
$
|
200
|
|
|
$
|
1,160
|
|
|
$
|
5,000
|
|
Other long-term liabilities
(b)
|
|
147
|
|
|
6
|
|
|
19
|
|
|
16
|
|
|
106
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Off-Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating leases
|
|
125
|
|
|
13
|
|
|
28
|
|
|
26
|
|
|
58
|
|
|||||
Purchase obligations
(c)
|
|
364
|
|
|
70
|
|
|
79
|
|
|
204
|
|
|
11
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total
|
|
$
|
6,996
|
|
|
$
|
89
|
|
|
$
|
326
|
|
|
$
|
1,406
|
|
|
$
|
5,175
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Excludes interest on the debt. As of December 31, 2014, interest on long-term debt totaling $2.4 billion is payable in the following years (in millions): 2015 - $312, 2016 and 2017 - $620, 2018 and 2019 - $608, 2020 and thereafter - $825. The calculation of interest payable on the variable interest debt assumes the interest rate at December 31, 2014 to be the applicable interest rate for the entire term. In performing the calculation, the Revolving Credit Facility borrowings outstanding at December 31, 2014 of $360 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 approximately 5%.
|
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)
|
||||||||||
2015
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2016
|
|
—
|
|
|
100
|
|
|
100
|
|
|||
2017
|
|
—
|
|
|
100
|
|
|
100
|
|
|||
2018
|
|
—
|
|
|
100
|
|
|
100
|
|
|||
2019
|
|
—
|
|
|
1,060
|
|
|
1,060
|
|
|||
Thereafter
|
|
5,000
|
|
|
—
|
|
|
5,000
|
|
|||
Total
|
|
$
|
5,000
|
|
|
$
|
1,360
|
|
|
$
|
6,360
|
|
Weighted-average interest rate
|
|
5.63
|
%
|
|
2.24
|
%
|
|
4.9
|
%
|
|||
Fair Value
|
|
$
|
4,285
|
|
|
$
|
1,360
|
|
|
$
|
5,645
|
|
•
|
commodity pricing;
|
•
|
vulnerability to economic downturns and adverse developments in our business due to our debt;
|
•
|
insufficiency of our operating cash flow to fund planned capital investments;
|
•
|
inability to implement our capital investment program profitably or at all;
|
•
|
compliance with regulations or changes in regulations and the ability to obtain government permits and approvals;
|
•
|
uncertainties associated with drilling for and producing oil and natural gas;
|
•
|
tax law changes;
|
•
|
competition for oilfield equipment, services, qualified personnel and acquisitions;
|
•
|
the subjective nature of estimates of proved reserves and related future net cash flows;
|
•
|
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;
|
•
|
risks related to our acquisition activities;
|
•
|
catastrophic events for which we may be uninsured or underinsured;
|
•
|
cyber attacks;
|
•
|
operational issues that restrict market access; and
|
•
|
uncertainties related to the Spin-off, the agreements related thereto and the anticipated effects of restructuring or reorganizing our business.
|
ITEM 8
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
|
|
|
|
|
/s/ KPMG LLP
|
|
|
|
|
|
|
||||
|
|
|
|
|
|
||||
|
|
2014
|
|
2013
|
|
||||
|
|
|
|
|
|
||||
CURRENT ASSETS
|
|
|
|
|
|
||||
|
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
14
|
|
|
$
|
—
|
|
|
Trade receivables, net
|
|
308
|
|
|
30
|
|
|
||
Inventories
|
|
71
|
|
|
75
|
|
|
||
Other current assets
|
|
308
|
|
|
149
|
|
|
||
Total current assets
|
|
701
|
|
|
254
|
|
|
||
PROPERTY, PLANT AND EQUIPMENT
|
|
20,536
|
|
|
20,972
|
|
|
||
Accumulated depreciation, depletion and amortization
|
|
(8,851
|
)
|
|
(6,964
|
)
|
|
||
|
|
11,685
|
|
|
14,008
|
|
|
||
|
|
|
|
|
|
||||
OTHER ASSETS
|
|
111
|
|
|
35
|
|
|
||
|
|
|
|
|
|
||||
TOTAL ASSETS
|
|
$
|
12,497
|
|
|
$
|
14,297
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
REVENUES
|
|
|
|
|
|
|
||||||
Oil and natural gas sales to related parties
|
|
$
|
2,617
|
|
|
$
|
4,054
|
|
|
$
|
3,878
|
|
Oil and natural gas sales to third parties
|
|
1,406
|
|
|
85
|
|
|
89
|
|
|||
Other revenue
|
|
150
|
|
|
145
|
|
|
106
|
|
|||
|
|
4,173
|
|
|
4,284
|
|
|
4,073
|
|
|||
COSTS AND OTHER DEDUCTIONS
|
|
|
|
|
|
|
||||||
Production costs
|
|
1,023
|
|
|
960
|
|
|
1,219
|
|
|||
Selling, general and administrative expenses
|
|
336
|
|
|
292
|
|
|
273
|
|
|||
Depreciation, depletion and amortization
|
|
1,198
|
|
|
1,144
|
|
|
926
|
|
|||
Asset impairments
|
|
3,402
|
|
|
—
|
|
|
29
|
|
|||
Taxes other than on income
|
|
217
|
|
|
185
|
|
|
167
|
|
|||
Exploration expense
|
|
139
|
|
|
116
|
|
|
148
|
|
|||
Interest and debt expense, net
|
|
72
|
|
|
—
|
|
|
—
|
|
|||
Other expenses
|
|
207
|
|
|
140
|
|
|
130
|
|
|||
|
|
6,594
|
|
|
2,837
|
|
|
2,892
|
|
|||
|
|
|
|
|
|
|
||||||
INCOME / (LOSS) BEFORE INCOME TAXES
|
|
(2,421
|
)
|
|
1,447
|
|
|
1,181
|
|
|||
Income tax (expense) / benefit
|
|
987
|
|
|
(578
|
)
|
|
(482
|
)
|
|||
NET INCOME / (LOSS)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
|
|
|
|
|
|
|
||||||
Net income / (loss) per share of common stock
|
|
|
|
|
|
|
||||||
Basic
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
$
|
1.80
|
|
Diluted
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
$
|
1.80
|
|
|
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
Net income / (loss)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
Other comprehensive income (loss) items:
|
|
|
|
|
|
|
||||||
Unrealized (losses) gains on derivatives
(a)
|
|
(2
|
)
|
|
(2
|
)
|
|
3
|
|
|||
Pension and postretirement (losses) gains
(b)
|
|
(1
|
)
|
|
27
|
|
|
2
|
|
|||
Reclassification to income of realized losses (gains) on derivatives
(c)
|
|
3
|
|
|
(2
|
)
|
|
—
|
|
|||
Other comprehensive income, net of tax
|
|
—
|
|
|
23
|
|
|
5
|
|
|||
Comprehensive income / (loss)
|
|
$
|
(1,434
|
)
|
|
$
|
892
|
|
|
$
|
704
|
|
(a)
|
Net of tax of $1, $1 and $(1) in 2014, 2013, and 2012, respectively.
|
(b)
|
Net of tax of $(1), $(16) and $(1) in 2014, 2013 and 2012, respectively. See Note 14, Retirement and Postretirement Benefit Plans, for additional information.
|
(c)
|
Net of tax of $(2), $1 and zero in 2014, 2013 and 2012, respectively.
|
|
Common Stock
|
|
Additional Paid-in Capital
|
|
Accumulated Deficit
|
|
Accumulated Other
Comprehensive
Income (Loss)
|
|
Net Parent
Company
Investment
|
|
Total Equity/Net Investment
|
||||||||||||
|
(in millions)
|
||||||||||||||||||||||
Balance, December 31, 2011
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(52
|
)
|
|
$
|
8,676
|
|
|
$
|
8,624
|
|
Net income / (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
699
|
|
|
699
|
|
||||||
Other comprehensive loss, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
5
|
|
||||||
Net contributions from Occidental
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
532
|
|
|
532
|
|
||||||
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
|
)
|
||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
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
|
|
(a)
|
Net income of $683 million related to operations from January 1, 2014 through the spin-off date of November 30, 2014 and 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.
