I am pleased to inform you that on , 2014, the board of directors of Occidental Petroleum Corporation ("Occidental") approved the spin-off of our California oil and gas operations and related assets as a separate, publicly traded company, which we have named California Resources Corporation ("CRC"). We believe that this separation of CRC to form a new, independent, publicly traded company is in the best interests of Occidental, its stockholders and CRC.

The spin-off will be completed by way of a pro rata distribution on , 2014 of over 80% CRC's outstanding common stock to Occidental stockholders of record as of the close of business on , 2014, the spin-off record date. Each Occidental stockholder will receive shares of CRC common stock for each share of Occidental common stock held by such stockholder on the record date. The distribution of these shares will be made in book-entry form, which means that no physical share certificates will be issued. Following the spin-off, stockholders may request that their shares of CRC common stock be transferred to a brokerage or other account at any time. No fractional shares of CRC common stock will be issued. If you would otherwise have been entitled to a fractional common share in the distribution, you will receive the net cash proceeds of the sale of such fractional share instead.

The spin-off is subject to certain customary conditions. Stockholder approval of the distribution is not required, nor are you required to take any action to receive your shares of CRC common stock.

Immediately following the spin-off, you will own common stock in both Occidental and CRC. Occidental's common stock will continue to trade on the New York Stock Exchange under the symbol "OXY." CRC's common stock is expected to be traded on the New York Stock Exchange under the symbol "CRC."

Occidental is seeking a private letter ruling from the Internal Revenue Service to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates. However, any cash that you receive in lieu of fractional shares generally will be taxable to you. You should consult your own tax advisor as to the particular tax consequences of the distribution to you, including potential tax consequences under state, local and non-U.S. tax laws. The spin-off is also subject to other conditions, as described in the enclosed information statement.

The enclosed information statement, which is being mailed to all Occidental stockholders, describes the spin-off in detail and contains important information about CRC, including its combined financial statements. We urge you to read this information statement carefully.

I want to thank you for your continued support of Occidental. We look forward to your support of CRC in the future.

Stephen I. Chazen
President and Chief Executive Officer
Occidental Petroleum Corporation

Information contained herein is subject to completion or amendment. A Registration Statement on Form 10 relating to these securities has been filed with the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended.

This information statement is being sent to you in connection with the separation of California Resources Corporation ("CRC") from Occidental Petroleum Corporation ("Occidental"), following which CRC will be an independent, publicly traded company. As part of the separation, Occidental will distribute over 80% of the outstanding shares of CRC common stock on a pro rata basis to the holders of Occidental's common stock. We refer to this pro rata distribution as the "distribution" and we refer to the separation, including the restructuring transactions (which will precede the separation) and the distribution, as the "spin-off." We expect that the spin-off will be tax-free to Occidental stockholders for U.S. federal income tax purposes, except to the extent of cash received in lieu of fractional shares. Each Occidental stockholder will receive shares of CRC common stock for each share of Occidental common stock held by such stockholder as of the close of business on , 2014, the record date for the distribution. The distribution of shares will be made in book-entry form. Occidental will not distribute any fractional shares of CRC common stock. Instead, the distribution agent will aggregate fractional shares into whole shares, sell the whole shares in the open market at prevailing market prices and distribute the aggregate net cash proceeds from the sales pro rata to each holder who would otherwise have been entitled to receive a fractional share in the spin-off. See "The Spin-Off—Treatment of Fractional Shares." As discussed under "The Spin-Off—Trading Prior to the Distribution Date," if you sell your Occidental common stock in the "regular-way" market after the record date and before the distribution date, you also will be selling your right to receive shares of CRC common stock in connection with the spin-off. If you sell your Occidental common stock in the "ex-distribution" market after the record date and before the distribution date, you will still receive shares of our common stock in the spin-off. The distribution will be effective as of 11:59 p.m., Eastern Time, on , 2014. Immediately after the distribution becomes effective, CRC will be an independent, publicly traded company.

No vote or further action of Occidental stockholders is required in connection with the spin-off. We are not asking you for a proxy. Occidental stockholders will not be required to pay any consideration for the shares of CRC common stock they receive in the spin-off, and they will not be required to surrender or exchange shares of their Occidental common stock or take any other action in connection with the spin-off.

All of the outstanding shares of CRC common stock are currently owned by Occidental. Accordingly, there currently is no public trading market for CRC common stock. We expect, however, that a limited trading market for CRC common stock, commonly known as a "when-issued" trading market, will develop on or shortly before the record date for the distribution, and we expect "regular-way" trading of CRC common stock will begin the first trading day after the distribution date. We intend to apply to list CRC common stock on the New York Stock Exchange under the ticker symbol "CRC."

In reviewing this information statement, you should carefully consider the matters described under the caption "Risk Factors" beginning on page 28 of this information statement.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this information statement is truthful or complete. Any representation to the contrary is a criminal offense.

This information statement is not an offer to sell, or a solicitation of an offer to buy, any securities.

This information statement was first mailed to Occidental stockholders on or about , 2014.

This information statement is being furnished solely to provide information to Occidental stockholders who will receive shares of CRC common stock in connection with the spin-off. It is not provided as an inducement or encouragement to buy or sell any securities. You should not assume that the information contained in this information statement is accurate as of any date other than the date set forth on the cover. Changes to the information contained in this information statement may occur after that date, and we undertake no obligation to update the information contained in this information statement, unless we are required by applicable securities laws to do so.

SUMMARY

This summary highlights information contained in this information statement and provides an overview of our company, our separation from Occidental and the distribution of our common stock by Occidental to its stockholders. You should read this entire information statement carefully, including the risks discussed under "Risk Factors," our audited and unaudited historical combined financial statements and the notes thereto and our unaudited pro forma combined financial statements and the notes thereto included elsewhere in this information statement. Some of the statements in this summary constitute forward-looking statements. See "Forward-Looking Statements."

Except when the context otherwise requires or where otherwise indicated, (1) all references to "CRC," the "Company," "we," "us" and "our" refer to California Resources Corporation and its subsidiaries or, as the context requires, the California business, (2) all references to the "California business" refer to Occidental's California oil and gas exploration and production operations and related assets, liabilities and obligations, which we will assume in connection with the spin-off and (3) all references to "Occidental" refer to Occidental Petroleum Corporation, our parent company, and its subsidiaries, other than us. Except as otherwise indicated or unless the context otherwise requires, the information included in this information statement assumes the completion of certain internal restructuring transactions and the spin-off and distribution described below. Except as otherwise indicated or unless the context otherwise requires, references in this information statement to drilling locations are to "gross" drilling locations and exclude our prospective resource drilling locations.

Overview

California Resources Corporation will, following its spin-off from Occidental, be an independent oil and natural gas exploration and production company focused on high-growth, high-return conventional and unconventional assets exclusively in California. 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 continental United States based on estimated proved reserves, four of which are in our portfolio. We are the largest producer in California on a gross operated basis and we believe we have established the largest privately-held mineral acreage position in the state, consisting of approximately 2.3 million net acres spanning the state's four major oil and gas basins. We have developed a sizable inventory of over 17,500 identified drilling locations and, as an independent company, we plan to exploit our significant portfolio of conventional and unconventional opportunities to generate double-digit production growth over the longer-term. We produced approximately 154,000 Boe/d net in 2013 and, as of December 31, 2013, we had proved reserves of 744 MMBoe, with approximately 69% proved developed and 72% proved oil reserves and an aggregate PV-10 value of $14.0 billion. For an explanation of the non-GAAP financial measure PV-10 and a reconciliation of PV-10 to Standardized Measure, the most directly comparable GAAP financial measure, see "—Summary Combined Historical Operating and Reserve Data—Non-GAAP Financial Measure and Reconciliations."

California oil and gas development began in 1876, and oil-in-place estimates have generally increased throughout the ensuing decades, with over 29 billion Bbls of oil and 40 Tcf of natural gas produced and over 53,000 currently active producing wells as of December 31, 2013 (according to California's Division of Oil, Gas & Geothermal Resources ("DOGGR")). We began our operations in California in the 1950s and have accumulated extensive, proprietary knowledge and experience in developing this world-class resource base. Over the past decade, we have also built an exceptional 3D seismic library, which covers over 4,250 square miles, representing approximately 90% of the 3D seismic data available for California, and we have developed unique and proprietary stratigraphic and structural models of the subsurface geology and hydrocarbon potential in each of the four basins in which we operate. As a result of our long, successful operating history, our extensive exploration programs, our exceptional 3D seismic library and proprietary subsurface geologic models, we have tested and successfully implemented in recent years various exploration, drilling, completion and enhanced recovery technologies to maximize recoveries, increase growth and optimize returns from our portfolio.

We believe that 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 spending in California, focus on shallow zone thermal projects or investments in other assets within their global portfolios. As an independent company focused exclusively on California, we expect to drive strong production growth through increased application of modern technologies and increased capital spending on development of the significant potential in our portfolio.

Our large acreage position contains numerous growth opportunities due to its varied geologic characteristics and multiple stacked pay reservoirs that, in most cases, are thousands of feet thick. We have a significant portfolio of unconventional growth opportunities, with approximately 4,500 identified drilling locations targeting unconventional reservoirs primarily in the San Joaquin basin. Over the last few years, we have increased our production by exploiting seven discrete stacked pay horizons within the Monterey formation, primarily within the upper Monterey. We continue to drill unconventional wells within these intervals and are also applying the knowledge acquired from these successes to the Kreyenhagen and Moreno shales, which we believe offer significant development opportunities as well. We also intend to pursue development opportunities in the lower Monterey shale, which contains a variety of reservoir lithologies and is the principal hydrocarbon source rock within the overall Monterey formation. The lower Monterey has a more limited production history than the upper Monterey, and therefore limited knowledge exists regarding its potential. However, we believe it will be productive over time. Over the last five years, we have drilled and completed over 570 development wells in unconventional reservoirs, primarily in the upper Monterey formation, with a nearly 100% commercial success rate.

We also have a large portfolio of lower-risk, high-growth conventional opportunities in each of California's four major oil and gas basins with approximately 71% of our proved reserves associated with conventional opportunities. We have a proven track record of successful exploration and development using primary, waterflood and steamflood recovery methods. In 2014, we anticipate that 75% of our capital expenditures will target conventional development, primarily low-risk waterflood and steamflood projects that we expect to generate significant near-term production and cash flow growth. For example, our Lost Hills and Kern Front steamflood projects and our Huntington field waterflood project are expected to deliver combined production growth of over 35% compounded annually through 2016 from their combined 2013 production of 15,000 Boe/d.

The following table summarizes certain information concerning our acreage and drilling activities (as of December 31, 2013, unless otherwise stated):

																		2014 Projected Development Drilling Capital ($MM)(3)

	Acreage (in millions)												Identified Drilling Locations(1)
					Gross Acreage Held in Fee (%)					Average Working Interest (%)
								Producing Wells, gross
	Gross		Net					Producing Wells, gross					Gross		Net
San Joaquin basin(4)		1.8		1.5		59	%		5,764		90	%		12,836		11,127	975	$	932
Los Angeles basin(5)		<0.1		<0.1		73	%		1,382		95	%		1,537		1,478	175		394
Ventura basin		0.3		0.3		77	%		780		98	%		2,310		1,716	32		73
Sacramento basin		0.6		0.5		36	%		729		100	%		1,008		864	7		6


Total		2.7		2.3		56	%		8,655		92	%		17,691		15,185	1,189	$	1,405

(1): Our total identified drilling locations include 2,141 gross (2,024 net) locations associated with proved undeveloped reserves as of December 31, 2013 and 2,344 gross (2,251 net) injector well locations associated with our waterflood and steamflood projects. Our total identified drilling locations excludes 6,400 gross (5,300 net) prospective resource drilling locations. Please see "Business—Our Reserves and Production Information—Determination of Identified Drilling Locations" 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.
(2): Includes 183 injection wells expected to be drilled in connection with our waterflood and steamflood projects.

(3): Includes drilling and completion expenditures of $180 million associated with injection wells. Our 2014 capital budget of $2.1 billion also includes spending on support equipment, facilities, workovers and exploration.
(4): Excluding Elk Hills, our average working interest in the San Joaquin basin is 97%.
(5): We currently hold approximately 27,173 gross (20,817 net) acres in the Los Angeles basin. Our Los Angeles basin operations are concentrated with pad drilling.

In 2013, oil represented 58% of our net production. We expect the percentage of oil production to continue to increase over time and favorably impact our overall margins as we anticipate directing virtually all of our capital expenditures towards oil-weighted opportunities in 2014 and beyond to the extent the current oil to gas price relationship continues. Approximately 42% of our 2013 production was generated from our growth-oriented fields through a combination of unconventional and conventional primary, waterflood and steamflood projects with attractive returns. The remaining 58% was generated by our world-class Elk Hills and Wilmington fields, each of which is among the 10 most productive fields in U.S. history. Over the last three years, we grew our total production 6% on a compound annual basis, from 138 MBoe/d in 2011 to 154 MBoe/d in 2013, while the proportionate share of liquids production grew from 69% to 71%. We intend to accelerate our production growth by significantly increasing our capital investments and focusing on higher-growth opportunities in our extensive drilling inventory. Our 2014 capital budget of $2.1 billion represents an increase of approximately 26% over the $1.7 billion we spent in 2013. After the spin-off, we intend to reinvest substantially all of our operating cash flow in our capital program for the foreseeable future as we will no longer be required to distribute cash to Occidental. We expect to increase our production by 6-9% on a compound annual basis in 2015 and 2016 with a 15% compound annual increase in our oil production for the same period. Over 90% of our expected production for this period is from currently producing fields where we have existing or permitted capacity in our production facilities.

As we develop our sizable inventory of over 17,500 identified drilling locations, the majority of which are vertical drilling locations with thousands of feet of stacked pay, and utilize horizontal drilling techniques, we expect that our inventory of drilling locations will increase. As a result, we believe our total annual production growth will increase to over 10% after 2016, as we continue to reinvest our cash flow from operations in our capital program and accelerate our unconventional development program.

The table below summarizes our proved reserves as of December 31, 2013 and production for the three months ended March 31, 2014 in each of California's four major oil and gas basins.

															Average Net Daily Production for the three months ended March 31, 2014

	Proved Reserves as of December 31, 2013
	Oil (MMBbl)		NGLs (MMBbl)		Natural Gas (Bcf)		Total (MMBoe)		Oil (%)			Proved Developed (%)								R/P Ratio (Years)(1)
	Oil (MMBbl)		NGLs (MMBbl)		Natural Gas (Bcf)		Total (MMBoe)		Oil (%)			Proved Developed (%)			(MBoe/d)		Oil (%)			R/P Ratio (Years)(1)
San Joaquin basin		331		68		669		511		65	%		68	%		109		57	%		12.9
Los Angeles basin		156		—		17		159		98	%		70	%		27		99	%		16.0
Ventura basin		45		4		35		55		82	%		64	%		9		67	%		16.7
Sacramento basin		—		—		117		19		—	%		100	%		9		—	%		5.8


Total operations		532		72		838		744		72	%		69	%		154		62	%		13.2

(1): Calculated as total proved reserves as of December 31, 2013 divided by annualized Average Net Daily Production for the three months ended March 31, 2014.

Portfolio Management and 2014 Capital Budget

monitor internal performance and external factors and adjust our capital program with the objective of achieving the highest total returns on our portfolio of drilling opportunities.

We have a 2014 capital expenditure budget of $2.1 billion for projects targeting investments in the San Joaquin, Los Angeles and Ventura basins, as compared to $1.7 billion in 2013. Virtually all of our 2014 capital budget is being directed towards oil-weighted production consistent with 2013. Of the total 2014 capital budget, approximately $1.4 billion is allocated to well drilling and completions, $200 million to workovers, $180 million to surface support equipment to handle higher production, $100 million to additional steam generation capacity expansion, $100 million to exploration and the rest to maintenance capital, HES projects and other items. As a result of recent investments in infrastructure, we do not anticipate any substantial infrastructure spending during the next several years. We believe the absence of such significant expenditures should support strong cash flows. The table below sets forth the expected allocation of our 2014 capital expenditure budget as compared to the allocation of our 2013 capital expenditures.

	2014 Capital Expenditure Budget		2013 Capital Expenditures

	(in millions)
Conventional:
Primary recovery	$	421	$	266
Waterfloods		754		480
Steamfloods		345		375


Total conventional		1,520		1,121


Unconventional		477		457
Exploration		100		91


Total	$	2,097	$	1,669

Assuming current market conditions and a drilling success rate comparable to our historical performance, we believe we will be able to fund our entire 2014 capital program with our cash flow from operations. We have a significant inventory of high-quality drilling locations to support higher spending. We expect our 2015 capital budget to increase further from 2014 levels to a range of $2.3 billion to $2.5 billion as we reinvest substantially all of our increased cash flow in our capital program.

Our Business Strategy

We plan to maximize shareholder returns by accelerating production growth profitably through the development of our high-growth unconventional assets and low-risk conventional assets. The principal elements of our business strategy include the following:

•: Accelerate development of high-growth unconventional drilling opportunities. Over the longer term, we expect substantial production growth to come from unconventional reservoirs such as tight sandstones and shales. We hold mineral interests in approximately 1.1 million net acres with unconventional potential and have identified 4,682 drilling locations on this acreage. As a result of our increased focus on these reservoirs over the past few years, more than one third of our production now comes from unconventional assets, an increase of approximately 160% since the acquisition of our Elk Hills field properties in 1998. We have been building a growing technical understanding of these reservoirs through our successful development of portions of our acreage. For example, we have developed seven discrete, productive intervals within the Monterey formation, primarily within the upper Monterey, with a nearly 100% commercial success rate on our development wells. We are now applying the knowledge acquired from these successes to operations in other unconventional reservoirs, such as the Kreyenhagen and Moreno shale formations, which we believe offer significant development opportunities due to similar reservoir characteristics with multiple potentially productive zones in each well bore.