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
CASH FLOW FROM OPERATING ACTIVITIES
|
|
|
|
|
||||||||
Net income / (loss)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
Adjustments to reconcile net income / (loss) to net cash provided by
operating activities:
|
|
|
|
|
|
|
||||||
Depreciation, depletion and amortization
|
|
1,198
|
|
|
1,144
|
|
|
926
|
|
|||
Asset impairments
|
|
3,402
|
|
|
—
|
|
|
29
|
|
|||
Deferred income tax expense / (benefit)
|
|
(1,152
|
)
|
|
260
|
|
|
603
|
|
|||
Other noncash charges to income
|
|
113
|
|
|
29
|
|
|
40
|
|
|||
Dry hole expenses
|
|
101
|
|
|
72
|
|
|
128
|
|
|||
Changes in operating assets and liabilities, net
|
|
|
|
|
|
|
||||||
(Increase) decrease in trade receivables, net
|
|
146
|
|
|
(8
|
)
|
|
20
|
|
|||
(Increase) decrease in inventories
|
|
2
|
|
|
8
|
|
|
(23
|
)
|
|||
(Increase) decrease in other current assets
|
|
(133
|
)
|
|
2
|
|
|
(49
|
)
|
|||
Increase (decrease) in accounts payable and other current liabilities
|
|
128
|
|
|
100
|
|
|
(150
|
)
|
|||
Net cash provided by operating activities
|
|
2,371
|
|
|
2,476
|
|
|
2,223
|
|
|||
|
|
|
|
|
|
|
||||||
CASH FLOW FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
||||||
Capital investments
|
|
(2,020
|
)
|
|
(1,669
|
)
|
|
(2,331
|
)
|
|||
Acquisitions and other
|
|
(292
|
)
|
|
(44
|
)
|
|
(424
|
)
|
|||
Net cash used by investing activities
|
|
(2,312
|
)
|
|
(1,713
|
)
|
|
(2,755
|
)
|
|||
|
|
|
|
|
|
|
||||||
CASH FLOW FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
||||||
(Distributions to) contributions from Occidental, net
|
|
(335
|
)
|
|
(763
|
)
|
|
532
|
|
|||
Dividends to Occidental
|
|
(6,000
|
)
|
|
—
|
|
|
—
|
|
|||
Issuance of senior notes
|
|
5,000
|
|
|
—
|
|
|
—
|
|
|||
Issuance of term loan
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from revolving credit facility
|
|
515
|
|
|
—
|
|
|
—
|
|
|||
Repayments of revolving credit facility
|
|
(155
|
)
|
|
—
|
|
|
—
|
|
|||
Debt issuance costs
|
|
(70
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash (used) provided by financing activities
|
|
(45
|
)
|
|
(763
|
)
|
|
532
|
|
|||
Increase in cash and cash equivalents
|
|
14
|
|
|
—
|
|
|
—
|
|
|||
Cash and cash equivalents—beginning of year
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Cash and cash equivalents—end of year
|
|
$
|
14
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
•
|
Our consolidated and combined statements of operations, comprehensive income and cash flows for the year ended December 31, 2014 consist of the stand-alone consolidated results of CRC following the Spin-off, and the consolidated and combined results of the California business from January 1, 2014, through 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 and combined balance sheet at December 31, 2014 consists of the consolidated balances of CRC, while at December 31, 2013, it consists of the combined balances of the California business.
|
•
|
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 consolidated statement of changes in equity for the years ended December 31, 2013 and 2012 consist entirely of the combined activity of the California business.
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in millions)
|
||||||||||
Balance - Beginning of Year
|
|
$
|
18
|
|
|
$
|
18
|
|
|
$
|
63
|
|
Additions to capitalized exploratory well costs pending the determination of proved reserves
|
|
3
|
|
|
46
|
|
|
62
|
|
|||
Reclassification to property, plant and equipment based on the determination of proved reserves
|
|
(8
|
)
|
|
(31
|
)
|
|
(61
|
)
|
|||
Capitalized exploratory well costs charged to expense
|
|
(9
|
)
|
|
(15
|
)
|
|
(46
|
)
|
|||
Balance - End of Year
|
|
$
|
4
|
|
|
$
|
18
|
|
|
$
|
18
|
|
|
|
For the years ended December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(in millions)
|
||||||
Beginning balance
|
|
$
|
415
|
|
|
$
|
387
|
|
Liabilities incurred - capitalized to PP&E
|
|
19
|
|
|
25
|
|
||
Liabilities settled and paid
|
|
(29
|
)
|
|
(9
|
)
|
||
Accretion expense
|
|
22
|
|
|
21
|
|
||
Acquisitions, disposition and other - changes in PP&E
|
|
26
|
|
|
(2
|
)
|
||
Revisions to estimated cash flows - changes in PP&E
|
|
(34
|
)
|
|
(7
|
)
|
||
Ending balance
|
|
$
|
419
|
|
|
$
|
415
|
|
|
|
Balance at December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(in millions)
|
||||||
Materials and supplies
|
|
$
|
66
|
|
|
$
|
73
|
|
Finished goods
|
|
5
|
|
|
2
|
|
||
Total
|
|
$
|
71
|
|
|
$
|
75
|
|
|
|
December 31,
|
||||||
|
|
2014
|
|
2013
|
||||
|
|
(in millions)
|
||||||
Revolving Credit Facility
|
|
$
|
360
|
|
|
$
|
—
|
|
Term Loan Facility
|
|
1,000
|
|
|
—
|
|
||
5% notes due 2020
|
|
1,000
|
|
|
—
|
|
||
5 1/2% notes due 2021
|
|
1,750
|
|
|
—
|
|
||
6% notes due 2024
|
|
2,250
|
|
|
—
|
|
||
Total
|
|
$
|
6,360
|
|
|
$
|
—
|
|
|
|
Amount
|
||
|
|
(in millions)
|
||
2015
|
|
$
|
13
|
|
2016
|
|
14
|
|
|
2017
|
|
14
|
|
|
2018
|
|
14
|
|
|
2019
|
|
12
|
|
|
Thereafter
|
|
58
|
|
|
Total minimum lease payments
|
|
$
|
125
|
|
|
|
December 31, 2014
|
|||||||||||||
(in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Collateral
|
|
Total
|
|||||
Commodity derivative instruments, other current assets
|
|
—
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
24
|
|
Total
|
|
—
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
24
|
|
For the years ended December 31,
|
|
United States
Federal
|
|
State
and Local
|
|
Total
|
||||||
|
|
(in millions)
|
||||||||||
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
|
|
|
|
|
|
|
|
|
||||||
2012
|
|
|
|
|
|
|
|
|
|
|||
Current
|
|
$
|
(140
|
)
|
|
$
|
19
|
|
|
$
|
(121
|
)
|
Deferred
|
|
518
|
|
|
85
|
|
|
603
|
|
|||
|
|
$
|
378
|
|
|
$
|
104
|
|
|
$
|
482
|
|
|
For the years ended
December 31,
|
|||||||
|
2014
|
|
2013
|
|
2012
|
|||
United States federal statutory tax rate
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
State income taxes, net of federal benefit
|
6
|
|
|
6
|
|
|
6
|
|
Other
|
—
|
|
|
(1
|
)
|
|
—
|
|
Effective tax rate
|
41
|
%
|
|
40
|
%
|
|
41
|
%
|
|
2014
|
|
2013
|
||||||||||||
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
|
Deferred Tax
Assets
|
|
Deferred Tax
Liabilities
|
||||||||
|
(in millions)
|
||||||||||||||
Property, plant and equipment differences
|
$
|
—
|
|
|
$
|
(2,437
|
)
|
|
$
|
—
|
|
|
$
|
(3,583
|
)
|
Postretirement benefit accruals
|
39
|
|
|
—
|
|
|
14
|
|
|
—
|
|
||||
Deferred compensation and benefits
|
62
|
|
|
—
|
|
|
60
|
|
|
—
|
|
||||
Asset retirement obligations
|
184
|
|
|
—
|
|
|
182
|
|
|
—
|
|
||||
Federal benefit of state income taxes
|
68
|
|
|
—
|
|
|
208
|
|
|
—
|
|
||||
Net operating loss carryforwards
|
64
|
|
|
—
|
|
|
8
|
|
|
—
|
|
||||
All other
|
27
|
|
|
(1
|
)
|
|
14
|
|
|
(2
|
)
|
||||
Total deferred taxes
|
$
|
444
|
|
|
$
|
(2,438
|
)
|
|
$
|
486
|
|
|
$
|
(3,585
|
)
|
|
|
Cash-Settled
|
|
Stock-Settled
|
||||||||||
|
|
RSUs (000's)
|
|
Weighted-Average Grant Date Fair Value
|
|
RSUs (000's)
|
|
Weighted-Average Grant-Date Fair Value
|
||||||
Unvested at December 31, 2013