•: Drive significant production growth from high-return, low-risk conventional assets. In the near term, we intend to increase our capital spending and generate significant production and cash flow growth from proven IOR methods, such as waterflooding, and EOR methods, such as steamflooding. The oil and gas industry has observed that primary recovery methods typically produce less than 10% of the oil volume initially in place and that subsequent waterfloods and steamfloods typically increase recovery to a range of 20% to 60%. Our Lost Hills and Kern Front steamflood projects and our Huntington field waterflood project are expected to deliver combined production growth of over 35% compounded annually through 2016 and together account for approximately 60% of our projected 6-9% annual production growth through 2016. We believe these projects are substantially derisked as they are currently producing and we have existing or permitted capacity in our production facilities sufficient to develop these projects through 2016. We have significant additional low-risk conventional opportunities like these with over 13,139 identified drilling locations, 52% of which are associated with IOR and EOR projects. The remaining 48% are associated with primary recovery methods, many of which we expect will develop into IOR and EOR projects in the future.
•: Aggressively apply modern technologies to enhance production growth. We believe that 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 spending in California, focus 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 modern technologies in drilling and completing wells, which we expect will substantially increase both our cost-efficiency and production growth over time. We are well positioned to execute on this strategy as we have developed an extensive 3D seismic library, which covers over 4,250 square miles, representing approximately 90% of the 3D seismic data available for California, and have tested and successfully implemented various exploration, drilling, completion and IOR and EOR technologies in the state. As a result of our long, successful operating history, our geographically broad exploration drilling programs and exceptional 3D seismic library, we believe we have developed a leading understanding of the geology, petroleum systems and hydrocarbon potential in the basins in which we operate. Our unique and proprietary stratigraphic and structural models of the subsurface geology allow us to recognize new development and exploration areas in each of our basins, and identify the applicable modern drilling and completion technologies needed to maximize recoveries and optimize returns. For example, we recently applied rigorous seismic, stratigraphic and reservoir analyses to discover unconventional resources in a new field in the Monterey zone in the San Joaquin basin. This area was previously tested from the 1940s to the 1970s with six wells drilled by major oil companies, but hydrocarbon resources were not recognized until our 2012 discovery, following our seismic evaluation and application of our unique and proprietary subsurface models. We have already increased production five-fold to 1,500 Bbls/d from first quarter production in 2012 and have identified an additional 150 drilling locations in the field.
•: Generate strong cash flows through a focus on high-margin crude oil in order to internally fund our capital budget. We intend to focus on increasing cost-efficiency and developing profitable opportunities in our portfolio in order to achieve self-funded growth in any foreseeable market or regulatory environment. We intend to reinvest substantially all of our operating cash flow in our capital program for the foreseeable future as we will no longer be required to distribute cash to Occidental. In 2013, we generated cash flow from operations of approximately $763 million after capital spending of approximately $1.7 billion. We believe we will continue to generate a substantial amount of free cash flow in 2014 after capital spending of $2.1 billion. Almost all our 2014 capital budget will be focused on oil producing projects and we expect this emphasis to continue in a high oil price environment. As of December 31, 2013, crude oil represented 72% and 58%, respectively, of our total reserves and production, which positions us well to grow our oil production. In addition,

we believe we have significant potential upside in a more favorable natural gas price environment, particularly with respect to our Sacramento basin acreage, where we have identified 1,008 gross (864 net) drilling locations as of December 31, 2013. Given our large acreage position and drilling inventory across both oil and natural gas opportunities, we expect to generate strong production and cash flow growth in different commodity price environments.

•: 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. We seek to proactively engage with regulatory agencies, communities, other stakeholders and our workforce to pursue mutually beneficial outcomes. To further implement this strategy and commitment, we have recently appointed a senior manager whose primary duty is to collaborate with the regulatory agencies and other stakeholders to address their concerns and obtain required approvals in a timely fashion. One recent example of our proactive approach is our development of a regional water mapping tool based on existing public data from the San Joaquin Valley, which we have shared with state and local agencies. Our multidisciplinary team worked with regulatory agencies to integrate those data sets with computer modeling and field validation, which allowed us to obtain new well stimulation permits for a key operating area at Elk Hills. This strategy also applies directly to our protection of the environments in which we operate. For example, we actively promote biodiversity, having set aside approximately 8,000 acres of certified habitat conservation areas at our Elk Hills and Long Beach field operations. To reduce our use of fresh water, we employ water recycling and treatment extensively in our operations, such as our use of reclaimed municipal wastewater in Long Beach for pressure maintenance and waterflooding.

As a result of these water management projects, our oil and gas operations supply more fresh water than we use, providing the surplus to agriculture. We believe our commitment to safety and the environment and our proactive and collaborative approach benefit both the company and our stakeholders and enhance our ability to obtain required approvals for our development and exploration projects.

•: Significantly increase our successful exploration program. We intend to significantly increase our investment in exploration over the next several years, focusing on both unconventional and conventional opportunities, primarily in areas that we believe can be quickly developed, such as those adjacent to our existing properties. In addition, we plan to explore and test new unconventional resource areas, which, if successful, could result in significant longer-term production growth. We believe our exceptional 3D seismic library, which covers over 4,250 square miles, or 2.7 million acres, including 47% of our current acreage, and our experience in drilling deep wells, provide us a significant competitive advantage in our exploration program. Our technical staff has analyzed this extensive 3D seismic data along with modern well-log data, and mapped multiple exploration plays and drilling prospects across our key basins. From 2007 to 2013, we drilled more than 100 exploration wells targeting both conventional and unconventional reservoirs and substantially all of these wells encountered strong indications of hydrocarbons. Our two most significant exploration discoveries over the past five years were the result of employing our unique and proprietary stratigraphic and structural models of the subsurface geology, proprietary 3D seismic data and understanding of the petroleum systems and hydrocarbon potential. They now together contribute approximately 18,000 Boe/d to our production. Our current drilling inventory includes 7,237 gross (5,117 net) exploration drilling locations that are located in proven formations, the majority of which are located near existing producing fields. Additionally, we have identified 6,400 gross (5,300 net) prospective resource drilling locations in the lower Monterey, Kreyenhagen, and Moreno resource plays. We expect that these exploration drilling locations, together with additional prospects within our current large acreage holdings, will drive significant growth in our successful exploration program for many years.

Our Competitive Strengths

We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

•: Largest acreage position in a world-class oil province. 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 top 12 largest fields in the continental United States based on estimated proved reserves, four of which are in our portfolio. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.3 million net acres that contain attractive conventional and unconventional drilling opportunities using primary, IOR and EOR methods. Our large and diverse acreage position, approximately 60% of which we hold in fee, allows us to prioritize projects by value and risk to achieve strong returns and maintain strong reserve replacement and production growth rather than drill simply to hold leases. A significant percentage of our opportunities are oil-weighted, with approximately 90% of our identified drilling locations associated with oil production. For the year ended December 31, 2013, we were the largest producer in the state on a combined gross operated basis with approximately 188,000 MBoe/d of production, 59% of which was oil. As of December 31, 2013, we had total combined reserves of over 744 MMBoe, of which approximately 72% was oil and 81% was liquids.
•: Significant growth potential from opportunity-rich drilling portfolio. Our drilling inventory at March 31, 2014 consisted of 17,691 identified well locations, including 4,682 gross (4,264 net) unconventional drilling locations and 13,009 gross (10,921 net) conventional drilling locations. We believe we can achieve significant production growth through the development of unconventional reservoirs. Over the last five years, we have drilled and completed over 570 unconventional development wells, primarily in the upper Monterey formation, with an almost 100% commercial success rate. Our successful unconventional drilling program has demonstrated the productive potential of seven stacked pay zones within the Monterey formation, primarily within the upper Monterey, and we believe that these successes are repeatable in other formations such as the Kreyenhagen formation, which has similar geologic attributes. We also have a large inventory of conventional development opportunities that will provide low-risk, near-term production growth with attractive returns. We believe that a significant portion of our production growth over the next two to three years will be driven by IOR and EOR projects, many of which are already being implemented. Over 90% of our expected 6-9% production growth through 2016 is expected to come from currently producing fields. As we develop our sizable inventory of drilling locations, the majority of which are vertical drilling locations with thousands of feet of stacked pay, and utilize horizontal drilling techniques, we expect that we will achieve double-digit production growth over the longer term.
•: Unique ability to drive high returns and growth in different commodity price environments. Our current drilling inventory comprises a diversified portfolio of oil and natural gas locations, which allows us to target drilling projects that are the most economically compelling depending on the prevailing commodity price outlook. 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. We have operating control over 97% of our properties, enabling us to determine all aspects of our development program, including the selection of specific drilling locations, the timing of the development and the drilling and completion techniques used. Our retention of operating control coupled with our diversified portfolio provides us with the flexibility to invest our capital in the highest return projects and control operating costs to drive strong production and cash flow growth in different commodity price environments as well as to adapt to any changes in regulatory and market conditions. Approximately 26% of our production for the three months ended March 31, 2014 was natural gas. If conditions change and gas prices become more favorable, we believe that we have the ability to significantly increase our gas production within a few years through

accelerated capital investment in gas projects currently in our portfolio. In addition to our drilling opportunities, we have made significant investments in infrastructure, including our state-of-the-art Elk Hills cryogenic gas plant and our 550 megawatt Elk Hills power plant, which increase our operational flexibility and ability to maximize returns in any commodity price environment.

•: Strong free cash flow and premium margins driven by deficit California energy market. We sell almost all of our crude oil into the California refining markets at prices we believe are among the most favorable in the United States. California, the largest state economy in the United States, imports approximately 62% of its oil and approximately 90% of its natural gas. Oil is imported via rail or supertanker and gas is imported via pipeline. As a result, California refiners typically purchase crude oil at international waterborne-based prices at a premium to WTI-based prices. For example, our average realized price for crude oil in 2013 reflected a 6% premium to WTI index prices. We believe that the limited crude transportation infrastructure from other parts of the country to California will allow us to continue to realize strong cash margins as a result. In addition, we own the fee minerals on approximately 60% of our acreage position. The returns on developed mineral fee acreage are greatly enhanced because we do not pay royalties and other lease payments. We expect the resulting substantial operating cash flow to fund our growth while allowing us to maintain ample liquidity.
•: Proven management and technical teams with extensive experience operating in California. Our experienced management team and technical staff have a proven track record of applying the leading technologies and operating methods to develop our assets. The members of our management and technical teams have an average of over years' experience in the oil and natural gas industry, with an average of years focused on California oil and gas operations. We believe this focused experience gives us an inherent competitive advantage. As a result of our long operating history in the state, our team of geoscientists and engineers has developed a growing understanding of the geology and can quickly identify and apply suitable recovery methods, as well as drilling, completion and other relevant technologies, to maximize production and reserves. For example, our technical team has extensive experience developing unconventional opportunities and growing large, world-class fields, such as Elk Hills and Wilmington. Our cumulative production and year end proven reserves from these fields are twice the proved reserves originally purchased and we continue to find additional reserves in these fields. In addition, production from unconventional reservoirs within these fields accounted for over 50% of our 2013 daily combined production for these fields. We are applying the expertise gained through re-developing Elk Hills and Wilmington to many of the other fields we operate. In addition, we believe that our team has established a favorable reputation among regulators and other stakeholders for our commitment to safety and demonstrated sensitivity to the environment. We believe that our favorable record and reputation with communities and regulators sustains our operations, and gives us an important advantage when we seek to acquire and develop opportunities throughout California.

Other Information

We were incorporated under the laws of the State of Delaware on April 23, 2014. Our principal executive offices are located at . Our telephone number is . Our website address is www. .com. Information contained on our website is not incorporated by reference into this information statement or the registration statement on Form 10 of which this information statement is a part, and you should not consider information on our website as part of this information statement or such registration statement on Form 10.

The Spin-Off

following the distribution, Occidental stockholders as of the record date will own over 80% of the outstanding shares of our common stock.

Before our separation from Occidental, we and Occidental will enter into a Separation and Distribution Agreement and several other agreements to effect the spin-off. These agreements will provide for the allocation between us and Occidental of Occidental's assets, liabilities and obligations, and we will generally be allocated those assets, liabilities and obligations relating to the California business. These agreements will also govern certain interactions between us and Occidental after the separation (including with respect to employee matters, tax matters and intellectual property matters). We and Occidental will also enter into a Transition Services Agreement which will provide for, among other matters, assistance to us or Occidental as needed. For more information regarding these agreements, see "Arrangements Between Occidental and Our Company" and the historical and pro forma financial statements and the notes thereto included elsewhere in this information statement. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties. See "Risk Factors—Risks Related to the Spin-Off." Our entry into the Separation and Distribution Agreement and the several ancillary agreements, our amendment and restatement of our certificate of incorporation and bylaws and other related transactions are collectively referred to as our "restructuring transactions" throughout this information statement.

The spin-off is expected to provide each company with a number of material opportunities and benefits, including the following:

•: creating two independent businesses that will be competitive industry leaders in their respective areas of operations;
•: allowing each business to pursue strategies tailored to its needs, including enabling CRC to reinvest substantially all of its cash flow in growing its business;
•: focusing each management team on the development and execution of its business in its areas of operation;
•: enabling each business to focus on and accelerate its technical expertise in specific reservoirs and fields; and
•: enhancing each company's market recognition with investors because of its status as an industry leader in its geographic areas of focus.

The distribution of our common stock as described in this information statement is subject to the satisfaction or waiver, in the sole discretion of Occidental, of certain conditions. In addition, Occidental has the right not to complete the spin-off if, at any time prior to the distribution, the board of directors of Occidental determines, in its sole discretion, that the spin-off is not in the best interests of Occidental or its stockholders or market conditions do not warrant completing the separation at that time. See "The Spin-Off—Conditions to the Spin-Off."

Questions and Answers About the Spin-Off

The following provides answers only to certain key questions we expect you may have regarding the spin-off. For a more detailed description of the terms of the spin-off, see "The Spin-Off."

Q:: What is the spin-off?
A:: In this information statement, when we refer to the "spin-off," we are referring to the separation of Occidental's California business from the remaining business of Occidental through a series of transactions, including the restructuring transactions, that will result in the California business being owned by us, and Occidental's pro rata distribution of over 80% of our outstanding shares to its stockholders. Following the spin-off, we will be a separate and independent company from Occidental.

The number of shares of Occidental common stock you own will not change as a result of the spin-off. Your proportionate direct interest in CRC, however, will be lower than your proportionate direct interest in Occidental, due to the fact that Occidental will continue to hold up to 19.9% of our outstanding shares (the "Retained Securities") for up to two years following the spin-off.

Q:: What will I receive in the spin-off?
A:: As a holder of Occidental stock, you will retain your Occidental shares and will receive shares of our common stock for each share of Occidental common stock you hold as of the record date. Your proportionate interest in Occidental will not change as a result of the spin-off.
Q:: What is CRC?
A:: CRC is currently a wholly-owned subsidiary of Occidental whose shares will be distributed to Occidental stockholders if the spin-off is completed. After the spin-off is completed, CRC will be an independent publicly traded company and will own and operate the California business.
Q:: When is the record date for the distribution, and when will the distribution occur?
A:: The record date for determining Occidental stockholders entitled to receive our shares in the distribution will be the close of business of the New York Stock Exchange (the "NYSE") on , 2014. The distribution will occur on , 2014.
Q:: What are the reasons for and benefits of separating us from Occidental?
A:: Our separation from Occidental and the distribution of our common stock will provide you with equity investments in two separate companies that are intended to be more focused and competitive industry leaders. The spin-off will enable each company to pursue strategies tailored to the respective needs of their businesses. For a more detailed discussion of the reasons for and benefits of the spin-off, see "The Spin-Off—Reasons for the Spin-Off."
Q:: What are the risks associated with the spin-off?
A:: There are a number of risks associated with the spin-off and resultant ownership of our common stock. These risks are discussed under "Risk Factors" beginning on page 28.
Q:: Why is the separation of CRC structured as a spin-off as opposed to a sale?
A:: Occidental believes that a tax-free distribution of our common stock is an efficient way to separate us from Occidental in a manner that will improve flexibility, benefit both Occidental and CRC and create long-term value for stockholders of both Occidental and CRC.
Q:: What is being distributed in the spin-off?
A:: Approximately shares of our common stock will be distributed in the spin-off, based on the number of shares of Occidental common stock expected to be outstanding as of the record date of , 2014. The actual number of shares of our common stock to be distributed will be calculated on , 2014, the record date. The shares of our common stock to be distributed by Occidental will constitute over 80% of the issued and outstanding shares of our common stock immediately prior to the distribution. For more information on the shares being distributed in the spin-off, see "Description of Capital Stock—Common Stock."

Q:: What will the relationship be between Occidental and CRC after the spin-off?
A:: Following the spin-off, CRC will be an independent, publicly traded company and Occidental will hold the Retained Securities for a maximum of two years. In connection with the spin-off, we will enter into a Separation and Distribution Agreement and several other agreements with Occidental for the purpose of allocating between us and Occidental various assets, liabilities and obligations relating to the California business. These agreements will also provide arrangements for employee matters, tax matters and some other liabilities and obligations attributable to periods before and, in some cases, after the spin-off. These agreements will also include arrangements with respect to transition services. We will also have an Area of Mutual Interest Agreement with Occidental that provides Occidental the right to acquire % of certain oil and gas properties we acquire in the United States outside of the state of California.
Q:: What will Occidental do with the Retained Securities?
A:: Occidental expects to dispose of all of the Retained Securities through one or more subsequent exchanges for Occidental common stock. Any shares Occidental does not dispose of through exchanges will be distributed pro rata to Occidental shareholders in no event later than two years after the distribution.
Q:: How will equity-based and other long-term incentive compensation awards held by Occidental employees be affected as a result of the spin-off?
A:: The treatment of outstanding Occidental equity-based and other long-term incentive compensation awards has not been finally determined, and we will include information regarding the treatment in an amendment to this information statement. For more information on Occidental's current anticipated treatment of equity-based and other long-term incentive compensation awards that may be held by our named executive officers as of the spin-off, see "Executive Compensation—Compensation Discussion and Analysis—Effects of Spin-off on Outstanding Executive and Other Compensation Awards."
Q:: What do I have to do to participate in the spin-off?
A:: You are not required to take any action, although you are urged to read this entire document carefully. No stockholder approval of the spin-off is required and none is being sought. You are not being asked for a proxy. No action is required on your part to receive your shares of our common stock. You will neither be required to pay anything for the new shares nor to surrender any shares of Occidental common stock to participate in the spin-off.
Q:: How will fractional shares be treated in the spin-off?
A:: Fractional shares of our common stock will not be distributed. Fractional shares of our common stock to which Occidental stockholders of record would otherwise be entitled will be aggregated and sold in the public market by the distribution agent. The aggregate net cash proceeds of the sales will be distributed ratably to those stockholders who would otherwise have received fractional shares of our common stock. Proceeds from these sales will generally result in a taxable gain or loss to those stockholders. Each stockholder entitled to receive cash proceeds from these shares should consult his, her or its own tax advisor as to the stockholder's particular circumstances. The tax consequences of the distribution are described in more detail under "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off."