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Granted
|
|
4,562
|
|
|
$
|
7.37
|
|
|
6,663
|
|
|
$
|
7.84
|
|
Vested
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Forfeited
|
|
(14
|
)
|
|
$
|
7.37
|
|
|
—
|
|
|
$
|
—
|
|
Unvested at December 31, 2014
|
|
4,548
|
|
|
$
|
7.37
|
|
|
6,663
|
|
|
$
|
7.84
|
|
|
Options (000's)
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Grant-Date Fair Value
|
|
Aggregate Intrinsic Value
|
|||||||
Beginning balance, December 31, 2013
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Granted
|
8,481
|
|
|
8.11
|
|
|
1.98
|
|
|
—
|
|
|||
Exercised
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Forfeited
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Expired or Canceled
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Ending balance, December 31, 2014
|
8,481
|
|
|
$
|
8.11
|
|
|
$
|
1.98
|
|
|
$
|
—
|
|
|
|
2014
|
||
Exercise price per share
|
|
$
|
8.11
|
|
Expected life (in years)
|
|
4.5
|
|
|
Expected volatility
|
|
35.4
|
%
|
|
Risk-free interest rate
|
|
1.4
|
%
|
|
Dividend yield
|
|
0.5
|
%
|
|
Grant date fair value of stock option awards granted
|
|
$
|
1.98
|
|
|
|
Common Stock
|
|
|
|
(in 000's)
|
|
Balance, December 31, 2013
|
|
—
|
|
Issued
|
|
385,640
|
|
Balance, December 31, 2014
|
|
385,640
|
|
|
Balance at December 31,
|
||||||
|
2014
|
|
2013
|
||||
|
(in millions)
|
||||||
Unrealized losses (gains) on derivatives
|
$
|
—
|
|
|
$
|
(1
|
)
|
Pension and post-retirement adjustments
(a)
|
(24
|
)
|
|
(23
|
)
|
||
Total
|
$
|
(24
|
)
|
|
$
|
(24
|
)
|
(a)
|
See Note 14 for further information.
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
|
(in millions, except per-share amounts)
|
||||||||||
Basic EPS calculation
|
|
|
|
|
|
|
||||||
Net income / (loss)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
Net income / (loss) allocated to participating securities
|
|
—
|
|
|
(14
|
)
|
|
(11
|
)
|
|||
Net income / (loss) available to common stockholders
|
|
$
|
(1,434
|
)
|
|
$
|
855
|
|
|
$
|
688
|
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding - basic
|
|
381.9
|
|
|
381.8
|
|
|
381.8
|
|
|||
Basic EPS
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
$
|
1.80
|
|
|
|
|
|
|
|
|
||||||
Diluted EPS calculation
|
|
|
|
|
|
|
||||||
Net income / (loss)
|
|
$
|
(1,434
|
)
|
|
$
|
869
|
|
|
$
|
699
|
|
Net income / (loss) allocated to participating securities
|
|
—
|
|
|
(14
|
)
|
|
(11
|
)
|
|||
Net income / (loss) available to common stockholders
|
|
$
|
(1,434
|
)
|
|
$
|
855
|
|
|
$
|
688
|
|
|
|
|
|
|
|
|
||||||
Weighted average common shares outstanding - basic
|
|
381.9
|
|
|
381.8
|
|
|
381.8
|
|
|||
Dilutive effect of potentially dilutive securities
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Weighted-average common shares outstanding - diluted
|
|
381.9
|
|
|
381.8
|
|
|
381.8
|
|
|||
Diluted EPS
|
|
$
|
(3.75
|
)
|
|
$
|
2.24
|
|
|
$
|
1.80
|
|
|
Pension
Benefits
|
|
Postretirement Benefits
|
||||||||||||
|
As of December 31,
|
||||||||||||||
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Amounts recognized in the balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Accrued liabilities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1
|
)
|
Other long-term liabilities
|
(21
|
)
|
|
(12
|
)
|
|
(68
|
)
|
|
(62
|
)
|
||||
|
$
|
(21
|
)
|
|
$
|
(12
|
)
|
|
$
|
(68
|
)
|
|
$
|
(63
|
)
|
AOCI included the following after-tax balances:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Net loss
|
$
|
22
|
|
|
$
|
19
|
|
|
$
|
2
|
|
|
$
|
4
|
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||||||||||
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
Changes in the benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Benefit obligation—beginning of year
|
$
|
103
|
|
|
$
|
108
|
|
|
$
|
63
|
|
|
$
|
74
|
|
Service cost—benefits earned during the period
|
4
|
|
|
5
|
|
|
4
|
|
|
4
|
|
||||
Interest cost on projected benefit obligation
|
4
|
|
|
3
|
|
|
2
|
|
|
3
|
|
||||
Actuarial (gain) loss
|
6
|
|
|
(2
|
)
|
|
(1
|
)
|
|
(18
|
)
|
||||
Benefits paid
|
(9
|
)
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
||||
Benefit obligation—end of year
|
$
|
108
|
|
|
$
|
103
|
|
|
$
|
68
|
|
|
$
|
63
|
|
|
|
|
|
|
|
|
|
||||||||
Changes in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Fair value of plan assets—beginning of year
|
$
|
91
|
|
|
$
|
74
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
5
|
|
|
13
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
—
|
|
|
15
|
|
|
—
|
|
|
—
|
|
||||
Benefits paid
|
(9
|
)
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
||||
Fair value of plan assets—end of year
|
$
|
87
|
|
|
$
|
91
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(Unfunded) status:
|
$
|
(21
|
)
|
|
$
|
(12
|
)
|
|
$
|
(68
|
)
|
|
$
|
(63
|
)
|
|
Accumulated
Benefit
Obligation
in Excess of
Plan Assets
|
|
Plan Assets
in Excess of
Accumulated
Benefit
Obligation
|
||||||||||||
|
As of December 31,
|
||||||||||||||
|
2014
|
|
2013
|
|
2014
|
|
2013
|
||||||||
|
(in millions)
|
||||||||||||||
Projected Benefit Obligation
|
$
|
31
|
|
|
$
|
30
|
|
|
$
|
77
|
|
|
$
|
73
|
|
Accumulated Benefit Obligation
|
$
|
26
|
|
|
$
|
25
|
|
|
$
|
62
|
|
|
$
|
58
|
|
Fair Value of Plan Assets
|
$
|
19
|
|
|
$
|
23
|
|
|
$
|
68
|
|
|
$
|
68
|
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||||||||||||||||||
|
2014
|
|
2013
|
|
2012
|
|
2014
|
|
2013
|
|
2012
|
||||||||||||
|
(in millions)
|
||||||||||||||||||||||
Net periodic benefit costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Service cost—benefits earned during the period
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
4
|
|
Interest cost on projected benefit obligation
|
4
|
|
|
3
|
|
|
4
|
|
|
2
|
|
|
3
|
|
|
3
|
|
||||||
Expected return on plan assets
|
(6
|
)
|
|
(4
|
)
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Recognized actuarial loss
|
2
|
|
|
4
|
|
|
4
|
|
|
1
|
|
|
2
|
|
|
2
|
|
||||||
Settlement cost
|
2
|
|
|
2
|
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic benefit cost
|
$
|
6
|
|
|
$
|
10
|
|
|
$
|
14
|
|
|
$
|
7
|
|
|
$
|
10
|
|
|
$
|
9
|
|
|
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
|
|
|
Fair Value Measurements at
December 31, 2013 Using
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Asset Class:
|
|
|
|
|
|
|
|
|
|
|
|
||||
Master trust investment account
(a)
|
$
|
—
|
|
|
$
|
69
|
|
|
$
|
—
|
|
|
$
|
69
|
|
Mutual funds:
|
|
|
|
|
|
|
|
|
|
|
|||||
Bond funds
|
5
|
|
|
—
|
|
|
—
|
|
|
5
|
|
||||
Blend funds
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Value funds
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Growth funds
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Guaranteed deposit account
|
—
|
|
|
—
|
|
|
9
|
|
|
9
|
|
||||
Total pension plan assets
(b)
|
$
|
14
|
|
|
$
|
69
|
|
|
$
|
9
|
|
|
$
|
92
|
|
(a)
|
Represents our investment in a master trust investment account established by Occidental. The trust investments include common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds.