Q:: What are the U.S. federal income tax consequences of the spin-off?
A:: The spin-off is conditioned on the receipt by Occidental of a private letter ruling from the Internal Revenue Service (the "IRS") substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates. The distribution is further conditioned on Occidental's tax counsel issuing an opinion in form and substance acceptable to Occidental, which may rely on the effectiveness of the private letter ruling with respect to certain issues, that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off qualifies as a tax-free transaction under Section 355 and/or Section 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (the "Code"). See "The Spin-Off—Conditions to the Spin-Off." Assuming that the spin-off will qualify as a tax-free transaction under Section 355 and/or Section 368(a)(1)(D) of the Code, for U.S. federal income tax purposes, except for gain realized on the receipt of cash paid in lieu of fractional shares, no gain or loss will generally be recognized by an Occidental shareholder, and no amount generally will be included in such Occidental shareholder's taxable income, as a result of the spin-off. You should, however, consult your own tax advisor as to the particular consequences to you. The U.S. federal income tax consequences of the distribution are described in more detail under "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off."
Q:: Will our common stock be listed on a stock exchange?
A:: Yes. Although there is currently no public market for our common stock, we intend to apply to list our common stock on the NYSE under the symbol "CRC."

It is anticipated that trading of our common stock will commence on a "when-issued" basis on or shortly before the record date. When-issued trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. When-issued trades generally settle within four trading days after the distribution date. On the first trading day following the distribution date, any when-issued trading with respect to our common stock will end and "regular-way" trading will begin. "Regular-way" trading refers to trading after a security has been issued and typically involves a transaction that settles on the third full trading day following the date of the transaction. See "Trading Market."
Q:: Will my shares of Occidental common stock continue to trade?
A:: Yes. Occidental common stock will continue to be listed and traded on the NYSE under the symbol "OXY."
Q:: If I sell, on or before the distribution date, shares of Occidental common stock that I held on the record date, am I still entitled to receive shares of CRC common stock distributable with respect to the shares of Occidental common stock I sold?
A:: Beginning on or shortly before the record date and continuing through the distribution date for the spin-off, Occidental's common stock will begin to trade in two markets on the NYSE: a "regular-way" market and an "ex-distribution" market. If you are a holder of record of shares of Occidental common stock as of the record date for the distribution and choose to sell those shares in the regular-way market after the record date for the distribution and before the distribution date, you also will be selling the right to receive the shares of our common stock in connection with the spin-off. However, if you are a holder of record of shares of Occidental common stock as of the record date for the distribution and choose to sell those shares in the ex-distribution market after the record date for the distribution and before the distribution date, you will still receive shares of our common stock in the spin-off.

Q:: Will the spin-off affect the trading price of my Occidental stock?
A:: Yes, the trading price of shares of Occidental common stock immediately following the distribution is expected to be lower than immediately prior to the distribution because of the dividend to Occidental common stockholders in the form of our common stock and the fact that the Occidental common stock trading price will no longer reflect the value of the California business, partially offset by the value of the cash we will distribute to Occidental. We cannot provide you with any assurance as to the price at which shares of Occidental common stock will trade following the spin-off.
Q:: What indebtedness will CRC have following the spin-off?
A:: We intend to enter into new financing arrangements in anticipation of the spin-off. We expect to incur up to $ billion in new debt, which may include long-term notes, term loans or borrowings under a revolving credit facility or a combination thereof. At separation, we intend to make a cash distribution of approximately $ billion to Occidental. We expect that our revolving credit facility will be available for our immediate working capital needs and for general corporate purposes including issuance of letters of credit. See "Description of Material Indebtedness" included elsewhere in this information statement.

Following the spin-off, our debt obligations could restrict our business and may adversely impact our financial condition, results of operations or cash flows. In addition, our separation from Occidental's other businesses may increase the overall cost of debt funding and decrease the overall debt capacity and commercial credit available to us. Our business, financial condition, results of operations and cash flows could be harmed by a deterioration of our credit profile or by factors adversely affecting the credit markets generally. See "Risk Factors—Risks Related to the Spin-Off—We will have significant indebtedness and may incur more debt. Higher levels of indebtedness could make us more vulnerable to economic downturns and adverse developments in our business."
Q:: What will our dividend and share repurchase policy be after the spin-off?
A:: We intend to pay a cash dividend of $0.01 per share per quarter, or $0.04 per share per year. We do not anticipate increasing the dividend on our common stock in the foreseeable future as we currently intend to retain the remainder of our future earnings to support the growth and development of our business. In addition, we will be authorized to implement a share repurchase program if circumstances warrant. The payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our capital investment program, financial condition, results of operations, capital requirements and development expenditures, future business prospects and any restrictions imposed by future debt instruments. For more information, see "Dividend Policy."
Q:: If I was enrolled in an Occidental dividend reinvestment plan, will I automatically be enrolled in the CRC dividend reinvestment plan?
A:: Yes. If you elected to have your Occidental cash dividends applied toward the purchase of additional Occidental shares, the CRC shares you receive in the distribution will be automatically enrolled in the sponsored by (CRC's transfer agent and registrar), unless you notify that you do not want to reinvest any CRC cash dividends in additional CRC shares. Contact information for the CRC plan sponsor ( ) is provided on page 147 of this Information Statement.
Q:: What are the anti-takeover effects of the spin-off?
A:: Some provisions of our amended and restated certificate of incorporation, our amended and restated bylaws and Delaware law may have the effect of making more difficult an acquisition of control of us

in a transaction not approved by our board of directors. For example, our amended and restated certificate of incorporation and amended and restated bylaws will require advance notice for shareholder proposals and nominations, place limitations on convening shareholder meetings and authorize our board of directors to issue one or more series of preferred stock. See "Description of Capital Stock—Anti-Takeover Effects of Provisions of our Amended and Restated Certificate of Incorporation, our Amended and Restated Bylaws and Delaware Law" for more information.

In addition, under the Tax Sharing Agreement we will enter into with Occidental in connection with the spin-off, we will agree to take certain actions and refrain from taking certain actions, including agreeing to refrain from entering into certain strategic and corporate transactions. The purpose of these covenants is to help ensure the tax free status of the spin-off. These restrictions and our related tax indemnification obligations in the Tax Sharing Agreement may have the effect, for a period of time following the spin-off, of making it more difficult and less desirable for us to enter into certain transactions, including those that may result in a change of control. See "Arrangements Between Occidental and Our Company—Tax Sharing Agreement" for more information.

Q:

Where can I get more information?

A:

If you have any questions relating to the mechanics of the distribution, you should contact the distribution agent at:

Distribution Agent:
Address:
Phone:

Before the spin-off, if you have any questions relating to the spin-off, you should contact Occidental at:

Occidental Petroleum Corporation
Attn: Investor Relations
1230 Avenue of the Americas
New York, New York 10020
Phone: (212) 603-8111
www.oxy.com

After the spin-off, if you have any questions relating to CRC, you should contact CRC at:

California Resources Corporation
Attn: Investor Relations
Address:
Phone:
www. .com

Summary of the Spin-Off


Distributing Company		Occidental Petroleum Corporation, a Delaware corporation. After the distribution, Occidental will hold the Retained Securities for up to two years.
Distributed Company		California Resources Corporation, a Delaware corporation and a wholly-owned subsidiary of Occidental. After the spin-off, we will be an independent, publicly owned company.
Distributed Securities		Occidental will distribute over 80% of the outstanding shares of CRC common stock. Based on approximately shares of Occidental common stock outstanding as of , 2014 and assuming distribution of 80.1% of our common stock and applying the distribution ratio, approximately shares of our common stock will be distributed.
Retained Securities		Occidental expects to dispose of all of the Retained Securities through one or more subsequent exchanges of the Retained Securities for Occidental common stock. Any shares Occidental does not dispose of through exchanges will be distributed pro rata to Occidental shareholders in no event later than two years after the distribution.
Record Date		The record date for the distribution is the close of business of the NYSE on , 2014.
Distribution Date		The distribution date is , 2014.
Restructuring Transactions		As part of the spin-off, Occidental will generally contribute and transfer to us the assets, liabilities and obligations related to the California business and we will amend and restate our certificate of incorporation and bylaws.
Distribution Ratio		Each Occidental stockholder will receive shares of our common stock for each share of Occidental common stock held by such stockholder on the record date.
Distribution Method		Our common stock will be issued only by direct registration in book-entry form. Registration in book-entry form is a method of recording stock ownership when no physical paper certificates are issued to stockholders, as is the case in this distribution.


Fractional Shares		The distribution agent will not distribute any fractional shares of our common stock to Occidental stockholders. Fractional shares of our common stock to which Occidental stockholders of record would otherwise be entitled will be aggregated and sold in the public market by the distribution agent. The aggregate net cash proceeds of the sales will be distributed ratably to those stockholders who would otherwise have received fractional shares of our common stock. Proceeds from these sales will generally result in a taxable gain or loss to those stockholders. Each stockholder entitled to receive cash proceeds from these shares should consult his, her or its own tax advisor as to the stockholder's particular circumstances. The tax consequences of the distribution are described in more detail under "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off."
Conditions to the Spin-Off		The spin-off is subject to the satisfaction or waiver by Occidental, in its sole discretion, of the following conditions, as well as other conditions described in this information statement in "The Spin-Off—Conditions to the Spin-Off":
		• the Securities and Exchange Commission ("SEC") shall have declared effective our registration statement on Form 10, of which this information statement is a part, under the Exchange Act of 1934, as amended (the "Exchange Act"); no stop order suspending the effectiveness of the registration statement shall be in effect; and no proceedings for such purpose shall be pending before or threatened by the SEC;
		• any required actions and filings with regard to state securities and blue sky laws of the U.S. (and any comparable laws under any foreign jurisdictions) shall have been taken and, where applicable, have become effective or been accepted;
		• our common stock shall have been authorized for listing on the NYSE, or another national securities exchange approved by Occidental, subject to official notice of issuance;
		• Occidental shall have received a private letter ruling from the IRS to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates, and such private letter ruling shall not have been revoked or modified in any material respect;
		• Occidental shall have received an opinion of its tax counsel, in form and substance acceptable to Occidental and which shall remain in full force and effect, that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off qualifies as a tax-free transaction under Section 355 and/or Section 368(a)(1)(D) of the Code;


		• no order, injunction, decree or regulation issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the distribution will be in effect;
		• the completion of our new financing arrangements;
		• no other events or developments shall have occurred or exist that, in the judgment of the board of directors of Occidental, in its sole discretion, makes it inadvisable to effect the distribution or other transactions contemplated by the Separation and Distribution Agreement;
		• each of the ancillary agreements contemplated by the Separation and Distribution Agreement shall have been executed by each party thereto; and
		• any government approvals and other material consents necessary to consummate the distribution will have been obtained and remain in full force and effect.
		The fulfillment of the foregoing conditions does not create any obligations on Occidental's part to effect the spin-off, and the Occidental board of directors has reserved the right, in its sole discretion, to abandon, modify or change the terms of the spin-off, including by waiving any conditions to the spin-off or accelerating or delaying the timing of the consummation of all or part of the spin-off, at any time prior to the distribution date.
Trading Market and Symbol		We intend to apply to list our common stock on the NYSE under the ticker symbol "CRC." We anticipate that, on or shortly before the record date, trading of shares of our common stock will begin on a "when-issued" basis and will continue up to and including the distribution date, and we expect "regular-way" trading of our common stock will begin the first trading day after the distribution date. We also anticipate that, on or shortly before the record date, there will be two markets in Occidental common stock: a "regular-way" market on which shares of Occidental common stock will trade with an entitlement to shares of our common stock to be distributed pursuant to the distribution, and an "ex-distribution" market on which shares of Occidental common stock will trade without an entitlement to shares of our common stock. For more information, see "Trading Market."


Tax Consequences		The distribution is conditioned on the receipt by Occidental of a private letter ruling from the IRS substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates. The distribution is further conditioned on Occidental's tax counsel issuing an opinion in form and substance acceptable to Occidental, which may rely on the effectiveness of the private letter ruling with respect to certain issues, that for U.S. federal income tax purposes, (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off qualifies as a tax-free transaction under Section 355 and/or Section 368(a)(1)(D) of the Code.
		Assuming that the spin-off will qualify as a tax-free transaction for U.S. federal income tax purposes, except for gain realized on the receipt of cash paid in lieu of fractional shares, no gain or loss will generally be recognized by an Occidental stockholder, and no amount generally will be included in such Occidental stockholder's taxable income, as a result of the spin-off.
		For a more detailed description of the U.S. federal income tax consequences of the spin-off, see "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off."
		Each stockholder is urged to consult his, her or its tax advisor as to the specific tax consequences of the spin-off to such stockholder, including the effect of any state, local or non-U.S. tax laws and of changes in applicable tax laws.


Relationship with Occidental after the Spin-Off		We will enter into a Separation and Distribution Agreement and other ancillary agreements with Occidental related to the spin-off. These agreements will provide for the allocation between us and Occidental of Occidental's assets, liabilities and obligations, and we will generally be allocated those assets, liabilities and obligations relating to the California business. These agreements will also govern certain interactions between us and Occidental after the separation (including with respect to employee matters, tax matters and intellectual property matters). We and Occidental will also enter into a Transition Services Agreement that will provide for, among other matters, assistance to us or Occidental as needed. We also intend to enter into an Employee Matters Agreement that will set forth the agreements between Occidental and us concerning certain employee compensation and benefit matters. Further, we intend to enter into a Tax Sharing Agreement with Occidental regarding the respective rights, responsibilities, and obligations of Occidental and us with respect to the payment of taxes, filing of tax returns, reimbursements of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes. We will also enter into an Area of Mutual Interest Agreement with Occidental, which will provide Occidental with the right to acquire an interest in and rights with respect to certain oil and gas properties in the United States (excluding the state of California). We describe these and other arrangements in greater detail under "Arrangements Between Occidental and Our Company," and describe some of the risks of these arrangements under "Risk Factors—Risks Related to the Spin-Off."
Indemnities		We will indemnify Occidental under the Tax Sharing Agreement for taxes incurred as a result of the failure of the spin-off to qualify as tax-free under Section 355 and/or Section 368(a)(1)(D) of the Code, to the extent caused by our breach of any representations or covenants made in the Tax Sharing Agreement, the Separation and Distribution Agreement, or made in connection with the private letter ruling or the tax opinion or by any other action taken by us. We also have agreed to pay 50% of any taxes arising from the spin-off to the extent that the tax is not attributable to the fault of either party. See "Arrangements Between Occidental and Our Company—Tax Sharing Agreement." In addition, under the Separation and Distribution Agreement, we and Occidental will indemnify each other and certain of our respective subsidiaries against claims and liabilities relating to the past operation of our business. See "Arrangements Between Occidental and Our Company."

Summary Risk Factors

We face both general and specific risks and uncertainties relating to our business and our being an independent, publicly owned company. We also are subject to risks related to the spin-off. Below is a summary of certain key risk factors that you should consider. Please read the full discussion of these risks and the other risks described under "Risk Factors" beginning on page 28 of this information statement and "Forward-Looking Statements."

Risks Related to our Business

•: Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations.
•: Commodity pricing strongly affects our results of operations, financial condition, cash flow and ability to grow.
•: Part of our strategy involves exploratory drilling, including drilling in new or emerging plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is unsuccessful.
•: Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing and other well stimulation techniques could result in increased costs and additional operating restrictions or delay our implementation of, or cause us to change, our business strategy.
•: Tax law changes may adversely affect our operations.
•: Drilling for and producing oil and gas are high-risk activities with many uncertainties.
•: We operate in a highly competitive environment for oilfield equipment, services, qualified personnel and acquisitions.
•: Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.
•: We will have significant indebtedness and may incur more debt. Higher levels of indebtedness could make us more vulnerable to economic downturns and adverse developments in our business.
•: Our business requires substantial capital expenditures. We may be unable to fund these expenditures through operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a decline in our oil and gas reserves or production. Our capital investment program is susceptible to risks that could materially affect its implementation.
•: We periodically evaluate our unproved oil and natural gas properties for impairment, and could be required to recognize noncash charges to earnings of future periods.
•: Laws and regulations, including those pertaining to land use and environmental protection, could delay or restrict our operations and cause us to incur substantial costs.
•: Restrictions on our ability to obtain, use, manage or dispose of water may have an adverse effect on our operations.

•: Our AMI Agreement may adversely affect our ability to operate outside of California.
•: We may not drill our identified sites at the times we have scheduled or at all.
•: Concerns about climate change and other air quality issues may affect our operations or results.
•: Risks related to our acquisition activities could negatively impact our financial condition and results of operations.
•: We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
•: Cyber attacks could significantly affect us.
•: Operational issues could restrict access to markets for the commodities we produce.