|
(b)
|
Amounts exclude net payables of approximately $1 million.
|
For the years ended December 31,
|
Pension
Benefits
|
|
Postretirement
Benefits
|
||||
|
(in millions)
|
||||||
2015
|
$
|
15
|
|
|
$
|
—
|
|
2016
|
$
|
9
|
|
|
$
|
1
|
|
2017
|
$
|
8
|
|
|
$
|
1
|
|
2018
|
$
|
10
|
|
|
$
|
2
|
|
2019
|
$
|
9
|
|
|
$
|
2
|
|
2020 - 2024
|
$
|
44
|
|
|
$
|
17
|
|
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in millions)
|
||||||||||
Sales
(a)
|
$
|
2,706
|
|
|
$
|
4,174
|
|
|
$
|
3,970
|
|
Allocated costs for services provided by affiliates
|
$
|
126
|
|
|
$
|
146
|
|
|
$
|
129
|
|
Purchases
|
$
|
175
|
|
|
$
|
164
|
|
|
$
|
119
|
|
(a)
|
Amounts include related-party sales from our Elk Hills power plant of $89 million, $120 million and $92 million during 2014, 2013 and 2012, respectively. These sales are included in other revenue in the statements of operations.
|
Quarterly Financial Data
(Unaudited)
|
|
|
|
|
2014
|
|
2013
|
||||||||||||||||||||||||||||
Quarter
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||||||||||
|
|
(in millions, except per share amounts)
|
||||||||||||||||||||||||||||||
Revenues
|
|
$
|
1,121
|
|
|
$
|
1,140
|
|
|
$
|
1,092
|
|
|
$
|
820
|
|
|
$
|
1,047
|
|
|
$
|
1,051
|
|
|
$
|
1,107
|
|
|
$
|
1,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Gross profit
|
|
865
|
|
|
878
|
|
|
830
|
|
|
577
|
|
|
812
|
|
|
813
|
|
|
863
|
|
|
836
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income / (loss)
(a)
|
|
$
|
223
|
|
|
$
|
246
|
|
|
$
|
188
|
|
|
$
|
(2,091
|
)
|
|
$
|
217
|
|
|
$
|
205
|
|
|
$
|
235
|
|
|
$
|
212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Net income / (loss) per share
(b)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Basic
|
|
$
|
0.57
|
|
|
$
|
0.63
|
|
|
$
|
0.48
|
|
|
$
|
(5.47
|
)
|
|
$
|
0.56
|
|
|
$
|
0.53
|
|
|
$
|
0.61
|
|
|
$
|
0.55
|
|
Diluted
|
|
$
|
0.57
|
|
|
$
|
0.63
|
|
|
$
|
0.48
|
|
|
$
|
(5.47
|
)
|
|
$
|
0.56
|
|
|
$
|
0.53
|
|
|
$
|
0.61
|
|
|
$
|
0.55
|
|
(a)
|
For the quarter ended December 31, 2014, amount includes after-tax non-cash 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, 2011
|
337
|
|
|
130
|
|
|
41
|
|
|
—
|
|
|
508
|
|
Revisions of previous estimates
|
(44
|
)
|
|
1
|
|
|
(3
|
)
|
|
—
|
|
|
(46
|
)
|
Improved recovery
|
36
|
|
|
16
|
|
|
11
|
|
|
—
|
|
|
63
|
|
Extensions and discoveries
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Purchases of proved reserves
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(21
|
)
|
|
(9
|
)
|
|
(2
|
)
|
|
—
|
|
|
(32
|
)
|
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
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
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
|
|
Purchases of proved reserves
|
1
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
6
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(23
|
)
|
|
(11
|
)
|
|
(2
|
)
|
|
—
|
|
|
(36
|
)
|
Balance at December 31, 2014
|
340
|
|
|
163
|
|
|
48
|
|
|
—
|
|
|
551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011
|
240
|
|
|
97
|
|
|
30
|
|
|
—
|
|
|
367
|
|
December 31, 2012
|
221
|
|
|
104
|
|
|
30
|
|
|
—
|
|
|
355
|
|
December 31, 2013
|
226
|
|
|
109
|
|
|
28
|
|
|
—
|
|
|
363
|
|
December 31, 2014
(b)
|
229
|
|
|
124
|
|
|
34
|
|
|
—
|
|
|
387
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011
|
97
|
|
|
33
|
|
|
11
|
|
|
—
|
|
|
141
|
|
December 31, 2012
|
91
|
|
|
34
|
|
|
17
|
|
|
—
|
|
|
142
|
|
December 31, 2013
|
106
|
|
|
46
|
|
|
17
|
|
|
—
|
|
|
169
|
|
December 31, 2014
|
111
|
|
|
39
|
|
|
14
|
|
|
—
|
|
|
164
|
|
(a)
|
Includes proved reserves related to economic arrangements similar to PSCs of 116 MMBbl, 102 MMBbl, 98 MMBbl and 92 MMBbl at December 31, 2014, 2013, 2012 and 2011, respectively.
|
(b)
|
Approximately 11 percent of the proved developed reserves at December 31, 2014 are nonproducing.
|
(a)
|
Approximately 5 percent of the proved developed reserves at December 31, 2014 are nonproducing.
|
(a)
|
Approximately 9 percent of the proved developed reserves at December 31, 2014 are nonproducing.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
(b)
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
|||||
|
(in MMBoe
(a)
)
|
|||||||||||||
PROVED DEVELOPED AND UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2011
|
537
|
|
|
134
|
|
|
52
|
|
|
6
|
|
|
729
|
|
Revisions of previous estimates
|
(83
|
)
|
|
—
|
|
|
(4
|
)
|
|
(1
|
)
|
|
(88
|
)
|
Improved recovery
|
65
|
|
|
16
|
|
|
13
|
|
|
—
|
|
|
94
|
|
Extensions and discoveries
|
5
|
|
|
—
|
|
|
1
|
|
|
1
|
|
|
7
|
|
Purchases of proved reserves
|
1
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|
26
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(39
|
)
|
|
(9
|
)
|
|
(4
|
)
|
|
(2
|
)
|
|
(54
|
)
|
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
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
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
|
|
Purchases of proved reserves
|
1
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
6
|
|
Sales of proved reserves
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production
|
(41
|
)
|
|
(11
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
(58
|
)
|
Balance at December 31, 2014
|
525
|
|
|
166
|
|
|
58
|
|
|
19
|
|
|
768
|
|
|
|
|
|
|
|
|
|
|
|
|||||
PROVED DEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011
|
372
|
|
|
99
|
|
|
40
|
|
|
6
|
|
|
517
|
|
December 31, 2012
|
341
|
|
|
105
|
|
|
38
|
|
|
24
|
|
|
508
|
|
December 31, 2013
|
349
|
|
|
110
|
|
|
35
|
|
|
20
|
|
|
514
|
|
December 31, 2014
(c)
|
367
|
|
|
126
|
|
|
41
|
|
|
18
|
|
|
552
|
|
|
|
|
|
|
|
|
|
|
|
|||||
PROVED UNDEVELOPED RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011
|
165
|
|
|
35
|
|
|
12
|
|
|
—
|
|
|
212
|
|
December 31, 2012
|
145
|
|
|
36
|
|
|
20
|
|
|
5
|
|
|
206
|
|
December 31, 2013
|
162
|
|
|
48
|
|
|
20
|
|
|
—
|
|
|
230
|
|
December 31, 2014
|
158
|
|
|
40
|
|
|
17
|
|
|
1
|
|
|
216
|
|
(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 2014, the average prices of Brent oil and NYMEX natural gas were $99.51 per Bbl and $4.34 per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 23 to 1.
|
(b)
|
Includes proved reserves related to economic arrangements similar to PSCs of 116 MMBbl, 102 MMBbl, 98 MMBbl and 92 MMBbl at December 31, 2014, 2013, 2012 and 2011, respectively.
|
(c)
|
Approximately 10 percent of the proved developed reserves at December 31, 2014 are nonproducing.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
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
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
December 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
14,359
|
|
|
$
|
1,974
|
|
|
$
|
1,327
|
|
|
$
|
286
|
|
|
$
|
17,946
|
|
Unproved properties
|
650
|
|
|
97
|
|
|
96
|
|
|
97
|
|
|
940
|
|
|||||
Total capitalized costs
(a)
|
15,009
|
|
|
2,071
|
|
|
1,423
|
|
|
383
|
|
|
18,886
|
|
|||||
Accumulated depreciation, depletion and amortization
(b)
|
(4,905
|
)
|
|
(424
|
)
|
|
(276
|
)
|
|
(95
|
)
|
|
(5,700
|
)
|
|||||
Net capitalized costs
|
$
|
10,104
|
|
|
$
|
1,647
|
|
|
$
|
1,147
|
|
|
$
|
288
|
|
|
$
|
13,186
|
|
(a)
|
Includes acquisition costs, development costs and asset retirement obligations.
|
(b)
|
Includes accumulated valuation allowance for total unproved properties of $715 million, $27 million and $20 million at December 31, 2014, 2013 and 2012, respectively.
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
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
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Property acquisition costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved properties
|
$
|
83
|
|
|
$
|
8
|
|
|
$
|
—
|
|
|
$
|
274
|
|
|
$
|
365
|
|
Unproved properties
|
30
|
|
|
1
|
|
|
—
|
|
|
10
|
|
|
41
|
|
|||||
Exploration costs
|
153
|
|
|
4
|
|
|
1
|
|
|
1
|
|
|
159
|
|
|||||
Development costs
|
1,721
|
|
|
348
|
|
|
124
|
|
|
26
|
|
|
2,219
|
|
|||||
Costs incurred
|
$
|
1,987
|
|
|
$
|
361
|
|
|
$
|
125
|
|
|
$
|
311
|
|
|
$
|
2,784
|
|
|
|
|
|
|
|
|
|
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
(in millions)
|
||||||||||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2014
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
(a)
|
$
|
2,735
|
|
|
$
|
956
|
|
|
$
|
244
|
|
|
$
|
88
|
|
|
$
|
4,023
|
|
Production costs
(b)
|
579
|
|
|
330
|
|
|
89
|
|
|
25
|
|
|
1,023
|
|
|||||
General and administrative expenses
(c)
|
76
|
|
|
42
|
|
|
11
|
|
|
11
|
|
|
140
|
|
|||||
Other operating expenses
(d)
|
44
|
|
|
21
|
|
|
16
|
|
|
5
|
|
|
86
|
|
|||||
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)
|
125
|
|
|
—
|
|
|
9
|
|
|
5
|
|
|
139
|
|
|||||
Pretax income
|
(370
|
)
|
|
(744
|
)
|
|
(405
|
)
|
|
(634
|
)
|
|
(2,153
|
)
|
|||||
Income tax benefit
|
(151
|
)
|
|
(304
|
)
|
|
(165
|
)
|
|
(259
|
)
|
|
(879
|
)
|
|||||
Results of operations
|
$
|
(219
|
)
|
|
$
|
(440
|
)
|
|
$
|
(240
|
)
|
|
$
|
(375
|
)
|
|
$
|
(1,274
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2013
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
(a)
|
$
|
2,823
|
|
|
$
|
968
|
|
|
$
|
259
|
|
|
$
|
89
|
|
|
$
|
4,139
|
|
Production costs
(b)
|
552
|
|
|
306
|
|
|
75
|
|
|
27
|
|
|
960
|
|
|||||
General and administrative expenses
|
74
|
|
|
36
|
|
|
9
|
|
|
13
|
|
|
132
|
|
|||||
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
|
1,122
|
|
|
466
|
|
|
77
|
|
|
(68
|
)
|
|
1,597
|
|
|||||
Income tax expense / (benefit)
|
447
|
|
|
185
|
|
|
31
|
|
|
(27
|
)
|
|
636
|
|
|||||
Results of operations
|
$
|
675
|
|
|
$
|
281
|
|
|
$
|
46
|
|
|
$
|
(41
|
)
|
|
$
|
961
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2012
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenues
(a)
|
$
|
2,738
|
|
|
$
|
921
|
|
|
$
|
262
|
|
|
$
|
46
|
|
|
$
|
3,967
|
|
Production costs
(b)
|
790
|
|
|
331
|
|
|
81
|
|
|
17
|
|
|
1,219
|
|
|||||
General and administrative expenses
|
73
|
|
|
44
|
|
|
10
|
|
|
7
|
|
|
134
|
|
|||||
Other operating expenses
(d)
|
26
|
|
|
—
|
|
|
2
|
|
|
2
|
|
|
30
|
|
|||||
Depreciation, depletion and amortization
|
724
|
|
|
79
|
|
|
61
|
|
|
44
|
|
|
908
|
|
|||||
Taxes other than on income
|
114
|
|
|
37
|
|
|
9
|
|
|
7
|
|
|
167
|
|
|||||
Asset impairments
|
19
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
29
|
|
|||||
Exploration expenses
|
112
|
|
|
29
|
|
|
1
|
|
|
6
|
|
|
148
|
|
|||||
Pretax income
|
880
|
|
|
391
|
|
|
98
|
|
|
(37
|
)
|
|
1,332
|
|
|||||
Income tax expense / (benefit)
|
359
|
|
|
160
|
|
|
40
|
|
|
(15
|
)
|
|
544
|
|
|||||
Results of operations
|
$
|
521
|
|
|
$
|
231
|
|
|
$
|
58
|
|
|
$
|
(22
|
)
|
|
$
|
788
|
|
(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)
|
Includes unusual and infrequent costs related to Spin-off and transition related costs of $6 million in total.
|
(d)
|
For 2014, the total amounts include unusual and infrequent costs related to rig termination charges and Spin-off and transition related costs totaling $55 million. For 2012, the total amounts include rig termination charges of $12 million.