Risks Related to the Spin-Off

•: We may not realize the anticipated benefits from our separation from Occidental.
•: The combined value of Occidental and our shares after the spin-off may not equal or exceed the value of Occidental shares prior to the spin-off.
•: Our historical and pro forma financial information may not be representative of the results we would have achieved as a stand-alone public company and may not be a reliable indicator of our future results.
•: A large number of our shares are or will be eligible for future sale, which may cause the market price for our common stock to decline.
•: In connection with our separation from Occidental, we will indemnify Occidental for certain liabilities, including those related to the operation of our business while it was still owned by Occidental, and Occidental will indemnify us for certain liabilities, and such indemnities may not be adequate.
•: Our costs will increase as a result of operating as a stand-alone public company, and our management will be required to devote substantial time to complying with public company regulations.
•: Following the separation, Occidental will provide us with certain transitional services that may not be sufficient to meet our needs. We may have difficulty finding supplemental or, ultimately, replacement services or be required to pay increased costs to supplement or, ultimately, replace these services.
•: The agreements between us and Occidental will not be made on an arm's length basis.
•: Our Tax Sharing Agreement with Occidental may limit our ability to take certain actions, including strategic transactions, and may require us to indemnify Occidental for significant tax liabilities.
•: We could have significant tax liabilities for periods during which Occidental operated our business.
•: Occidental, its stockholders, or we could have significant tax liabilities if the separation, and certain transactions in preparation therefore, are not tax-free.
•: Following the spin-off, several members of our board of directors and management may have actual or potential conflicts of interest because of their ownership of shares of common stock of Occidental.
•: The spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements.

Risks Related to our Common Stock

•: No market currently exists for our common stock. We cannot assure you that an active trading market will develop for our common stock.
•: The market price and trading volume of our common stock may be volatile and you may not be able to resell your shares at or above the initial market price of our common stock following the spin-off.
•: We do not anticipate paying significant dividends on our common stock in the foreseeable future. As a result, you will need to sell your shares of common stock to receive any significant income.
•: Provisions contained in our amended and restated certificate of incorporation and amended and restated bylaws could discourage a takeover attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, the ability of our stockholders to sell their shares for a premium.
•: Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders' ability to obtain an alternative judicial forum for disputes with us or our directors, officers, employees or agents.

SUMMARY COMBINED HISTORICAL AND PRO FORMA FINANCIAL DATA

Set forth below is a summary of our combined historical and pro forma financial data for the periods indicated. The historical unaudited combined financial data for the three months ended March 31, 2014 and 2013 and the balance sheet data as of March 31, 2014 have been derived from our unaudited condensed combined financial statements included elsewhere in this information statement. The unaudited condensed combined financial statements have been prepared on the same basis as our audited combined financial statements, except as stated in the related notes thereto, and include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial condition and results of operations for such periods. The results of operations for the three months ended March 31, 2014 presented below are not necessarily indicative of results for the entire fiscal year. The historical financial data for the years ended December 31, 2013, 2012 and 2011 and the balance sheet data as of December 31, 2013 and 2012 have been derived from our audited combined financial statements included elsewhere in this information statement.

The unaudited pro forma financial data have been derived from our historical combined financial statements included in this information statement. While the historical combined financial statements reflect the past financial results of the California business, these pro forma statements give effect to the separation of those operations into a stand-alone, publicly traded company in the spin-off. The pro forma adjustments are based on available information and assumptions that we believe are reasonable; however, such adjustments are subject to change based on the finalization of the terms of the spin-off and the related separation and distribution agreements, as well as our expected debt offering. We have attempted to include recurring costs of operating as a stand-alone company, although only the additional costs we have determined to be factually supportable are included as pro forma adjustments. There are expected to be additional incremental costs of operating as a stand-alone company not reflected in the unaudited pro forma combined financial statements, which are currently estimated to be approximately $ million before income taxes annually. Additionally, such adjustments are estimates and may not prove to be accurate. The adjustments include certain costs associated with the spin-off related to certain management actions which are either in the balance sheet or income statement, as appropriate. The pro forma adjustments, including related tax effects, to reflect the spin-off are expected to include the following:

•: the receipt of $ billion from the issuance of new debt, after deducting fees and costs, as well as the interest expense related to such debt;
•: the distribution of approximately $ billion to Occidental from the net proceeds from our new debt;
•: the distribution of approximately million shares of our common stock to Occidental stockholders; and
•: incremental costs and expenses associated with operating as a standalone publicly traded company that are factually supportable.

The separation and distribution, tax sharing, transition services, employee matters and indemnification agreements have not been finalized, and the pro forma statements will be revised in future amendments to reflect the effects of those agreements, to the extent material.

You should read the following summary financial data in conjunction with "Selected Historical Combined Financial Data," "Unaudited Pro Forma Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our audited combined financial statements, unaudited interim combined condensed financial statements and the notes to those statements included in this information statement.

public company during the periods presented, or in the case of the unaudited pro forma information, had the transactions reflected in the pro forma adjustments actually occurred as of the dates assumed. The unaudited pro forma combined financial data are for illustrative purposes only. The unaudited pro forma combined financial data constitute forward-looking information and are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated. See "Forward-Looking Statements" in this information statement.

											Pro Forma

	Three Months Ended March 31,										Pro Forma
					Year Ended December 31,						Three Months Ended March 31, 2014
					Year Ended December 31,							Year Ended December 31, 2013
	2014		2013		2013		2012		2011			Year Ended December 31, 2013
	(in millions)
Statement of Income Data:
Net sales, including to related parties	$	1,121	$	1,048	$	4,285	$	4,072	$	3,938	$	$
Income before income taxes	$	374	$	362	$	1,447	$	1,181	$	1,641	$	$
Net income	$	223	$	217	$	869	$	699	$	971	$	$

							Pro Forma

			December 31,				Pro Forma
	March 31, 2014		December 31,				March 31, 2014
	March 31, 2014		2013		2012		March 31, 2014
	(in millions)
Balance Sheet Data:
Property, plant and equipment, net	$	14,173	$	14,008	$	13,499	$
Net investment	$	9,979	$	9,989	$	9,860	$

																Pro Forma

	Three Months Ended March 31,															Pro Forma
							Year Ended December 31,									Three Months Ended March 31, 2014
							Year Ended December 31,										Year Ended December 31, 2013
	2014			2013			2013			2012			2011				Year Ended December 31, 2013
	(in millions)
Statement of Cash Flows Data:
Net cash provided by operating activities	$	716		$	708		$	2,476		$	2,223		$	2,456		$	$
Capital expenditures	$	(475	)	$	(337	)	$	(1,669	)	$	(2,331	)	$	(2,164	)	$	$
Payments for purchases of assets and businesses	$	(2	)	$	(9	)	$	(48	)	$	(427	)	$	(1,405	)	$	$

SUMMARY COMBINED HISTORICAL OPERATING AND RESERVE DATA

The following table presents a summary of our estimated net proved oil and gas reserves as of the dates indicated. In 2013, Ryder Scott Company, L.P. ("Ryder Scott") reviewed the specific application of reserve estimation methods and procedures for approximately 37% of our proved oil and gas reserves. Since being engaged by Occidental, Ryder Scott has reviewed the specific application of reserve estimation methods and procedures for approximately 79% of our proved reserves that existed at December 31, 2013. Based on its reviews, including the data, technical processes and interpretations presented with respect to our oil and gas reserves, Ryder Scott concluded that the overall procedures and methodologies utilized in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties were appropriate for the purpose thereof and complied with SEC regulations as of December 31, 2013. The reserve estimates mentioned here were prepared in a manner consistent with SEC rules regarding oil and gas reserves reporting currently in effect. You should refer to "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business" when evaluating the material presented below.

	At December 31,

	2013		2012
Estimated Proved Reserves and Other Information:
Oil (MMBbl)		532		497
NGLs (MMBbl)		72		62
Natural Gas (Bcf)		838		928
Total (MMBoe)		744		714
PV-10 (in millions)(1)	$	14,018	$	13,773
Standardized Measure of Discounted Future Net Cash Flows (in millions)(1)	$	9,223	$	9,073

(1): For an explanation of the non-GAAP financial measure PV-10 and a reconciliation of PV-10 to Standardized Measure, the most directly comparable GAAP financial measure, see "—Non-GAAP Financial Measure and Reconciliations" below.

The following table summarizes our net production, average realized prices and average costs for the periods indicated.

	Three Months Ended March 31,				Year Ended December 31,

	2014		2013		2013		2012		2011
Production Data:
Oil (MBbl/d)		95		88		90		88		80
NGLs (MBbl/d)		19		20		20		17		15
Natural gas (MMcf/d)		242		260		260		256		260
Average daily combined production (MBoe/d)(1)		154		151		154		148		138
Total combined production (MMBoe)(1)		14		14		56		54		50
Average realized prices:
Oil (per Bbl)	$	102.32	$	107.26	$	104.16	$	104.02	$	103.80
NGLs (per Bbl)	$	60.39	$	48.87	$	50.43	$	52.76	$	70.03
Natural gas (per Mcf)	$	4.78	$	3.40	$	3.73	$	2.94	$	4.31
Average costs per Boe:
Production costs	$	20.80	$	19.27	$	18.99	$	24.34	$	21.30
Other operating expenses	$	5.04	$	3.74	$	4.38	$	4.04	$	3.89
Depreciation, depletion and amortization	$	20.83	$	20.59	$	20.38	$	17.15	$	13.38
Taxes other than on income	$	3.76	$	3.90	$	3.29	$	3.09	$	2.84

(1): Natural gas volumes have been converted to Boe based on energy content of six Mcf of 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 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per Bbl and $3.66 per Mcf, respectively, resulting in an oil-to-gas ratio of over 25 to 1.

Non-GAAP Financial Measure and Reconciliation

PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and 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 income. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and 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 taxpaying status of the entity.

The following table provides a reconciliation of our Standardized Measure to PV-10.

	At December 31,

	2013			2012
	(in millions)
PV-10	$	14,018		$	13,773
Present value of future income tax discounted at 10%		(4,795	)		(4,700	)


Standardized Measure of Discounted Future Net Cash Flows	$	9,223		$	9,073

You should carefully consider the information included in this information statement, including the matters addressed under "Forward-Looking Statements," and the following risks.

We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks discussed below, any of which could materially and adversely affect our business, financial condition, cash flows, results of operations and stock price, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may ultimately materially and adversely affect our business, financial condition, cash flows, results of operations and stock price.

Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations.

Our operations are subject to complex and stringent federal, state and local laws and regulations. See "Business—Regulation of the Oil and Natural Gas Industry" for a description of the laws and regulations that affect our business. In order to conduct operations in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local governmental authorities. Costs of compliance may increase or operational delays may occur if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. New or additional permitting requirements, new interpretations of requirements or changes in our operations could also trigger the need for Environmental Assessments or more detailed Environmental Impact Statements under the National Environmental Policy Act ("NEPA") or Environmental Impact Reviews under the California Environmental Quality Act ("CEQA"), as well as litigation over the adequacy of those reviews, which could result in increased costs or delays of, or denial of rights to conduct, our development programs.

For example, in 2011 changes in the implementation of the permitting process of DOGGR depressed our capital spending in California for the year and slowed our development program. DOGGR is currently implementing additional changes, such as new hydraulic fracturing and well stimulation regulations pursuant to Senate Bill ("SB") 4 that are causing, and may cause additional, costs, delays and uncertainty.

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

Our financial results, financial condition, cash flow and rate of growth correlate closely to the prices we obtain for our products. Product prices are affected by a variety of factors, including changes in consumption patterns, global and local (particularly for gas) economic conditions, inventory levels, actual or threatened production disruptions, the actions of OPEC and other oil and natural gas producing countries, currency exchange rates, worldwide drilling and exploration activities, the effects of conservation, weather, geophysical and technical limitations, refining and processing disruptions, transportation bottlenecks and other matters affecting the supply and demand dynamics of oil, gas and NGLs, and the effect of changes in market perceptions. Occidental typically has not hedged commodity price risk and we do not expect to have a hedging program in the future. In addition, any significant increase in transportation infrastructure that increases the importation of crude oil to California from other parts of the country could negatively impact the price we receive for our crude oil.

Significant and sustained declines in oil and gas prices could require substantial downward adjustments to our estimated proved reserves. If this occurs, accounting rules may require us to write-down, as a noncash charge to earnings, part of the carrying value of our oil and gas properties.

Part of our strategy involves exploratory drilling, including drilling in new or emerging plays. Our drilling results are uncertain, and the value of our undeveloped acreage may decline if drilling is unsuccessful.

Exploration is inherently risky and its results are unpredictable. The results of our exploratory drilling in new or emerging plays are more uncertain than drilling results in areas that are developed and have established production. Where appropriate, we may try to limit exploration risk by exploring in areas close to our producing assets with similar geologic characteristics; however, this strategy may not succeed and may not adequately mitigate the exploration risks. We may not find commercial amounts of oil or gas, in which case the value of our undeveloped acreage may decline and could be impaired.

One of our important assets is our acreage in the Monterey shale play in the San Joaquin, Los Angeles and Ventura basins. The geology of the Monterey shale is highly complex and not uniform due to localized and varied faulting and changes in structure and rock characteristics. As a result, it differs from other shale plays that can be developed in part on the basis of their uniformity. Instead, individual Monterey shale drilling sites may need to be more fully understood and may require a more precise development approach, which could affect our ability, the timing or the cost to develop this asset.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing and other enhanced production techniques or fluid disposal could result in increased costs and additional operating restrictions or delay our implementation of, or cause us to change, our business strategy.

Well stimulation techniques like hydraulic fracturing and acid well stimulation are important and common practices used in our operations to increase the flow of fluids to production wells. These techniques have been regulated by DOGGR for decades; however, several federal, state and local agencies have recently proposed to further regulate them.

For example, in 2013, California adopted SB 4, which mandates further regulation of certain well stimulation techniques. Among other things, SB 4 requires:

The federal, state, and local governments could continue to seek to impose new or more stringent requirements for permitting, well construction, public disclosure or environmental review, seek to impose land use or other restrictions on hydraulic fracturing and other enhanced production techniques or fluid disposal, or otherwise seek to ban some or all of these activities. In addition, government agencies have investigated and continue to study whether injection activity can induce ground movement or seismicity. Our enhanced production operations or fluid disposal could give rise to litigation over claims related to alleged damage to the environment. Such new requirements, restrictions or litigation could result in potentially significant added costs to comply, delay or curtailment of our exploration, development, or production activities, and preclude us from drilling or stimulating wells, which could impair our expected production growth over the longer term.

In California, there have been proposals for tax increases for the past several years including a severance tax as high as 12.5% on all oil, gas and NGLs production in California. Although the proposals have not become law, well-funded campaigns by various interest groups could lead to future oil and gas severance taxes. The imposition of such a tax could severely reduce our profit margins and cash flow and

could ultimately result in lower oil production, which may reduce our capital expenditures and growth plans in California.

In addition, President Obama's budget proposal for the fiscal year 2015 recommended the elimination of certain federal income tax preferences currently available to oil and gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) an increase in the amortization period from two years to seven years for geophysical costs paid or incurred by independent producers in connection with the exploration for, or development of, oil or gas, all of which could potentially harm us.

Drilling for and producing oil and gas are high-risk activities with many uncertainties.

Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our decisions to explore, develop, purchase or otherwise exploit prospects or properties will depend in part on the evaluation of geophysical, geologic, engineering, production and other technical data, the analysis of which is often inconclusive or subject to varying interpretations. Our cost of drilling, completing, equipping and operating wells is also often uncertain. Overruns in budgeted expenditures are a common risk that can make a particular project uneconomical or less economical than forecast. We bear the risks of equipment failures, accidents, environmental hazards, adverse weather conditions, permitting or construction delays, title disputes, surface access disputes, disappointing drilling results or reservoir performance, including response to IOR or EOR efforts, and other associated risks.

We operate in a highly competitive environment for oilfield equipment, services, qualified personnel and acquisitions.

We compete for services to profitably develop our assets, to find or acquire additional reserves and to attract and retain qualified personnel. We have many competitors, some of which: (i) are larger and better funded, (ii) may be willing to accept greater risks or (iii) have special competencies. Historically, there have been periodic shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and gas industry can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages. Finally, competition for reserves can make it more difficult to find attractive investment opportunities or require delay of reserve replacement efforts.

Estimates of proved reserves and related future net cash flows are not precise. The actual quantities of our proved reserves and future net cash flows may prove to be lower than estimated.

Many uncertainties exist in estimating quantities of proved reserves and related future net cash flows. Our estimates are based on various assumptions, which may ultimately prove to be inaccurate.

The reserves information included in this information statement represents estimates prepared by Occidental's internal engineers, including some who will work for us. The procedures and methods used to estimate our reserves by these internal engineers were reviewed by independent petroleum consultants; however, no audit of estimated reserve volumes was conducted by these consultants. Reserves estimation is a partially subjective process of estimating accumulations of oil and gas. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variables and assumptions, including:

Misunderstanding of the variables, inaccurate assumptions, changed circumstances or new information could require us to make significant negative reserve revisions.

We currently expect improved recovery, extensions and discoveries to be our main sources for reserve additions, but factors such as geology, government regulations and permits and the effectiveness of development plans are partially or fully outside management's control and could cause unforeseen results.

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

Following our separation from Occidental, we expect to have total outstanding debt of approximately $ billion, including $ in senior notes and a $ term loan credit facility. Revolving commitments from our bank group are expected to total $ billion, of which approximately $ billion is expected to remain available to be borrowed.

Indebtedness outstanding under our credit facility bears interest at a variable rate, so a rise in interest rates will generate greater interest expense to the extent we do not purchase interest rate hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business because we would be required to use a greater proportion of our cash flow to pay interest and principal. Following the separation and incurrence of $ billion of debt, we could incur $ in additional indebtedness in compliance with the terms of our debt facilities. In addition, we can incur obligations that do not constitute indebtedness under the indenture or credit facility.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional equity on terms that we may not find attractive if it may be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness.

Our business requires substantial capital expenditures. We may be unable to fund these expenditures through operating cash flow or obtain any needed additional capital on satisfactory terms or at all, which could lead to a decline in our oil and gas reserves or production. Our capital investment program is also susceptible to risks that could materially affect its implementation.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and exploration of oil and gas reserves. We have developed a multi-year capital investment program to execute our growth strategy. We spent approximately $1.7 billion of capital on development and exploration expenses during the year ended December 31, 2013, funded by our operating cash flow of $2.5 billion. Under our 2014 capital budget, we currently intend to invest approximately $2.1 billion for development and exploration activities this year.

Our ability to deploy capital as planned depends on a number of uncertainties, including: (i) regulatory and third-party approvals; (ii) our inability to timely drill wells due to technical factors and contract terms; (iii) the availability of capital, equipment, services and personnel; (iv) commodity prices and sales point disruptions; and (v) drilling and completion costs and results. Because of these and other

potential uncertainties, we may be unable to deploy capital in the manner planned and actual development activities may materially differ from those presently anticipated.

We intend to finance our future capital expenditures, other than any significant acquisitions, primarily through cash flow from operations and, if necessary, through borrowings under our credit facility or the issuance of debt or equity securities. Although we intend to reinvest substantially all of our cash flow in our business, we may not generate sufficient cash flow to fund our growth plans or to generate acceptable returns. Additional financing may not be available on acceptable terms or at all if there is not market demand or if our lenders refuse to expand our existing credit as they may do at their discretion. In the event additional capital is needed and unavailable, we may curtail drilling, development and other activities or be forced to sell some our assets on an unfavorable basis.

We periodically evaluate our unproved oil and natural gas properties for impairment, and could be required to recognize noncash charges to earnings of future periods.

At December 31, 2013, we carried unproved property costs of $0.9 billion. GAAP requires periodic evaluation of these costs to assess realizability. These evaluations will be affected by management's development plans, the results of exploration activities, commodity prices, planned future sales and expiration of all or a portion of the leases, contracts and permits appurtenant to such properties. If the quantity of potential reserves is not sufficient to fully recover the cost invested in or management's plans change with respect to such properties, we will recognize noncash charges to earnings of future periods.

Laws and regulations, including those pertaining to land use and environmental protection, could delay or restrict our operations and cause us to incur substantial costs.

Our operations are subject to numerous federal, state, local and other laws and regulations governing health and safety, the release or discharge of materials into the environment or otherwise relating to land use or environmental protection. These laws and regulations:

These laws and regulations may have the effect of restricting the amount of oil, NGLs and natural gas that we produce. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal fines and penalties and liability for non-compliance, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or limiting our operations. Under certain environmental laws and regulations, we could be subject to strict or joint and several liability for the removal or remediation of previously released materials or property contamination.

Restrictions on our ability to obtain, use, manage or dispose of water may have an adverse effect on our operations.

Water is an essential component of our operations. Approximately 95% of the fluids we produce are brackish waters, not suitable for agricultural use, that need to be managed, recycled or disposed of, and we treat and re-use substantial volumes of this water for activities such as waterflooding, steamflooding, pressure management, well completion and stimulation, including hydraulic fracturing. Although we have been able to use recycled and produced water from our operations for a substantial portion of our water needs and to provide water to local agricultural users in certain basins, we also use supplied water from various local and regional sources. Some of our fields are more dependent on supplied water to support operations like pressure maintenance or steam injection. Due to severe drought in California, some local and regional water districts and the state government have begun implementing regulations that restrict water usage and increase the cost of water.

Existing regulations restrict our ability and increase our cost to manage and dispose of wastewater. The federal Clean Water Act ("CWA") and similar state laws impose restrictions and strict controls on the discharge of produced waters and waste where such discharges could affect surface or ground waters. We must obtain permits or waivers for certain discharges into waters and wetlands and for construction activities that may affect regulated water resources. For example, our operating costs have increased due to policy changes in December 2013 by California state and regional water quality agencies that restrict or prohibit discharges that were formerly permitted. These regulations and attendant liabilities may increase our costs of operations. Future federal, state, local and other regulations could impose additional restrictions and costs on our ability to obtain and use water for our operations.

Our AMI Agreement may adversely affect our ability to operate outside of California.

In connection with the spin-off, we intend to enter into an AMI Agreement, which provides Occidental with the right to acquire a % interest in and rights with respect to certain oil and gas properties we acquire in the United States, other than oil and gas properties in the state of California, for five years following the completion of the spin-off. Our ability to own and operate oil and gas properties outside the state of California may be limited for the five-year term of the AMI Agreement to the extent that doing so would violate the terms of this agreement. If we were to change our current strategy of focusing exclusively on opportunities in California, the AMI Agreement could adversely affect our ability to pursue opportunities outside of California during the five years following the spin-off. See "Arrangements Between Occidental and Our Company—AMI Agreement."

We may not drill our identified sites at the times we scheduled or at all.

We have specifically identified and scheduled drilling locations over the next several years. These drilling locations represent a significant part of our growth strategy. Our ability to profitably drill and develop these locations depends on a number of variables, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals, available transportation capacity and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. We view the risk profile for our exploration drilling locations and our prospective resource drilling locations as being higher than for our other drilling locations due to relatively less available geologic and production data and drilling history, in particular with respect to our prospective resource locations, which are in unproven geologic plays. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate. We cannot guarantee that these prospective drilling locations or any other drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these drilling locations. In addition, some of our leases could expire if we do not establish production in the leased acreage. The combined net acreage expiring in the next three years represents 12% of our total net undeveloped acreage at December 31, 2013. Our actual drilling activities may materially differ from those presently identified.

Concerns about climate change and other air quality issues may affect our operations or results.

Climate change, the costs that may be associated with its effects and the regulation of greenhouse gases ("GHGs") may affect our business in many ways, including increasing the costs to provide our products and services, and reducing demand for, and consumption of, our products and services. In addition, legislative and regulatory responses to climate change may increase our operating costs. In 2006, California adopted Assembly Bill ("AB") 32, known as the "California Global Warming Solutions Act of 2006," which establishes a statewide cap on GHG emissions, including on the oil and natural gas production industry, and a "cap-and-trade" program. In December 2010, the California Air Resources Board adopted regulations to implement AB 32 that commenced on January 1, 2012, and require us to obtain GHG emissions allowances corresponding to our reported GHG emissions. In 2013, we incurred approximately $34 million of costs for GHG emissions allowances in California.

Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act ("CAA") and associated state laws and regulations. In addition, California air quality laws and regulations are in many instances more stringent than comparable federal laws and regulations. Regulatory requirements relating to air emissions are particularly stringent in Southern and Central California, where most of our operations are located. As these requirements become more stringent, we cannot assure you that we will continue to be able to implement them in a cost-effective manner. Also, as a result of existing and future air quality initiatives, we could face risks of increased costs and taxes, an inability to execute projects and reduced demand for our products and services.

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

Our acquisition activities carry risks that we may: (i) not fully realize anticipated benefits due to less-than-expected reserves or production or changed circumstances, such as the deterioration of gas prices in recent years; (ii) bear unexpected integration costs or experience other integration difficulties; (iii) experience share price declines based on the market's evaluation of the activity or (iv) assume liabilities that are greater than anticipated.

In connection with our acquisitions, we are often only able to perform limited due diligence. Successful acquisitions of oil and gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing for recovering the reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact and incomplete, and we may be unable to make these assessments with a high degree of accuracy.

There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware or for which we are unable to obtain indemnity.

Also, we may issue our securities in connection with acquisitions. The amount of common stock issued in connection with an acquisition could constitute a material portion of our then outstanding common stock, which could significantly dilute existing shareholders and depress our share price.

We may incur substantial losses and be subject to substantial liability claims as a result of catastrophic events. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not fully insured against all risks. Our oil and gas exploration and production activities, including well stimulation and completion activities, are subject to operating risks associated with drilling for and producing oil and gas, such as well blowouts, fires, explosions, releases or discharges of hazardous or toxic materials and industrial accidents. Other catastrophic events such as earthquakes, floods, mudslides, droughts, terrorist attacks and other events that cause operations to cease or be curtailed may negatively affect our business and the communities in which we operate. We may be unable to obtain, or

may elect not to obtain, insurance for certain risks if we believe that the cost of available insurance is excessive relative to the risks presented.

Cyber attacks on businesses have escalated in recent years. We rely on electronic systems and networks to control and manage our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant.

Operational issues could restrict access to markets for the commodities we produce.

Our ability to market our production of oil, gas and NGLs depends on a number of factors, including the proximity of production fields to pipelines and terminal facilities, competition for capacity on such facilities and the ability of such facilities to gather, transport or process our commodities.

We may not realize the anticipated benefits from our separation from Occidental.

We may not realize the benefits that we anticipate from our separation from Occidental. These benefits include the following:

We may not achieve the anticipated benefits from our separation for a variety of reasons. For example, the process of separating our business from Occidental and operating as an independent public company may distract our management from focusing on our business and strategic priorities. Although we intend to reinvest substantially all of our cash flow in our business, we may not generate sufficient cash flow to fund our growth plans and to generate acceptable returns. Moreover, even with equity compensation tied to our business, we may not be able to attract and retain employees as desired. We also may not fully realize the anticipated benefits from our separation if any of the other matters identified as risks in this "Risk Factors" section were to occur.

The combined value of Occidental and our shares after the spin-off may not equal or exceed the value of Occidental shares prior to the spin-off.

We cannot assure you that the combined trading prices of Occidental's common stock and our common stock after the spin-off, as adjusted for any changes in the combined capitalization of these companies, will be equal to or greater than the trading price of Occidental common stock prior to the spin-off. Until the market has fully evaluated the business of Occidental without the California business, the price at which Occidental common stock trades may fluctuate significantly. Similarly, until the market has fully evaluated our company, the price at which our common stock trades may fluctuate significantly.

Our historical and pro forma financial information may not be representative of the results we would have achieved as a stand-alone public company and may not be a reliable indicator of our future results.

The historical and pro forma financial information included in this information statement has been derived from Occidental's accounting records and may not reflect what our financial position, results of operations or cash flows would have been had we been an independent, stand-alone entity during the periods presented or those that we will achieve in the future. Occidental did not account for us, and we were not operated, as a separate, stand-alone company for the historical periods presented. The costs and expenses reflected in our historical financial information include an allocation for certain corporate functions historically provided by Occidental, including expense allocations for: (1) executive oversight, accounting, procurement, engineering, drilling, exploration, finance, internal audit, legal, risk management, tax, treasury, information technology, government relations, investor relations, public relations, financial reporting, human resources, marketing, ethics and compliance, and certain other shared services; (2) certain employee benefits and incentives; and (3) share-based compensation, that may be different from the comparable expenses that we would have incurred had we operated as a stand-alone company. We have allocated these expenses in our historical financial information on the basis of direct usage when identifiable, with the remainder allocated based on estimated time spent by Occidental personnel, headcount or our relative size compared to Occidental and its subsidiaries. In addition, we have attempted to include recurring costs of operating as a stand-alone company in our pro forma financial statements, although only the additional costs we have determined to be factually supportable are included as pro forma adjustments. There are expected to be additional incremental costs of operating as a stand-alone company not reflected in the unaudited pro forma combined financial statements, which are currently estimated to be approximately $ million before income taxes annually. These estimates may not prove to be accurate.

In addition, if we fail to implement the requirements with respect to our internal accounting and audit functions, our ability to report our operating results on a timely and accurate basis could be impaired and we might be subject to sanctions or investigation by regulatory authorities, such as the SEC or the NYSE. Any such action could harm our reputation and the confidence of investors in our company. For additional information, see "Selected Historical Combined Financial Data," "Unaudited Pro Forma Combined Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our financial statements and related notes included elsewhere in this information statement.

A large number of our shares are or will be eligible for future sale, which may cause the market price for our common stock to decline.

Upon completion of the spin-off, we will have an aggregate of approximately shares of our common stock outstanding. All of those shares (other than those held by our "affiliates") will be freely tradable without restriction. Shares held by our affiliates, which include our directors and executive officers, can be sold subject to volume, manner of sale and notice provisions. We estimate that our affected directors and executive officers will beneficially own approximately shares of our common stock immediately following the distribution. We are unable to predict whether large amounts of our common stock will be sold in the open market following the spin-off. We are also unable to predict whether a sufficient number of buyers will be in the market at that time. Occidental stockholders may sell the shares of our common stock they receive in the distribution for various reasons. For example, such stockholders may not believe our business profile or level of market capitalization as an independent company fits their investment objectives. A change in the level of analyst coverage following the spin-off could also negatively impact demand for our shares. In addition, following the distribution, Occidental will retain ownership of up to 19.9% of our common stock. Occidental expects to dispose of all Retained Securities through one or more subsequent exchanges for Occidental common stock. Occidental will distribute pro rata any shares it does not dispose of pursuant to such exchanges in no event later than two years after the distribution.

Pursuant to the Stockholder's and Registration Rights Agreement, we will agree that, upon the request of Occidental, we will use our best efforts to effect the registration under applicable securities laws of the disposition of shares of common stock retained by Occidental and to cooperate with Occidental to facilitate its disposition of the Retained Securities through one or more exchanges for Occidental common stock. Any disposition by Occidental, or any other significant shareholder, of our common stock in the public market, or the perception that such dispositions may occur, could adversely affect prevailing market prices for our common stock.

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

Pursuant to the Separation and Distribution Agreement and other agreements with Occidental, Occidental will agree to indemnify us for certain liabilities, and we will agree to indemnify Occidental for certain liabilities, in each case for uncapped amounts, as discussed further in "Arrangements Between Occidental and Our Company." Indemnities that we may be required to provide Occidental will not be subject to any cap, may be significant and could negatively impact our business, particularly indemnities relating to our actions that could impact the tax-free nature of the distribution. Third parties could also seek to hold us responsible for any of the liabilities that Occidental has agreed to retain. Further, there can be no assurance that the indemnity from Occidental will be sufficient to protect us against the full amount of such liabilities, or that Occidental will be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from Occidental any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.

Our costs will increase as a result of operating as a stand-alone public company, and our management will be required to devote substantial time to complying with public company regulations.

Historically, our operations have been fully integrated within Occidental, and we have relied on Occidental to provide certain corporate functions. As a stand-alone public company, we may incur additional expenses for executive oversight, accounting, finance, risk management, treasury, tax, financial reporting, internal audit, legal, information technology, governmental relations, public relations, investor relations, human resources, procurement, engineering, drilling, exploration, ethics and compliance, marketing and certain other services that we have not incurred historically.

In addition, after the spin-off, we will become obligated to file with the SEC annual and quarterly information and other reports. We will also be required to ensure that we have the ability to prepare financial statements that are fully compliant with all SEC reporting requirements on a timely basis. In addition, we will become subject to other reporting and corporate governance requirements, including certain requirements of the NYSE, and certain provisions of the Sarbanes-Oxley Act of 2002, and the regulations promulgated thereunder, which will impose significant compliance obligations upon us.

Following the separation, Occidental will provide us with certain transitional services that may not be sufficient to meet our needs. We may have difficulty finding supplemental or, ultimately, replacement services or be required to pay increased costs to supplement or, ultimately, replace these services.

Certain administrative services required by us for the operation of our business are currently provided by Occidental and its subsidiaries, including, executive oversight, accounting, procurement, engineering, drilling, exploration, finance, internal audit, legal, risk management, tax, treasury, information technology, government relations, investor relations, public relations, financial reporting, human resources, ethics and compliance, marketing and certain other shared services. Prior to the completion of the separation, we will enter into agreements with Occidental related to the separation of our business operations from Occidental, including a Transition Services Agreement. We believe it is helpful for Occidental to provide transitional assistance for us under the Transition Services Agreement to facilitate the efficient operation

of our business as we transition to becoming a stand-alone public company. While these services are being provided to us by Occidental, our operational flexibility to modify or implement changes with respect to such services or the amounts we pay for them will be limited. After the expiration or termination of the Transition Services Agreement, we may not be able to replace these services or enter into appropriate third-party agreements on terms and conditions, including cost, comparable to those that we will receive from Occidental under the Transition Services Agreement. Although we intend to replace portions of the services currently provided by Occidental, we may encounter difficulties replacing certain services or be unable to negotiate pricing or other terms as favorable as those we currently have in effect. See "Arrangements Between Occidental and Our Company—Transition Services Agreement."

The agreements between us and Occidental will not be made on an arm's length basis.

The agreements we will enter into with Occidental in connection with the spin-off, including the Separation and Distribution Agreement, Tax Sharing Agreement, Employee Matters Agreement, and Transition Services Agreement, will have been negotiated in the context of the spin-off while we were still a wholly-owned subsidiary of Occidental. Accordingly, during the period in which the terms of those agreements will have been negotiated, we will not have had an independent board of directors or a management team independent of Occidental. As a result, the terms of those agreements may not reflect terms that would have resulted from arm's-length negotiations between unaffiliated third parties. The terms relate to, among other things, the allocation of assets, liabilities, rights and other obligations between Occidental and us. See "Arrangements Between Occidental and Our Company" for a description of these obligations and the allocation of liabilities between Occidental and us.

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

Under the Tax Sharing Agreement, we will agree to take certain actions or refrain from taking certain actions to ensure that the separation qualifies for tax-free status under section 355 and/or section 368(a)(1)(D) of the Code. We will also make various other covenants in the Tax Sharing Agreement intended to ensure the tax-free status of the separation. These covenants restrict our ability to sell assets outside the ordinary course of business, to issue or sell additional common stock or other securities (including securities convertible into our common stock), or to enter into certain other corporate transactions. For example, for a period of two years after the final disposition of the Retained Securities by Occidental, absent approval by Occidental, we may not enter into any transaction that would cause us to undergo either a 50% or greater change in the ownership of our voting stock or a 50% or greater change in the ownership (measured by value) of all classes of our stock in transactions considered related to the separation. See "Arrangements Between Occidental and Our Company—Tax Sharing Agreement."

Further, under the Tax Sharing Agreement, we are required to indemnify Occidental against certain tax-related liabilities incurred by Occidental (including any of its subsidiaries) relating to the separation, to the extent caused by our breach of any representations or covenants made in the Tax Sharing Agreement or the separation and distribution agreement, or made in connection with the private letter ruling or the tax opinion. These liabilities include the substantial tax-related liability (calculated without regard to any net operating loss or other tax attribute of Occidental) that would result if the distribution of our stock to Occidental stockholders failed to qualify as a tax-free transaction. In addition, we have agreed to pay 50% of any taxes arising from the separation to the extent that the tax is not attributable to the fault of either party.