|
(e)
|
At year end 2014, we recorded pre-tax asset impairment charges of $3.4 billion on certain proved and unproved properties in the San Joaquin, Los Angeles, Ventura and Sacramento basins.
|
(f)
|
Includes $21 million of unusual and infrequent costs related to dry holes and seismic charges.
|
|
|
San Joaquin
Basin
|
|
Los Angeles
Basin
|
|
Ventura
Basin
|
|
Sacramento
Basin
|
|
Total
|
||||||||||
|
|
(in millions)
|
||||||||||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Revenue from each barrel of oil equivalent ($/Boe)
(a)(b)
|
|
$
|
67.32
|
|
|
$
|
88.96
|
|
|
$
|
75.73
|
|
|
$
|
26.11
|
|
|
$
|
69.40
|
|
Production costs
|
|
14.24
|
|
|
30.71
|
|
|
27.62
|
|
|
7.42
|
|
|
17.64
|
|
|||||
General and administrative expenses
|
|
1.87
|
|
|
3.91
|
|
|
3.41
|
|
|
3.26
|
|
|
2.41
|
|
|||||
Other operating expenses
|
|
1.13
|
|
|
1.95
|
|
|
4.97
|
|
|
1.48
|
|
|
1.52
|
|
|||||
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
(c)
|
|
31.14
|
|
|
103.29
|
|
|
135.63
|
|
|
174.78
|
|
|
58.66
|
|
|||||
Exploration expenses
|
|
3.07
|
|
|
—
|
|
|
2.79
|
|
|
1.48
|
|
|
2.40
|
|
|||||
Pretax income
|
|
(9.09
|
)
|
|
(69.23
|
)
|
|
(125.69
|
)
|
|
(188.13
|
)
|
|
(37.13
|
)
|
|||||
Income tax benefit
|
|
(3.71
|
)
|
|
(28.29
|
)
|
|
(51.21
|
)
|
|
(76.85
|
)
|
|
(15.16
|
)
|
|||||
Results of operations
|
|
$
|
(5.38
|
)
|
|
$
|
(40.94
|
)
|
|
$
|
(74.48
|
)
|
|
$
|
(111.28
|
)
|
|
$
|
(21.97
|
)
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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
|
|
14.05
|
|
|
31.98
|
|
|
22.96
|
|
|
6.70
|
|
|
17.10
|
|
|||||
General and administrative expenses
|
|
1.88
|
|
|
3.76
|
|
|
2.75
|
|
|
3.23
|
|
|
2.35
|
|
|||||
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
|
|
28.58
|
|
|
48.72
|
|
|
23.58
|
|
|
(16.89
|
)
|
|
28.44
|
|
|||||
Income tax expense / (benefit)
|
|
11.38
|
|
|
19.34
|
|
|
9.49
|
|
|
(6.70
|
)
|
|
11.33
|
|
|||||
Results of operations
|
|
$
|
17.20
|
|
|
$
|
29.38
|
|
|
$
|
14.09
|
|
|
$
|
(10.19
|
)
|
|
$
|
17.11
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
FOR THE YEAR ENDED DECEMBER 31, 2012
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Revenue from each barrel of oil equivalent ($/Boe)
(a)(b)
|
|
$
|
69.30
|
|
|
$
|
102.45
|
|
|
$
|
81.85
|
|
|
$
|
20.09
|
|
|
$
|
73.48
|
|
Production costs
|
|
20.00
|
|
|
36.82
|
|
|
25.30
|
|
|
7.42
|
|
|
22.58
|
|
|||||
General and administrative expenses
|
|
1.85
|
|
|
4.89
|
|
|
3.12
|
|
|
3.06
|
|
|
2.48
|
|
|||||
Other operating expenses
|
|
0.66
|
|
|
—
|
|
|
0.62
|
|
|
0.88
|
|
|
0.56
|
|
|||||
Depreciation, depletion and amortization
|
|
18.33
|
|
|
8.79
|
|
|
19.06
|
|
|
19.21
|
|
|
16.82
|
|
|||||
Taxes other than on income
|
|
2.89
|
|
|
4.12
|
|
|
2.81
|
|
|
3.06
|
|
|
3.09
|
|
|||||
Asset impairments
|
|
0.48
|
|
|
1.11
|
|
|
—
|
|
|
—
|
|
|
0.54
|
|
|||||
Exploration expenses
|
|
2.83
|
|
|
3.23
|
|
|
0.31
|
|
|
2.62
|
|
|
2.74
|
|
|||||
Pretax income
|
|
22.26
|
|
|
43.49
|
|
|
30.63
|
|
|
(16.16
|
)
|
|
24.67
|
|
|||||
Income tax expense / (benefit)
|
|
9.09
|
|
|
17.80
|
|
|
12.50
|
|
|
(6.55
|
)
|
|
10.08
|
|
|||||
Results of operations
|
|
$
|
13.17
|
|
|
$
|
25.69
|
|
|
$
|
18.13
|
|
|
$
|
(9.61
|
)
|
|
$
|
14.59
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas to 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 2014, the average prices of Brent oil and NYMEX natural gas were $99.51 per Bbl and $4.34 per Mcf, respectively, resulting in an oil to gas price ratio of approximately 23 to 1.
|
(b)
|
Revenues are net of royalty payments.
|
(c)
|
At year end 2014, we recorded pre-tax asset impairment charges of $3.4 billion 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,
|
||||||||||
|
2014
|
|
2013
|
|
2012
|
||||||
|
(in millions)
|
||||||||||
Beginning of year
|
$
|
9,223
|
|
|
$
|
9,073
|
|
|
$
|
10,347
|
|
Sales and transfers of oil and natural gas produced, net of production costs and other operating expenses
|
(2,658
|
)
|
|
(3,082
|
)
|
|
(2,695
|
)
|
|||
Net change in prices received per Bbl, net of production costs and other operating expenses
|
567
|
|
|
575
|
|
|
(1,431
|
)
|
|||
Extensions, discoveries and improved recovery, net of future production and development costs
|
2,593
|
|
|
1,914
|
|
|
1,897
|
|
|||
Change in estimated future development costs
|
75
|
|
|
(688
|
)
|
|
(1,526
|
)
|
|||
Revisions of quantity estimates
|
(925
|
)
|
|
(62
|
)
|
|
(1,405
|
)
|
|||
Previously estimated development costs incurred during the period
|
1,440
|
|
|
1,185
|
|
|
1,039
|
|
|||
Accretion of discount
|
1,324
|
|
|
1,292
|
|
|
1,512
|
|
|||
Net change in income taxes
|
(468
|
)
|
|
(95
|
)
|
|
984
|
|
|||
Purchases and sales of reserves in place, net
|
125
|
|
|
4
|
|
|
221
|
|
|||
Changes in production rates and other
|
(468
|
)
|
|
(893
|
)
|
|
130
|
|
|||
Net change
|
1,605
|
|
|
150
|
|
|
(1,274
|
)
|
|||
End of year
|
$
|
10,828
|
|
|
$
|
9,223
|
|
|
$
|
9,073
|
|
|
2014
|
|
2013
|
|
2012
|
|||
Oil (MBbl/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
64
|
|
|
58
|
|
|
58
|
|
Los Angeles Basin
(c)
|
29
|
|
|
26
|
|
|
24
|
|
Ventura Basin
|
6
|
|
|
6
|
|
|
6
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
99
|
|
|
90
|
|
|
88
|
|
|
|
|
|
|
|
|
|
|
NGLs (MBbl/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
18
|
|
|
19
|
|
|
16
|
|
Los Angeles Basin
|
—
|
|
|
—
|
|
|
—
|
|
Ventura Basin
|
1
|
|
|
1
|
|
|
1
|
|
Sacramento Basin
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
19
|
|
|
20
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d)
|
|
|
|
|
|
|
|
|
San Joaquin Basin
(b)
|
180
|
|
|
182
|
|
|
204
|
|
Los Angeles Basin
(c)
|
1
|
|
|
2
|
|
|
3
|
|
Ventura Basin
|
11
|
|
|
11
|
|
|
12
|
|
Sacramento Basin
|
54
|
|
|
65
|
|
|
37
|
|
Total
|
246
|
|
|
260
|
|
|
256
|
|
|
|
|
|
|
|
|||
Total Production (MBoe/d)
(a)
|
159
|
|
|
154
|
|
|
148
|
|
(a)
|
Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas to 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 2014, the average prices of Brent oil and NYMEX natural gas were $99.51 per Bbl and $4.34 per Mcf, respectively, resulting in an oil to gas price ratio of approximately 23 to 1.
|
(b)
|
Includes daily production from Elk Hills field of 25 MBbl oil, 16 MBbl NGLs and 136 MMcf natural gas in 2014; 26 MBbl oil, 18 MBbl NGLs and 145 MMcf natural gas in 2013; and 29 MBbl oil, 15 MBbl NGLs and 168 MMcf natural gas in 2012.
|
(c)
|
Includes daily production from Wilmington field of 25 MBbl Oil in 2014; 22 MBbl Oil in 2013; and 21 MBbl Oil in 2012.
|
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 4.2 to the Registrant’s Registration Statement on Form S-8 filed November 26, 2014 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
|
|
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).
|
|
|
|
4.4
|
|
Form of 5% Senior Note due 2020 (included in Exhibit 4.2)
|
|
|
|
4.5
|
|
Form of 5 1/2% Senior Note due 2021 (included in Exhibit 4.2)
|
|
|
|
4.6
|
|
Form of 6% Senior Note due 2024 (included in Exhibit 4.2)
|
|
|
|
10.1
|
|
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).
|
|
|
|
10.2
|
|
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).
|
|
|
|
10.19
|
|
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).
|
|
|
|
10.20
|
|
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).
|
|
|
|
10.21
|
|
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).
|
|
|
|
10.22
|
|
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).
|
|
|
|
10.23
|
|
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).
|
|
|
|
10.24
|
|
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).
|
|
|
|
10.25
|
|
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).
|
|
|
|
10.26
|
|
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).
|
|
|
|
10.27
|
|
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).
|
|
|
|
10.30
|
|
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).
|
|
|
|
10.31
|
|
Form of 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).
|
|
|
|
10.32
|
|
Form of California Resources Corporation Supplemental Retirement Plan II (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).
|
|
|
|
10.33
|
|
Form of California Resources Corporation Deferred Compensation Plan (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).
|
|
|
|
10.34
|
|
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).
|
|
|
|
10.35*
|
|
First Amendment to 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.
|
|
|
|
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*
|
|
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 Process Review of the Estimated Future Proved Reserves and Income Attributable to Certain Fee, Leasehold and Royalty Interests and Certain Economic Interests Derived Through Certain Production Sharing Type Contracts as of December 31, 2014.
|
|
|
|
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 26, 2015
|
By:
|
/s/ Todd A. Stevens
|
|
|
Todd A. Stevens
|
|
|
President
|
|
|
and Chief Executive Officer
|
|
|
|
Title
|
Date
|
|
|
|
|
|
|
/s/ Todd A. Stevens
|
|
President,
|
February 26, 2015
|
|
Todd A. Stevens
|
|
Chief Executive Officer and Director
|
|
|
|
|
|
|
|
/s/ Marshall D. Smith
|
|
Senior Executive Vice President and
|
February 26, 2015
|
|
Marshall D. Smith
|
|
Chief Financial Officer
|
|
|
|
|
|
|
|
/s/ Roy Pineci
|
|
Executive Vice President - Finance and
|
February 26, 2015
|
|
Roy Pineci
|
|
Principal Accounting Officer
|
|
|
|
|
|
|
|
/s/ William E. Albrecht
|
|
Executive Chairman of the Board
|
February 26, 2015
|
|
William E. Albrecht
|
|
||
|
|
|
|
|
|
/s/ Justin A. Gannon
|
|
Director
|
February 26, 2015
|
|
Justin A. Gannon
|
|
||
|
|
|
|
|
|
/s/ Ronald L. Havner
|
|
Director
|
February 26, 2015
|
|
Ronald L. Havner
|
|
||
|
|
|
|
|
|
/s/ Harold M. Korell
|
|
Director
|
February 26, 2015
|
|
Harold M. Korell
|
|
||
|
|
|
|
|
|
/s/ Richard W. Moncrief
|
|
Director
|
February 26, 2015
|
|
Richard W. Moncrief
|
|
||
|
|
|
|
|
|
/s/ Avedick B. Poladian
|
|
Director
|
February 26, 2015
|
|
Avedick B. Poladian
|
|
||
|
|
|
|
|
|
/s/ Robert V. Sinnott
|
|
Director
|
February 26, 2015
|
|
Robert V. Sinnott
|
|
||
|
|
|
|
|
|
/s/ Timothy J. Sloan
|
|
Director
|
|
|
Timothy J. Sloan
|
|
February 26, 2015
|
10.35
|
|
First Amendment to 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.
|
|
|
|
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
|
|
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 Process Review of the Estimated Future Proved Reserves and Income Attributable to Certain Fee, Leasehold and Royalty Interests and Certain Economic Interests Derived Through Certain Production Sharing Type Contracts as of December 31, 2014.
|
|
|
|
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.
|
(a)
|
Leverage Ratio
. The Borrower will not permit the Leverage Ratio as of the last day of each fiscal quarter of the Borrower to be greater than the ratio applicable to such fiscal quarter set forth below:
|
Fiscal Quarter Ending
|
Leverage Ratio
|
March 31, 2015
|
4:50 to 1.00
|
June 30, 2015
|
4:75 to 1.00
|
September 30, 2015
|
6.25 to 1.00
|
December 31, 2015
|
8.25 to 1.00
|
March 31, 2016
|
8.00 to 1.00
|
June 30, 2016
|
7.25 to 1.00
|
September 30, 2016
|
6.75 to 1.00
|
December 31, 2016
|
6.25 to 1.00
|
Thereafter
|
4.50 to 1.00
|
(b)
|
Interest Expense Ratio
. Other than for the fiscal quarter ending December 31, 2015, the Borrower will not permit the Interest Expense Ratio as of the last day of each fiscal quarter of the Borrower to be less than 2.50 to 1.00. As of December 31, 2015, the Borrower will not permit the Interest Expense Ratio to be less than 2.25 to 1.00.
|
(c)
|
Asset Coverage Ratio
. As of the last day of each fiscal quarter of the Borrower (other than during a Borrowing Base Trigger Period when a Borrowing Base has been established), the Borrower will not permit the Asset Coverage Ratio to be less than the ratio applicable to such fiscal quarter set forth below:
|
Fiscal Quarter Ending
|
Asset Coverage Ratio
|
March 31, 2015 through December 31, 2016
|
1.05 to 1.00
|
Thereafter
|
1.50 to 1.00
|
(d)
|
Liquidity
. As of any date of determination, the Borrower will not permit Liquidity to be less than $750,000,000.
|
BORROWER:
|
|
CALIFORNIA RESOURCES CORPORATION
|
|
|
|
|
|
|
|
|
By: /s/ Marshall D. Smith
|
|
|
Name: Marshall D. Smith
|
|
|
Title: Senior Executive Vice President and Chief Financial Officer
|
|
|
|
GUARANTORS:
|
|
|
|
|
California Heavy Oil, Inc.
|
|
|
California Resources Long Beach, Inc.
|
|
|
California Resources Petroleum Corporation
|
|
|
California Resources Production Corporation
|
|
|
California Resources Tidelands, Inc.
|
|
|
Southern San Joaquin Production, Inc.