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

For any tax periods (or portion thereof) in which Occidental owns at least 80% of the total voting power and value of our common stock, we and our subsidiaries will be included in Occidental's consolidated group for federal income tax purposes. In addition, we or one or more of our U.S.

subsidiaries may be included in the combined, consolidated or unitary tax returns of Occidental or one or more of its subsidiaries for state or local income tax purposes. Under the Tax Sharing Agreement, for each period in which we or any of our subsidiaries are consolidated or combined with Occidental for purposes of any tax return, and with respect to which such tax return has not yet been filed, Occidental will prepare a pro forma tax return for us as if we filed our own consolidated, combined or unitary return, except that such pro forma tax return will generally include current income, deductions, credits and losses from us (with certain exceptions), will not include any carryovers or carrybacks of losses or credits and will be calculated without regard to the federal Alternative Minimum Tax. We will reimburse Occidental for any taxes shown on the pro forma tax returns. In addition, by virtue of Occidental's controlling ownership and the Tax Sharing Agreement, Occidental will effectively control all of our tax decisions in connection with any consolidated, combined or unitary income tax returns in which we (or any of our subsidiaries) are included. The Tax Sharing Agreement provides that Occidental will have sole authority to respond to and conduct all tax proceedings (including tax audits) relating to us, to prepare and file all consolidated, combined or unitary income tax returns in which we are included on our behalf (including the making of any tax elections), and to determine the reimbursement amounts in connection with any pro forma tax returns. This arrangement may result in conflicts of interest between Occidental and us. For example, under the Tax Sharing Agreement, Occidental will be able to choose to contest, compromise or settle any adjustment or deficiency proposed by the relevant taxing authority in a manner that may be beneficial to Occidental and detrimental to us; provided, however, that Occidental may not make any settlement that would materially increase our tax liability without our consent. See "Arrangements Between Occidental and Our Company—Tax Sharing Agreement."

Moreover, notwithstanding the Tax Sharing Agreement, federal law provides that each member of a consolidated group is liable for the group's entire tax obligation. Thus, to the extent Occidental or other members of Occidental's consolidated group fail to make any federal income tax payments required by law, we could be liable for the shortfall with respect to periods in which we were a member of Occidental's consolidated group. Similar principles may apply for state or local income tax purposes where we file combined, consolidated or unitary returns with Occidental or its subsidiaries for federal, foreign, state or local income tax purposes. Pursuant to the Tax Sharing Agreement, Occidental has agreed to indemnify us for any taxes attributable to Occidental that we are required to pay as a result of our membership in the Occidental consolidated group during such period.

Occidental, its stockholders, or we could have significant tax liabilities if the separation, and certain transactions in preparation therefore, are not tax-free.

The separation is conditioned on Occidental's receipt of a private letter ruling from the IRS substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the separation will not cause the distribution to be taxable to Occidental or its affiliates. The separation is further conditioned on Occidental's tax counsel issuing an opinion in form and substance acceptable to Occidental that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off qualifies as a tax-free transaction under Sections 355 and/or 368(a)(1)(D) of the Code. The private letter ruling and opinion will rely on facts, assumptions, representations and undertakings from Occidental and us regarding the past and future conduct of the companies' respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied, Occidental and its stockholders may not be able to rely on the private letter ruling or the opinion of its tax advisor and could be subject to significant tax liabilities. In addition, an opinion of counsel is not binding upon the IRS, so, notwithstanding the opinion of Occidental's tax advisor, the IRS could conclude upon audit that the separation is taxable in full or in part. The IRS may determine that separation is taxable for other reasons, including as a result of certain significant changes in the stock ownership of Occidental or us after the separation. If the separation is determined to be taxable for U.S. federal income tax purposes, Occidental or its stockholders could incur

significant income tax liabilities, and we could incur significant liabilities. For a discussion of the potential tax consequences to Occidental stockholders if the separation is determined to be taxable, see "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off." For a description of the sharing of such liabilities between Occidental and us, see "Arrangements Between Occidental and Our Company—Tax Sharing Agreement."

Following the spin-off, several members of our board of directors and management may have actual or potential conflicts of interest because of their ownership of shares of common stock of Occidental.

Following the spin-off, several members of our board of directors and management will initially own common stock of Occidental or options to purchase common stock of Occidental or other equity-based awards, in addition to equity interests in us, because of their current or prior relationships with Occidental, which could create, or appear to create, potential conflicts of interest when our directors and executive officers are faced with decisions that could have different implications for Occidental and us.

The spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements.

The separation is subject to review under various state and federal fraudulent conveyance laws. Under these laws, if a court in a lawsuit by an unpaid creditor or an entity vested with the power of such creditor (including a trustee or debtor-in-possession in a bankruptcy by us or Occidental or any of our respective subsidiaries) were to determine that Occidental or any of its subsidiaries did not receive fair consideration or reasonably equivalent value for distributing our common stock or taking other action as part of the separation, or that we or any of our subsidiaries did not receive fair consideration or reasonably equivalent value for incurring indebtedness, including the new debt incurred by us in connection with the separation, transferring assets or taking other action as part of the separation and, at the time of such action, we, Occidental or any of our respective subsidiaries (i) was insolvent or would be rendered insolvent, (ii) had reasonably small capital with which to carry on its business and all business in which it intended to engage or (iii) intended to incur, or believed it would incur, debts beyond its ability to repay such debts as they would mature, then such court could void the separation as a constructive fraudulent transfer. The court could impose a number of different remedies, including voiding our liens and claims against Occidental, or providing Occidental with a claim for money damages against us in an amount equal to the difference between the consideration received by Occidental and the fair market value of our company at the time of the separation.

The measure of insolvency for purposes of the fraudulent conveyance laws will vary depending on which jurisdiction's law is applied. Generally, however, an entity would be considered insolvent if the present fair saleable value of its assets is less than (i) the amount of its liabilities (including contingent liabilities) or (ii) the amount that will be required to pay its probable liabilities on its existing debts as they become absolute and mature. No assurance can be given as to what standard a court would apply to determine insolvency or that a court would determine that we, Occidental or any of our respective subsidiaries were solvent at the time of or after giving effect to the spin-off, including the distribution of our common stock.

Under the Separation and Distribution Agreement, from and after the separation, each of Occidental and we will be responsible for the debts, liabilities and other obligations related to the business or businesses which it owns and operates following the consummation of the separation, and each of Occidental and we will assume or retain certain liabilities for the operation of our respective businesses prior to the spin-off and certain liabilities related to the spin-off. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the Separation and Distribution Agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to Occidental, particularly if Occidental were to refuse or

were unable to pay or perform the subject allocated obligations. See "Arrangements Between Occidental and Our Company—Separation and Distribution Agreement."

No market currently exists for our common stock. We cannot assure you that an active trading market will develop for our common stock.

Prior to the completion of the separation, there has been no public market for shares of our common stock. We cannot predict the extent to which investor interest in our company will lead to the development of a trading market on the NYSE or otherwise, or how liquid that market might become. If an active market does not develop, you may have difficulty selling any shares of our common stock that you receive in the separation.

The market price and trading volume of our common stock may be volatile and you may not be able to resell your shares at or above the initial market price of our common stock following the spin-off.

The market price of our stock may be influenced by many factors, some of which are beyond our control, including those described above in "—Risks Related to Our Business" and the following:

As a result of these factors, holders of our common stock may not be able to resell their shares at or above the initial market price following the separation or may not be able to resell them at all. In addition, price volatility may be greater if trading volume of our common stock is low.

We do not anticipate paying significant dividends on our common stock in the foreseeable future. As a result, you will need to sell your shares of common stock to receive any significant income.

We intend to pay a cash dividend of $0.01 per share per quarter, or $0.04 per share per year. We currently intend to retain the remainder of our future earnings to support the growth and development of our business and do not anticipate increasing the dividend on our common stock in the foreseeable future. The future payment of any dividends will be at the sole discretion of our board of directors and will depend on many factors, including our earnings, capital requirements, financial condition, the limitations imposed by the Delaware General Corporation Law (the "DGCL") and other considerations that our board of directors deems relevant. As a result, to receive significant income, you will need to sell your shares of common stock. You may not be able to sell your shares of common stock at or above the price you paid for them.

Provisions contained in our amended and restated certificate of incorporation and amended and restated bylaws could discourage a takeover attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, the ability of our stockholders to sell their shares for a premium.

Provisions contained in our certificate of incorporation and bylaws provide for limitations on the removal and replacement of directors, a classified board through 2018, limitations on stockholder proposals at meetings of stockholders and limitations on stockholder action by written consent and the inability of stockholders to call special meetings, could make it more difficult for a third-party to acquire control of our company. Our certificate of incorporation also authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could increase the difficulty for a third-party to acquire us, which may reduce or eliminate our stockholders' ability to sell their shares of our common stock at a premium. See "Description of Capital Stock—Anti-Takeover Effects of Provisions of our Amended and Restated Certificate of Incorporation, our Amended and Restated Bylaws and Delaware Law."

Our amended and restated certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders' ability to obtain an alternative judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for:

Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a shareholder's ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions.

The information in this information statement includes "forward-looking statements." The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. You can typically identify "forward-looking statements" by the use of forward-looking words such as "aim," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "likely," "may," "might," "objective," "outlook," "plan," "potential," "predict," "project," "seek," "should," "target, "will" or "would" and other similar words. Such statements may include statements regarding our future financial position, budgets, capital expenditures, projected production growth, projected costs, plans and objectives of management for future operations and possible future strategic transactions. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading "Risk Factors" included in this information statement.

Any forward-looking statement in which we, or our management, express an expectation or belief as to future results, is made in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. Taking this into account, the following are identified as important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, our company:

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no responsibility to publicly release the result of any revision of our forward-looking statements after the date they are made.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

As part of a strategic review to streamline and focus operations, Occidental's board of directors reviewed the possibility and advisability of separating its California business from Occidental's other businesses. On February 14, 2014, Occidental announced that its board of directors had authorized management to pursue the spin-off of its California business into a standalone, publicly traded company. On , 2014, Occidental announced that its board of directors had unanimously approved the spin-off and the distribution of over 80% of the stock of the new company to Occidental's shareholders as of the record date of , 2014. This authorization is subject to the satisfaction or waiver by Occidental, in its sole discretion, of the conditions described below under "—Conditions to the Spin-Off." Following our spin-off from Occidental, we will be an independent, publicly owned company.

To complete the spin-off on the Closing Date, Occidental will, following the restructuring transactions, distribute to its stockholders over 80% of the shares of our common stock. The distribution will occur on the distribution date, which is , 2014. Each holder of Occidental common stock will receive shares of our common stock for each share of Occidental common stock held by such stockholder at the close of business on , 2014, the record date. After completion of the spin-off, we will own and operate the California business as an independent publicly traded company.

Each holder of Occidental common stock will continue to hold his, her or its shares in Occidental. No vote of Occidental stockholders is required or is being sought in connection with the spin-off, and Occidental stockholders will not have any appraisal rights in connection with the spin-off.

The distribution of our common stock as described in this information statement is subject to the satisfaction, or waiver by the board of directors of Occidental, of certain conditions. In addition, Occidental has the right not to complete the spin-off if, at any time prior to the distribution, the board of directors of Occidental determines, in its sole discretion, that the spin-off is not in the best interests of Occidental or its stockholders or market conditions do not warrant completing the separation at that time. For a more detailed description, see "—Conditions to the Spin-Off."

The spin-off is expected to provide each company with a number of material opportunities and benefits, including the following:

The general terms and conditions relating to the spin-off will be set forth in a Separation and Distribution Agreement between us and Occidental. Under the Separation and Distribution Agreement, the distribution will be effective as of 11:59 p.m., Eastern Time, on , 2014, the distribution date.

As a result of the spin-off, on the distribution date, each holder of Occidental common stock will receive shares of our common stock for each share of Occidental common stock owned. In order to receive shares of our common stock in the spin-off, an Occidental stockholder must be a stockholder at the close of business of the NYSE on , 2014, the record date.

On the distribution date, Occidental will release the shares of our common stock to our distribution agent to distribute to Occidental stockholders. For Occidental stockholders of record, our distribution agent will credit their shares of our common stock to book-entry accounts established to hold their shares of our common stock. Our distribution agent will send these stockholders, including any Occidental stockholder that holds physical share certificates of Occidental common stock and is the registered holder of such shares of Occidental common stock represented by those certificates on the record date, a statement reflecting their ownership of our common stock. Book-entry refers to a method of recording stock ownership in records in which no physical certificates are used. Shares of our common stock will be credited by the broker or other nominee for stockholders who own Occidental common stock through a broker or other nominee. We expect that it will take the distribution agent one to two weeks to electronically issue shares of our common stock to Occidental stockholders or their bank or brokerage firm by way of direct registration in book-entry form. Trading of our stock will not be affected by this delay in issuance by the distribution agent. As further discussed below, we will not issue fractional shares of our common stock in the distribution. Following the spin-off, stockholders whose shares are held in book-entry form may request that their shares of our common stock be transferred to a brokerage or other account at any time.

Occidental stockholders will not be required to make any payment or surrender or exchange their shares of Occidental common stock or take any other action to receive their shares of our common stock. No vote of Occidental stockholders is required or sought in connection with the spin-off, including the restructuring transactions, and Occidental stockholders have no appraisal rights in connection with the spin-off.

Occidental currently expects to dispose of all of the Retained Securities through one or more subsequent exchanges of the Retained Securities for Occidental common stock. Any shares Occidental does not dispose of through exchanges will be distributed pro rata to Occidental shareholders in no event later than two years after the distribution.

The distribution agent will not distribute any fractional shares of our common stock to Occidental stockholders. Instead, as soon as practicable on or after the distribution date, the distribution agent will aggregate fractional shares of our common stock held by holders of record into whole shares, sell them in the open market at the prevailing market prices and then distribute the aggregate net sale proceeds ratably to Occidental stockholders who would otherwise have been entitled to receive fractional shares of our common stock. The amount of this payment will depend on the prices at which the distribution agent sells the aggregated fractional shares of our common stock in the open market shortly after the distribution date. We will be responsible for paying any brokerage fees, which we do not expect to be material. The receipt of cash in lieu of fractional shares of our common stock will generally result in a taxable gain or loss to the recipient stockholder. Each stockholder entitled to receive cash proceeds from these shares should consult his, her or its own tax advisor as to the stockholder's particular circumstances. The tax consequences of the distribution are described in more detail under "—U.S. Federal Income Tax Consequences of the Spin-Off."

The following is a summary of the material U.S. federal income tax considerations relating to holders of Occidental common stock as a result of the distribution. This summary is based on the Code, the Treasury Regulations promulgated thereunder and judicial and administrative interpretations thereof, in each case as in effect and available as of the date of this information statement and all of which are subject to differing interpretations that may change at any time, possibly with retroactive effect. Any such change could affect the tax consequences described below.

Except as specifically described below, this summary is limited to holders of Occidental common stock that are U.S. holders (as described below). For purposes of this summary, a U.S. holder is a beneficial owner of Occidental common stock that is, for U.S. federal income tax purposes:

A non-U.S. holder is a beneficial owner (other than an entity treated as a partnership or other pass-through entity for U.S. federal income tax purposes) of shares of Occidental common stock who is not a U.S. holder.

This summary does not discuss all tax considerations that may be relevant to Occidental shareholders in light of their particular circumstances, nor does it address the consequences to Occidental shareholders subject to special treatment under the U.S. federal income tax laws, such as:

This summary does not address the U.S. federal income tax consequences to Occidental shareholders who do not hold Occidental common stock as capital assets. Moreover, this summary does not address any state, local or non-U.S. tax consequences or any estate, gift or other non-income tax consequences.

If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds shares of Occidental common stock, the tax treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership holding shares of Occidental common stock, you should consult your tax advisor.

HOLDERS OF OCCIDENTAL COMMON STOCK SHOULD CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE SPECIFIC U.S. FEDERAL, STATE AND LOCAL AND NON-U.S. TAX CONSEQUENCES OF THE DISTRIBUTION IN LIGHT OF THEIR PARTICULAR CIRCUMSTANCES AND THE EFFECT OF POSSIBLE CHANGES IN LAW THAT MIGHT AFFECT THE TAX CONSEQUENCES DESCRIBED HEREIN.

Occidental has requested (i) a private letter ruling substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates and (ii) an opinion from its tax counsel regarding, among other things, that the spin-off qualifies as a tax-free transaction under Section 355 and/or Section 368(a)(1)(D) of the Code. Assuming that the distribution qualifies as a tax-free distribution,

The private letter ruling and tax opinion of counsel will rely on certain facts, assumptions, representations and undertakings from Occidental and us regarding the past and future conduct of the companies' respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied, Occidental and its stockholders may not be able to rely on the private letter ruling or the opinion of its tax advisor. In addition, an opinion of counsel is not binding on the IRS, so, notwithstanding the opinion of Occidental's tax advisor, the IRS could conclude upon audit that the distribution is taxable if it disagrees with the conclusions in the opinion or for other reasons. There can be no assurance that the IRS or the courts will not challenge the qualification of the distribution as a tax-free transaction under Section 355 and/or Section 368(a)(1)(D) of the Code or that such challenge would not prevail.

Even if the distribution otherwise qualifies as tax-free, Occidental or its affiliates may recognize taxable gain under Section 355(e) of the Code if there are one or more acquisitions (including issuances) of either our stock or the stock of Occidental, representing 50% or more, measured by vote or value, of the then-outstanding stock of either corporation, and the acquisition or acquisitions are deemed to be part of a plan or series of related transactions that include the distribution. Any such acquisition of our stock within two years before the initial distribution or two years after the final disposition of the Retained Securities (with exceptions, including public trading by less-than 5% stockholders and certain compensatory stock issuances) generally will be presumed to be part of such a plan unless Occidental can rebut that presumption. If Occidental recognizes gain under Section 355(e), it would result in a significant U.S. federal income tax liability to Occidental (although the distribution would generally be tax-free to Occidental stockholders), and, under some circumstances, the Tax Sharing Agreement would require us to indemnify Occidental for such tax liability. See "—Indemnification" and "Arrangements Between Occidental and Our Company—Tax Sharing Agreement."

Material U.S. Federal Income Tax Consequences of the Distribution to U.S. Holders

The discussion above under "—Tax-free Status of the Distribution" applies to U.S. holders if the distribution qualifies as tax-free under Section 355 of the Code.