|
|
|
Thums Long Beach Company
|
|
|
|
|
|
By: /s/ Michael L. Preston
|
|
|
Name: Michael L. Preston
|
|
|
Title: Executive Vice President, General Counsel and Corporate Secretary
|
|
|
|
|
|
California Resources Wilmington, LLC
|
|
|
|
|
|
By: /s/ Michael L. Preston
|
|
|
Name: Michael L. Preston
|
|
|
Title: Executive Vice President, General Counsel and Corporate Secretary of California Resources Tidelands, Inc., its Sole Member
|
|
|
|
|
|
CRC Marketing, Inc.
|
|
|
|
|
|
By: /s/ D. Adam Smith
|
|
|
Name: D. Adam Smith
|
|
|
Title: Assistant Secretary
|
|
|
|
|
|
Elk Hills Power, LLC
|
|
|
|
|
|
By: /s/ Michael L. Preston
|
|
|
Name: Michael L. Preston
|
|
|
Title: Executive Vice President, General Counsel and Corporate Secretary of California Resources Corporation, the Sole Member of California Resources Elk Hills, LLC, its Sole Member
|
|
|
|
|
|
|
|
|
Tidelands Oil Production Company
|
|
|
|
|
|
By: /s/ Michael L. Preston
|
|
|
Name: Michael L. Preston
|
|
|
Title: Executive Vice President, General Counsel and Corporate Secretary of California Resources Tidelands, Inc., its Managing Partner
|
|
|
|
|
|
California Resources Elk Hills, LLC
|
|
|
CRC Services, LLC
|
|
|
Socal Holding, LLC
|
|
|
|
|
|
By: /s/ Michael L. Preston
|
|
|
Name: Michael L. Preston
|
|
|
Title: Executive Vice President, General Counsel and Corporate Secretary of California Resources Corporation, its Sole Member
|
|
|
|
|
|
|
|
JPMORGAN CHASE BANK, N.A.
, as Administrative Agent, Letter of Credit Issuer, Swingline Lender, Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Dave Katz
|
|
Name: Dave Katz
|
|
Title: Executive Director
|
|
BANK OF AMERICA, N.A.
, as Syndication Agent, Letter of Credit Issuer, Swingline Lender, Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Bryan Heller
|
|
Name: Bryan Heller
|
|
Title: Director
|
|
CITIBANK, N.A.
, as Letter of Credit Issuer, Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Ivan Davey
|
|
Name: Ivan Davey
|
|
Title: Vice President
|
|
THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Kevin Sparks
|
|
Name: Kevin Sparks
|
|
Title: Vice President
|
|
U.S. BANK NATIONAL ASSOCIATION
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ John Prigge
|
|
Name: John Prigge
|
|
Title: Vice President
|
|
MORGAN STANLEY BANK, N.A.
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Dmitriy Barskiy
|
|
Name: Dmitriy Barskiy
|
|
Title: Authorized Signatory
|
|
HSBC BANK USA, NA
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Steven Smith
|
|
Name: Steven Smith
|
|
Title: Director
|
|
GOLDMAN SACHS BANK USA
, as Revolving Lender
|
|
|
|
|
|
By: /s/ Michelle Latzoni
|
|
Name: Michelle Latzoni
|
|
Title: Authorized Signatory
|
|
BANK OF NOVA SCOTIA
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Mark Sparrow
|
|
Name: Mark Sparrow
|
|
Title: Director
|
|
SOCIÉTÉ GÉNÉRALE
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Alexandre Huet
|
|
Alexandre Huet
|
|
Managing Director
|
|
|
|
And
|
|
|
|
By: /s/ Diego Medina
|
|
Diego Medina
|
|
Director
|
|
|
|
|
|
PNC BANK, NATIONAL ASSOCIATION
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Sandra Aultman
|
|
Name: Sandra Aultman
|
|
Title: Managing Director
|
|
BRANCH BANKING AND TRUST COMPANY
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ James Giordano
|
|
Name: James Giordano
|
|
Title: Vice President
|
|
THE BANK OF NEW YORK MELLON
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Mark W. Rogers
|
|
Name: Mark W. Rogers
|
|
Title: Vice President
|
|
SUMITOMO MITSUI BANKING CORPORATION
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Shuji Yabe
|
|
Name: Shuji Yabe
|
|
Title: Managing Director
|
|
INTESA SANPAOLO S.P.A., NEW YORK BRANCH
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ Katherine Hand
|
|
Name: Katherine Hand
|
|
Title: Relationship Manager
|
|
|
|
By: /s/ Francesco Di Mario
|
|
Name: Francesco Di Mario
|
|
Title: FVP & Head of Credit
|
|
KEYBANK NATIONAL ASSOCIATION
, as Revolving Lender and Term Loan Lender
|
|
|
|
|
|
By: /s/ George E. McKean
|
|
Name: George E. McKean
|
|
Title: Senior Vice President
|
|
|
|
|
EXHIBIT 12
|
|
|
Year Ended December 31,
|
|
|||||||||||||||||
|
|
2014
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|||||
Income / (loss) before income taxes
(a)
|
|
$
|
(2,421
|
)
|
|
$
|
1,447
|
|
|
$
|
1,181
|
|
|
$
|
1,641
|
|
|
$
|
1,129
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense and amortization of debt issuance costs
|
|
72
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Portion of lease rentals representative of the interest factor
|
|
3
|
|
|
4
|
|
|
4
|
|
|
3
|
|
|
3
|
|
|||||
Earnings before fixed charges
|
|
$
|
(2,346
|
)
|
|
$
|
1,451
|
|
|
$
|
1,185
|
|
|
$
|
1,644
|
|
|
$
|
1,132
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense and amortization of debt issuance costs, including capitalized interest
|
|
$
|
76
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Portion of lease rentals representative of the interest factor
|
|
3
|
|
|
4
|
|
|
4
|
|
|
3
|
|
|
3
|
|
|||||
Total fixed charges
|
|
$
|
79
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
(b)
|
|
n/a
|
|
|
363
|
|
|
296
|
|
|
548
|
|
|
377
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Insufficient coverage
|
|
$
|
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 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 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 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)) 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.
|
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
|
c.
|
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;
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2.
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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;
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3.
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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;
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4.
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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)) for the registrant and have:
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a.
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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;
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b.
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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
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c.
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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
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5.
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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):
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a.
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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
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b.
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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.
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/s/ Marshall D. Smith
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Marshall D. Smith
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Senior Executive Vice President and
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Chief Financial Officer
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(Principal Financial Officer)
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1.
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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2.
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
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/s/ Todd A. Stevens
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Name:
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Todd A. Stevens
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Title:
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President and Chief Executive Officer
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Date:
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February 26, 2015
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/s/ Marshall D. Smith
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Name:
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Marshall D. Smith
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Title:
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Senior Executive Vice President and Chief Financial Officer
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Date:
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February 26, 2015
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\s\ Fred Richoux
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Fred P. Richoux, P.E.
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TBPE License No. 33949
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President
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As of December 31, 2014
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Oil/Condensate
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NGL
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Total Liquid
Hydrocarbons
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Gas
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Equivalent
MMBOE
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|
|
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Total Proved Developed
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32%
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13%
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29%
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22%
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28%
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Total Proved Undeveloped
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47%
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18%
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44%
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38%
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43%
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Total Company Proved
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36%
|
15%
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33%
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26%
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32%
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Geographic Area
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Product
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Price
Reference
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Average
Benchmark
Prices
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Average Realized
Prices
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North America
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|
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United States
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Oil/Condensate
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Brent Crude
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$101.30/Bbl
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$95.20/Bbl
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California
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NGLs
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Brent Crude
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$101.30/Bbl
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$49.94/Bbl
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Gas
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Henry Hub
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$4.415/MMBTU
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$4.73/MCF
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(1)
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completion intervals which are open at the time of the estimate, but which have not started producing;
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(2)
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wells which were shut-in for market conditions or pipeline connections; or
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(3)
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wells not capable of production for mechanical reasons.
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(i)
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Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
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