If the distribution of shares of our common stock does not qualify under Section 355, then each U.S. holder of Occidental receiving shares of our common stock in the distribution generally would be treated as receiving a distribution in an amount equal to the fair market value of such shares (including fractional shares in lieu of which such holder receives cash) of our common stock. This generally would result in the following consequences to the U.S. holder:

In addition, Occidental would recognize a taxable gain equal to the excess of the fair market value of our common stock distributed over Occidental's adjusted tax basis in such stock, and, under certain circumstances, the Tax Sharing Agreement would require us to indemnify Occidental for such tax liability. See "—Indemnification" and "Arrangements Between Occidental and Our Company—Tax Sharing Agreement."

Assuming the distribution qualifies as a tax-free distribution for U.S. federal income tax purposes, a U.S. holder who receives cash in lieu of our common stock in connection with the distribution generally will recognize capital gain or loss measured by the difference between the cash received for such fractional share of our common stock and the holder's tax basis that would be allocated to such fractional share. Any such capital gain would be long term capital gain, assuming that the U.S. holder has held all of its Occidental common stock for more than one year. If the distribution does not qualify as a tax-free distribution, then the same rule will apply, but the U.S. holder's basis in the fractional share of our stock will be its fair market value at the time of the distribution.

A U.S. holder that receives a taxable distribution of our common stock or payment of cash in lieu of a fractional share of our common stock made in connection with the distribution may be subject to information reporting and backup withholding. A U.S. holder may avoid backup withholding if such holder provides proof of an applicable exemption or a correct taxpayer identification number, and otherwise complies with the requirements of the backup withholding rules. Backup withholding does not constitute an additional tax, but is merely an advance payment that may be refunded or credited against a holder's U.S. federal income tax liability, provided the required information is timely supplied to the IRS.

Material U.S. Federal Income Tax Consequences of the Distribution to Non-U.S. Holders

Provided that the distribution qualifies as a tax-free distribution for U.S. federal income tax purposes, non-U.S. holders receiving stock in the distribution will not be subject to U.S. federal income tax on any gain realized on the receipt of our common stock so long as (1) Occidental's common stock is considered regularly traded on an established securities market and (2) such non-U.S. holder beneficially owns 5% or less of Occidental's common stock at all times during the shorter of the five-year period ending on the distribution date or the non-U.S. holder's holding period, taking into account both actual and constructive ownership under the applicable ownership attribution rules of the Code. Occidental believes that its common stock has been and is regularly traded on an established securities market for U.S. federal income tax purposes.

Any non-U.S. holder that beneficially owns more than 5% of Occidental common stock under the rules described above and receives our common stock will be subject to U.S. federal income tax on any gain realized with respect to its existing Occidental common stock as a result of the distribution if (1) Occidental is treated as a "United States real property holding corporation" ("USRPHC") for U.S. federal income tax purposes at any time during the shorter of the five year period ending on the distribution date or the period during which the non-U.S. holder held such Occidental common stock and (2) we are not a USRPHC immediately following the distribution. In general, either Occidental or we will be a USRPHC at any relevant time described above if 50% or more of the fair market value of the respective company's assets constitute "United States real property interests" within the meaning of the Code. We expect to be a USRPHC immediately after the distribution. However, because the determination of whether we are a USRPHC turns on the relative fair market value of our United States real property interests and our other assets, and because the USRPHC rules are complex, we can give no assurance that we will be a USRPHC after the distribution. Any non-U.S. holder that beneficially owns more than 5% of Occidental common stock under the rules described above and receives our common stock will not be subject to U.S. federal income tax on any gain realized with respect to its existing Occidental common stock as a result of the distribution if (a) we are a USRPHC and (b) such non-U.S. holders meet certain procedural and substantive requirements described in Treasury regulations. Non-U.S. holders should consult their tax advisors to determine if they are more than 5% beneficial owners of Occidental's common stock, or may be more than 5% owners of our common stock under the applicable rules.

If the distribution does not qualify as a tax-free distribution for U.S. federal income tax purposes, then each non-U.S. holder receiving shares of our common stock in the distribution (including fractional shares in lieu of which such holder receives cash) would be subject to U.S. federal income tax at a rate of 30% of the gross amount of any such distribution that is treated as a dividend, unless:

Under the first exception, regular graduated federal income tax rates applicable to U.S. persons would apply to the dividend, and, in the case of a corporate non-U.S. holder, a branch profits tax may also apply, as described below. Unless one of these exceptions applies and the non-U.S. holder provides Occidental with an appropriate IRS Form (or Forms) W-8 to claim an exemption from or reduction in the rate of withholding under such exception, Occidental may be required to withhold 30% of any distribution of our common stock treated as a dividend to satisfy the non-U.S. holder's U.S. federal income tax liability.

A distribution of our common stock that is not tax-free for U.S. federal income tax purposes could also be treated as a nontaxable return of capital or could trigger capital gain for U.S. federal income tax purposes. A distribution of our common stock that is treated as a nontaxable return of capital is generally not subject to U.S. income tax. Furthermore, such distribution generally is not subject to U.S. withholding tax so long as the common stock of Occidental is regularly traded on an established securities market, which Occidental believes to be the case, and the non-U.S. holder does not beneficially own more than 5% of Occidental's common stock at any time during the shorter of the five year period ending on the distribution date or the period during which the non-U.S. Holder held such Occidental common stock, taking into account the attribution rules described above. A distribution of our common stock triggering capital gain is generally not subject to U.S. federal income taxation subject to the same exceptions described below under "—Cash In Lieu of Fractional Shares," and generally is not subject to U.S. withholding tax subject to the same exception described above for a nontaxable return of capital.

Assuming the distribution qualifies as a tax-free distribution, non-U.S. holders generally will not be subject to regular U.S. federal income or withholding tax on gain realized on the receipt of cash in lieu of fractional shares of our common stock received in the distribution, unless:

If one of the above clauses (1) through (3) applies, the non-U.S. holder generally will recognize capital gain or loss measured by the difference between the cash received for the fractional share of our common stock and the holder's tax basis that would be allocated to such fractional share. Gains realized by a non-U.S. holder described in clause (1) above that are effectively connected with the conduct of a trade or business, and, if required by an applicable income tax treaty, are attributable to a permanent establishment or a fixed base maintained by the non-U.S. holder within the United States generally will be taxed on a net income basis at the graduated rates that are applicable to U.S. persons. In the case of a non-U.S. holder that is a corporation, such income may also be subject to the U.S. federal branch profits tax, which generally is imposed on a foreign corporation upon the deemed repatriation from the United States of effectively connected earnings and profits, currently at a 30% rate, unless the rate is reduced or eliminated by an applicable income tax treaty and the non-U.S. holder is a qualified resident of the treaty country. Gains realized by a non-U.S. holder described in clause (2) above generally will be subject to a 30% tax

from the receipt of cash in lieu of fractional shares (or a lower treaty rate, if applicable), with such gains eligible to be offset by certain U.S.-source capital losses recognized in the same taxable year of the distribution. Non-U.S. holders that meet the circumstances in clause (3) should consult their tax advisors regarding the determination of the amount of gain (if any) that would be subject to U.S. federal income tax. If the distribution does not qualify as a tax-free distribution, then the same rule will apply, but the non-U.S. holder's basis in the fractional share of our stock will be its fair market value at the time of the distribution.

Payments made to non-U.S. holders in the distribution may be subject to information reporting and backup withholding. Non-U.S. holders generally may avoid backup withholding by furnishing a properly executed IRS Form W-8BEN (or other applicable IRS Form W-8) certifying the non-U.S. holder's non-U.S. status or by otherwise establishing an exemption. Backup withholding is not an additional tax. Rather, non-U.S. holders may use amounts withheld as a credit against their U.S. federal income tax liability or may claim a refund of any excess amounts withheld by timely and duly filing a claim for refund with the IRS.

Current Treasury regulations require a "significant" stockholder (one who immediately before the distribution owns 5% or more (by vote or value) of the total outstanding Occidental common stock) who receives our common stock pursuant to the distribution to attach to such stockholder's U.S. federal income tax return for the year in which the distribution occurs a detailed statement setting forth such data as may be appropriate in order to show the applicability to the distribution of Section 355 of the Code.

Under the Tax Sharing Agreement, we have agreed to indemnify Occidental from liability for any taxes arising from the spin-off to the extent attributable to a breach by us (or any of our subsidiaries) of any of our representations or covenants in the Tax Sharing Agreement, the Separation and Distribution Agreement, or made in connection with the private letter ruling or opinion of counsel. We also have agreed to pay 50% of any taxes arising from the spin-off to the extent that the tax is not attributable to the fault of either party. See "Arrangements Between Occidental and Our Company—Tax Sharing Agreement."

After the spin-off, we will be an independent, publicly traded company. Immediately following the spin-off, we expect to have approximately registered holders of shares of our common stock and approximately shares of our common stock outstanding, based on the number of stockholders and outstanding shares of Occidental common stock expected as of the record date. These figures assume no exercise of outstanding options or issuance of other stock awards and exclude shares of Occidental common stock held directly or indirectly by Occidental, if any. The actual number of shares to be distributed will be determined on the record date and will reflect any exercise of Occidental options or issuance of other stock awards between the date the Occidental board of directors declares the dividend for the distribution and the record date for the distribution.

For information regarding options to purchase shares of our common stock or issuance of other stock awards that will be outstanding after the distribution, see "Capitalization," "Management" and "Arrangements Between Occidental and Our Company—Employee Matters Agreement."

It is anticipated that, on or shortly before the record date and continuing up to and including the distribution date, there will be a "when-issued" market in our common stock. When-issued trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. The when-issued trading market will be a market for shares of our common stock that will be distributed to Occidental stockholders on the distribution date. Any Occidental stockholder that owns shares of Occidental common stock at the close of business on the record date will be entitled to shares of our common stock distributed in the spin-off. Occidental stockholders may trade this entitlement to shares of our common stock, without the shares of Occidental common stock they own, on the when-issued market. On the first trading day following the distribution date, we expect when-issued trading with respect to our common stock will end and "regular-way" trading will begin. See "Trading Market."

Following the distribution date, we expect shares of our common stock to be listed on the NYSE under the ticker symbol "CRC." We will announce the when-issued ticker symbol when and if it becomes available.

It is also anticipated that, on or shortly before the record date and continuing up to and including the distribution date, there will be two markets in Occidental common stock: a "regular-way" market and an "ex-distribution" market. Shares of Occidental common stock that trade on the regular-way market will trade with an entitlement to shares of our common stock distributed pursuant to the distribution. Shares that trade on the ex-distribution market will trade without an entitlement to shares of our common stock distributed pursuant to the distribution. Therefore, if shares of Occidental common stock are sold in the regular-way market up to and including the distribution date, the selling stockholder's right to receive shares of our common stock in the distribution will be sold as well. However, if Occidental stockholders own shares of Occidental common stock at the close of business on the record date and sell those shares on the ex-distribution market up to and including the distribution date, the selling stockholders will still receive the shares of our common stock that they would otherwise receive pursuant to the distribution. See "Trading Market."

The treatment of outstanding Occidental equity-based and other long-term incentive compensation awards has not been finally determined, and we will include information regarding the treatment in an amendment to this information statement. For more information on Occidental's currently anticipated treatment of equity-based and other long-term incentive compensation awards that may be held by our named executive officers as of the spin-off, see "Executive Compensation—Compensation Discussion and Analysis—Effects of Spin-off on Outstanding Executive and Other Compensation Awards."

Occidental expects that the spin-off will be effective as of 11:59 p.m., Eastern Time, on , 2014, the distribution date, provided that the following conditions shall have been satisfied or waived by Occidental in its sole discretion:

The fulfillment of the foregoing conditions does not create any obligations on Occidental's part to effect the spin-off, and the Occidental board of directors has reserved the right, in its sole discretion, to abandon, modify or change the terms of the spin-off, including by waiving any conditions to the spin-off or accelerating or delaying the timing of the consummation of all or part of the distribution, at any time prior to the distribution date.

This information statement is being furnished solely to provide information to Occidental stockholders who will receive shares of our common stock in the spin-off. It is not to be construed as an inducement or encouragement to buy or sell any of our securities. We believe that the information contained in this information statement is accurate as of the date set forth on the cover. Changes may occur after that date and neither Occidental nor we undertake any obligation to update the information, except to the extent applicable securities laws require us to do so.

There has been no public market for our common stock. An active trading market may not develop or may not be sustained. We anticipate that trading of our common stock will commence on a "when-issued" basis on or shortly before the record date and continue through the distribution date. When-issued trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. When-issued trades generally settle within four trading days after the distribution date. If you own shares of Occidental common stock at the close of business on the record date, you will be entitled to shares of our common stock distributed pursuant to the spin-off. You may trade this entitlement to shares of our common stock, without the shares of Occidental common stock you own, on the when-issued market. On the first trading day following the distribution date, any when-issued trading with respect to our common stock will end and "regular-way" trading will begin. We intend to list our common stock on the NYSE under the ticker symbol "CRC." We will announce our when-issued trading symbol when and if it becomes available.

It is also anticipated that, on or shortly before the record date and continuing up to and including the distribution date, there will be two markets in Occidental common stock: a "regular-way" market and an "ex-distribution" market. Shares of Occidental common stock that trade on the regular-way market will trade with an entitlement to shares of our common stock distributed pursuant to the distribution. Shares that trade on the ex-distribution market will trade without an entitlement to shares of our common stock distributed pursuant to the distribution. Therefore, if you sell shares of Occidental common stock in the regular-way market up to and including the distribution date, you will be selling your right to receive shares of our common stock in the distribution. However, if you own shares of Occidental common stock at the close of business on the record date and sell those shares on the ex-distribution market up to and including the distribution date, you will still receive the shares of our common stock that you would otherwise receive pursuant to the distribution.

We cannot predict the prices at which our common stock may trade before the spin-off on a "when-issued" basis or after the spin-off. Those prices will be determined by the marketplace. Prices at which trading in our common stock occurs may fluctuate significantly. Those prices may be influenced by many factors, including anticipated or actual fluctuations in our operating results or those of other companies in our industry, investor perception of our company and the energy industry, market fluctuations and general economic conditions. In addition, the stock market in general has experienced extreme price and volume fluctuations that have affected the performance of many stocks and that have often been unrelated or disproportionate to the operating performance of these companies. These are just some factors that may adversely affect the market price of our common stock. See "Risk Factors—Risks Related to Our Common Stock."

The shares of our common stock that you will receive in the distribution will be freely transferable, unless you are considered an "affiliate" of ours under Rule 144 under the Securities Act of 1933, as amended (the "Securities Act"). Persons who can be considered our affiliates after the spin-off generally include individuals or entities that directly, or indirectly through one or more intermediaries, control, are controlled by, or are under common control with, us, and may include certain of our officers and directors. In addition, individuals who are affiliates of Occidental on the distribution date may be deemed to be affiliates of ours. We estimate that our directors and executive officers, who may be considered "affiliates," will beneficially own approximately shares of our common stock immediately following the distribution. Occidental may also be considered our affiliate because immediately following the distribution Occidental may own as much as 19.9% of CRC's outstanding shares of common stock (estimated to be equal to approximately shares of common stock of CRC). See "Security

Ownership of Certain Beneficial Owners and Management" included elsewhere in this information statement for more information. As discussed under "Other Related Party Transactions," we are entering into a Stockholder's and Registration Rights Agreement with Occidental pursuant to which we will be required to use our best efforts to effect the registration under applicable federal and state securities laws of the shares of our common stock retained by Occidental after the distribution. See "Arrangements Between Occidental and Our Company—Stockholder's and Registration Rights Agreement" included elsewhere in this information statement. Our affiliates may sell shares of our common stock received in the distribution only:

In general, under Rule 144 as currently in effect, an affiliate will be entitled to sell, within any three-month period commencing 90 days after the date the registration statement, of which this information statement is a part, is declared effective, a number of shares of our common stock that does not exceed the greater of:

Rule 144 also includes notice requirements and restrictions governing the manner of sale. Sales may not be made under Rule 144 unless certain information about us is publicly available.

In the future, we may adopt new stock option and other equity-based award plans and issue options to purchase shares of our common stock and other stock-based awards. We currently expect to file a registration statement under the Securities Act to register shares to be issued under these stock plans. Shares issued pursuant to awards after the effective date of the registration statement, other than shares issued to affiliates, generally will be freely tradable without further registration under the Securities Act.

Except for our common stock distributed in the distribution, none of our equity securities will be outstanding on or immediately after the spin-off and there are no registration rights agreements existing with respect to our common stock.

We intend to pay a cash dividend of $0.01 per share per quarter, or $0.04 per share per year. We currently intend to retain the remainder of our future earnings to support the growth and development of our business. In addition, we will be authorized to implement a share repurchase program if circumstances warrant. The payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our financial condition, results of operations, capital requirements and development expenditures, future business prospects and any restrictions imposed by future debt instruments.

The following table sets forth (i) our historical capitalization as of March 31, 2014 and (ii) our adjusted capitalization assuming the distribution, the incurrence of debt and other matters (as discussed in "The Spin-Off") were effective as of March 31, 2014. The table below should be read in conjunction with "Selected Historical Combined Financial Data," "Unaudited Pro Forma Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our audited combined financial statements, unaudited interim combined condensed financial statements and the notes to those statements included elsewhere in this information statement.

	As of March 31, 2014

	Historical			As Adjusted
	(Unaudited)
	(in millions)
Debt Outstanding
Short-term debt	$	—		$
Long-term debt		—


Total debt		—


Net Investment / Stockholders' Equity
Common stock
Par value		—
Additional paid-in capital		—
Net investment		10,001
Accumulated other comprehensive loss		(22	)


Total Net Investment/Stockholders' Equity		9,979


Total Capitalization	$	9,979		$

The following tables set forth selected historical combined financial data for the periods indicated. The historical unaudited combined financial data for the three months ended March 31, 2014 and 2013 and balance sheet data as of March 31, 2014 have been derived from our unaudited condensed combined financial statements included elsewhere in this information statement. The unaudited condensed combined financial statements have been prepared on the same basis as our audited combined financial statements, except as stated in the related notes thereto, and include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial condition and result of operations for such periods. The results of operations for the three months ended March 31, 2014 and 2013 presented below are not necessarily indicative of results for the entire fiscal year. Our selected historical combined financial data as of December 31, 2013 and 2012 and for the fiscal years ended December 31, 2013, 2012 and 2011 have been derived from our audited historical combined financial statements included elsewhere in this information statement. Our historical combined financial data as of December 31, 2011, 2010 and 2009 and for the years ended December 31, 2010 and 2009 have been derived from our unaudited accounting records not included in this information statement.

The financial statements included elsewhere in this information statement may not necessarily reflect our financial position, results of operations and cash flows as if we had operated as a stand-alone public company during all periods presented. Accordingly, our historical results should not be relied upon as an indicator of our future performance.

The following selected historical financial data should be read in conjunction with "Capitalization," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Arrangements Between Occidental and Our Company" and our historical financial statements and related notes thereto appearing elsewhere in this information statement.

The unaudited pro forma combined financial statements presented below have been derived from our historical combined financial statements included elsewhere in this information statement. While the historical combined financial statements reflect the past financial results of the California business, these pro forma statements give effect to the separation of those operations into a standalone, publicly traded company in the spin-off.

The pro forma adjustments, including related tax effects, to reflect the spin-off are expected to include the following:

The separation and distribution, tax sharing, transaction services and employee matters and indemnification agreements have not been finalized, and the pro forma financial statements will be revised in future amendments to reflect the effects of those agreements, to the extent material.

The unaudited pro forma combined statements of income for the year ended December 31, 2013 and the three months ended March 31, 2014 have been prepared as though the spin-off occurred as of January 1, 2013. The unaudited pro forma combined balance sheet at March 31, 2014 has been prepared as though the spin-off occurred on March 31, 2014. The pro forma adjustments are based on available information and assumptions that we believe are reasonable; however, such adjustments are subject to change based on the final terms of the spin-off and the related separation and distribution agreements, as well as our expected debt offering. Additionally, such adjustments are estimates and may not prove to be accurate.

Management has attempted to include recurring costs of operating as a stand-alone company, including executive oversight, accounting, procurement, engineering, drilling, exploration, marketing, finance, internal audit, legal, risk management, tax, treasury, information technology, government relations, investor relations, public relations, financial reporting, human resources, ethics and compliance, and certain other shared services related to being a stand-alone company. Only costs we have determined to be factually supportable are included as pro forma adjustments, including the items described above. Some of these costs may vary and there could be additional incremental costs not reflected in the unaudited pro forma combined financial statements. Incremental costs and expenses associated with being a stand-alone company, which are not reflected in the unaudited pro forma combined financial statements, are estimated to be approximately $ million before income taxes annually.

The financial information presented below is not necessarily indicative of our future performance or what our financial position and results of operations would have been had we operated as a stand-alone public company during the periods presented, or had the transactions reflected in the pro forma adjustments actually occurred as of the dates assumed. The unaudited pro forma combined financial data are for illustrative purposes only. The unaudited pro forma combined financial data constitute forward-looking information and are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated. See "Forward-Looking Statements" in this information statement.

The unaudited pro forma combined financial data should be read in conjunction with "Selected Historical Combined Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our audited combined financial statements, unaudited interim combined condensed financial statements and the related notes thereto appearing elsewhere in this information statement.

CALIFORNIA RESOURCES CORPORATION
Unaudited Pro Forma Combined Statements of Income
Three Months Ended March 31, 2014

	Historical			Pro Forma Adjustments		Pro Forma

	(in millions, except per share amounts)
Revenues:
Net sales to related parties	$	1,098		$	(a)	$
Net sales to third parties		23			(a)


		1,121


Costs and expenses:
Production costs		289
Selling, general and administrative expenses		86			(b)
Depreciation, depletion and amortization		289
Taxes other than on income		52
Exploration expense		31
Interest and debt expense, net		—			(c)


		747


Income before income taxes		374
Provision for income taxes		(151	)		(d)


Net income	$	223		$		$




Pro forma earnings per share(e):
Basic						$
Diluted						$
Pro forma shares outstanding(e):
Basic
Diluted

CALIFORNIA RESOURCES CORPORATION
Unaudited Pro Forma Combined Statements of Income
Year Ended December 31, 2013

	Historical			Pro Forma Adjustments		Pro Forma

	(in millions, except per share amounts)
Revenues and other income:
Net sales to related parties	$	4,174		$	(a)	$
Net sales to third parties		111			(a)
Other income		(1	)


		4,284


Costs and expenses:
Production costs		1,066
Selling, general and administrative expenses		326			(b)
Depreciation, depletion and amortization		1,144
Taxes other than on income		185
Exploration expense		116
Interest and debt expense, net		—			(c)


		2,837


Income before income taxes		1,447
Provision for income taxes		(578	)		(d)


Net income	$	869		$		$




Pro forma earnings per share(e):
Basic						$
Diluted						$
Pro forma shares outstanding(e):
Basic
Diluted

CALIFORNIA RESOURCES CORPORATION
Unaudited Pro Forma Combined Balance Sheets
As of March 31, 2014

	Historical			Pro Forma Adjustments		Pro Forma

	(in millions)
Current assets:
Cash and cash equivalents	$	—		$	(f)	$
Trade receivables, net		22
Inventories		75
Other current assets		142


Total current assets		239


Property, plant and equipment, net		14,173
Other assets		35			(g)


Total assets	$	14,447		$		$




Current liabilities:
Accounts payable	$	480		$		$
Accrued liabilities		255


Total current liabilities		735


Long-term debt, net		—			(f)
Deferred income taxes		3,232			(h)
Deferred credits and other liabilities		501			(i)


Total liabilities		3,733
Net Investment/Stockholders' Equity:
Common stock		—			(j)
Additional paid-in capital		—			(k)
Net investment		10,001			(b,f,i,j,k)
Accumulated other comprehensive income (loss)		(22	)


Total net investment/stockholders' equity		9,979


Total liabilities and net investment/stockholder's equity	$	14,447		$		$

CALIFORNIA RESOURCES CORPORATION
Unaudited Pro Forma Combined Statements of Cash Flows
Three Months Ended March 31, 2014

	Historical				Pro Forma

	(in millions)
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	223
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization of assets		289
Deferred debt charges		—		(c,g)
Deferred income tax provision		119
Other noncash charges to income		14
Dry hole expenses		24
Changes in operating assets and liabilities, net		47


Net cash provided by operating activities		716


CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(475	)
Payments for purchases of assets and businesses, and other		(2	)


Net cash used by investing activities		(477	)


CASH FLOW FROM FINANCING ACTIVITIES
Distributions to parent company		(239	)
Cash dividends paid		—		(l)


Net cash used by financing activities		(239	)


Increase (decrease) in cash and cash equivalents		—				—
Cash and cash equivalents—beginning of year		—				—


Cash and cash equivalents—end of year	$	—			$	—

CALIFORNIA RESOURCES CORPORATION
Unaudited Pro Forma Combined Statements of Cash Flows
Year Ended December 31, 2013

	Historical			Pro Forma Adjustments			Pro Forma

	(in millions)
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	869		$			$
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization of assets		1,144
Deferred income tax provision		260
Deferred debt charges		—				(c,g)
Other noncash charges to income		29
Asset impairments and related items		—
Dry hole expenses		72
Changes in operating assets and liabilities:
(Increase) decrease in trade receivables, net		(8	)
Decrease (increase) in inventories		8
Decrease (increase) in other current assets		2
Increase (decrease) in accounts payable and accrued liabilities		100


Net cash provided by operating activities		2,476


CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(1,669	)
Payments for purchases of assets and businesses		(48	)
Other, net		4


Net cash used by investing activities		(1,713	)


CASH FLOW FROM FINANCING ACTIVITIES
(Distributions to) contributions from parent company		(763	)
Cash dividends paid		—				(l)


Net cash (used) provided by financing activities		(763	)


Increase (decrease) in cash and cash equivalents		—			—
Cash and cash equivalents—beginning of year		—			—


Cash and cash equivalents—end of year	$	—		$	—		$	—

CALIFORNIA RESOURCES CORPORATION
Notes to Unaudited Pro Forma Combined Financial Statements

(a) Reflects the reclassification of activity and balances with Occidental from related-party to third-party.

(b) Represents incremental costs associated with operating as a stand-alone, public company, including costs related to certain corporate functions and centrally-located activities.

(c) Reflects the following adjustments to interest and debt expense resulting from the assumed incurrence of $ billion of indebtedness in connection with the spin-off:

Pro forma interest expense was calculated based on an assumed blended interest rate of % using market rates on an assumed borrowing amount of $ . Interest expense also includes estimated amortization on approximately $ million of debt issuance costs related to our anticipated debt, including the revolving credit facility. Such costs are amortized over the terms of the associated debt. Interest expense also includes an estimated % commitment fee on the anticipated new $ revolving credit facility. Actual interest expense may be higher or lower depending on fluctuations in interest rates. A one-eighth percent change in interest rates would result in a $ change in annual interest expense.

(d) Represents the tax effect of pro forma adjustments to income before income taxes using a statutory tax rate of % for both the three months ended March 31, 2014 and the year ended December 31, 2013. Our effective tax rate could be different (either higher or lower) depending on activities subsequent to the spin-off.

(e) The calculation of pro forma basic earnings per share and shares outstanding is based on the number of shares of Occidental common stock outstanding as of , 2014, adjusted for the distribution ratio of one share of our common stock for every shares of Occidental common stock outstanding. The calculation of pro forma diluted earnings per share and shares outstanding for the periods presented is based on the number of shares of Occidental common stock outstanding and diluted shares of common stock outstanding as of , 2014, adjusted for the same distribution ratio. This calculation may not be indicative of the participating or dilutive effect that will actually result from the replacement of Occidental stock-based awards held by our employees or the grant of new stock-based awards.

(f) Represents the following adjustments to cash and cash equivalents, as follows (in millions):

(g) Represents new debt issuance costs of $ million related to the assumed incurrence of $ billion of indebtedness and the anticipated new $ billion revolving credit facility.

(i) Represents a liability of $ million for payment of stock-based compensation and other long-term incentive units to employees based on value at the assumed effective date for the spin-off. For additional information, see "Arrangements between Occidental and Our Company."

(j) Represents the distribution of approximately shares of our common stock at a par value of $0.01 per share to holders of Occidental common stock.

(k) Represents the elimination of Occidental's net investment in us and adjustments to additional paid-in capital resulting from the following (in millions):

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of financial condition and results of operations (MD&A) should be read in conjunction with the information under the headings "Risk Factors," "Selected Historical Combined Financial Data," "Unaudited Pro Forma Combined Financial Data" and "Business," as well as the audited combined financial statements, unaudited interim combined condensed financial statements and the related notes thereto, all appearing elsewhere in this information statement.

This MD&A contains forward-looking statements concerning trends or events potentially affecting our business or future performance, including, without limitation, statements relating to our plans, strategies, objectives, expectations and intentions. The words "aim," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "likely," "may," "might," "objective," "outlook," "plan," "potential," "predict," "project," "seek," "should," "target, "will" or "would" and similar expressions identify forward-looking statements. We do not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements contained in this information statement. See "Forward-Looking Statements" and "Risk Factors."

On February 14, 2014, Occidental announced that its board of directors had authorized management to pursue the spin-off of the California business into a standalone, publicly traded company. The spin-off is being executed in accordance with a Separation and Distribution Agreement between us and Occidental. The spin-off is intended to be tax-free to the stockholders of Occidental and to Occidental and us for U.S. federal income tax purposes. Occidental intends to distribute, on a pro rata basis, over 80% of our common stock to the Occidental stockholders as of the record date for the spin-off. Upon completion of the spin-off, we and Occidental will each be independent, publicly traded companies and will have separate public ownership, boards of directors and management. The spin-off is, among other things, subject to final approval by Occidental's board of directors and the satisfaction or waiver by Occidental, in its sole discretion, of certain conditions to the spin-off, including the, receipt of a private letter ruling from the IRS and an opinion of tax counsel, with respect to the tax-free nature of the spin-off for federal income tax purposes.

We were incorporated in Delaware as a wholly-owned subsidiary of Occidental on April 23, 2014. We will be an independent oil and natural gas exploration and production company, with operations exclusively in California. See the discussion under the heading "The Spin-Off" included in this information statement for further details.

We are currently a wholly-owned subsidiary of Occidental formed to own and operate the California business. We did not have material assets or liabilities as a separate corporate entity until the contribution to us by Occidental of the California business. Occidental previously conducted the California business through various wholly-owned subsidiaries. The combined financial statements included elsewhere in this information statement were prepared in connection with the spin-off and reflect the combined historical results of operations, financial position and cash flows of the California business, as if we had held the

California business for all historical periods presented. All significant intercompany transactions and accounts within the California business have been eliminated. The assets and liabilities in the combined financial statements included elsewhere in this information statement have been reflected on a historical basis. The historical results discussed in the MD&A do not consider the transactions to be effected in connection with the spin-off, which will impact our results of operations, financial position and cash flows.

Factors Affecting Comparability of Our Historical Financial Results of Operations to our Future Financial Results of Operations

The combined statements of income also include expense allocations for certain functions and centrally-located activities historically performed by Occidental. These functions include executive oversight, accounting, procurement, engineering, drilling, exploration, marketing, internal audit, legal, risk management, finance, tax, treasury, information technology, government relations, investor relations, public relations, financial reporting, human resources, ethics and compliance, and certain other shared services. These allocations are based primarily on specific identification of time or activities associated with us, employee headcount or our relative size compared to Occidental. Our management believes the assumptions underlying the combined financial statements, including the assumptions regarding allocating expenses from Occidental, are reasonable. However, the combined financial statements may not include all of the actual expenses that would have been incurred, may include duplicative costs and may not reflect our combined results of operations, financial position and cash flows had we operated as a stand-alone public company during the periods presented. We have attempted to include recurring costs of operating as a stand-alone company in our pro forma financial statements, although only the additional costs we have determined to be factually supportable are included as pro forma adjustments. There are expected to be additional incremental costs of operating as a stand-alone company not reflected in the unaudited pro forma combined financial statements, which are currently estimated to be approximately $ million before income taxes annually. These estimates may not prove to be accurate. Actual costs that would have been incurred if we had been a stand-alone public company would depend on multiple factors, including organizational structure and strategic and operating decisions. See "Unaudited Pro Forma Combined Financial Data."

We have historically participated in Occidental's corporate treasury management program and have not incurred any debt. Excess cash generated by our business has been distributed to Occidental, and likewise our cash needs have been provided by Occidental, in the form of an investment. Accordingly, we have not included debt or related interest expense in our combined financial statements because there was no specifically identifiable debt associated with our operations. We intend to enter into new financing arrangements in connection with the spin-off. We expect to incur up to $ billion in new debt, which may include term and revolving bank debt, long-term notes or a combination thereof and make a cash distribution of approximately $ billion to Occidental. As a result, the capitalization for our business will be different and we will incur cash interest expenses as well as amortization of financing costs.

Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly, generally as a result of changes in supply and demand and other market-related uncertainties. These and other factors make it impossible to predict realized prices reliably. We respond to economic conditions primarily by adjusting our capital expenditures to be in line with current economic conditions, including adjusting the size and allocation of our capital program. We have only occasionally hedged our commodity price risk and do not expect to have a significant hedging program in the future. A significant portion of our oil production is typically linked to world oil prices, such as Brent, that in the recent past have been at a premium to in-land U.S. crude prices such as West Texas Intermediate ("WTI"). We believe that the limited crude transportation infrastructure from other parts of the country to California will allow us to continue to

realize strong margins as a result. The following table presents the average daily WTI, Brent and NYMEX gas prices for 2013, 2012 and 2011:

The following table presents our average realized prices as a percentage of WTI and NYMEX for 2013, 2012 and 2011:

Oil prices will continue to be affected by (i) global supply and demand, which are generally a function of global economic conditions, inventory levels, production disruptions, technological advances, regional market conditions and the actions of OPEC, other significant producers and governments; (ii) transportation capacity and cost in producing areas; (iii) currency exchange rates; and (iv) the effect of changes in these variables on market perceptions.

Prices for natural gas liquids ("NGLs") are related to the supply and demand for the components of products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints magnify the pricing volatility from region to region.

Gas prices and differentials are strongly affected by local supply and demand fundamentals, as well as availability of transportation capacity from producing areas.

Our earnings are also affected by the performance of our processing and power generation assets. We process our wet gas to extract NGLs and other gas byproducts, and deliver dry gas to pipelines and sell NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. In addition, a portion of the power produced by our Elk Hills power plant is used for certain of our operations while a majority of the output is sold to third parties.

Seasonality is not a primary driver of changes in our quarterly earnings during the year.

We conduct our operations based on our subsurface mineral rights, land leases and other contractual arrangements. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.3 million net acres, approximately 60% of which we hold in fee. Our oil and gas leases have a primary term ranging from one to ten years, which is extended through the end of production once it commences. We also own a network of strategically placed infrastructure assets, including three gas plants, oil and gas gathering systems, a power plant and other related assets to maximize the value generated from our production.

Our share of production and reserves from operations in Long Beach, California are subject to contractual arrangements similar to production-sharing contracts and are in effect through the economic life of the assets. Under such contracts, we record a share of production and reserves to recover all capital and production costs and an additional share for profit. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as

defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, our net economic benefit from these contracts is greater when product prices are higher. Production under these contracts represented 19% of our revenues for the year ended December 31, 2013.

The following table sets forth our production volumes of oil, NGLs and natural gas per day for the three-month periods ended March 31, 2014 and 2013 and each of the three years in the period ended December 31, 2013.

	Three months ended March 31,				Year ended December 31,

	2014		2013		2013		2012		2011
*Oil (MBbl/d)*
San Joaquin Basin		62		57		58		58		56
Los Angeles Basin		27		25		26		24		19
Ventura Basin		6		6		6		6		5
Sacramento Basin		—		—		—		—		—


Total		95		88		90		88		80




*NGLs (MBbl/d)*
San Joaquin Basin		18		19		19		16		14
Los Angeles Basin		—		—		—		—		—
Ventura Basin		1		1		1		1		1
Sacramento Basin		—		—		—		—		—


Total		19		20		20		17		15




*Natural gas (MMcf/d)*
San Joaquin Basin		171		183		182		204		220
Los Angeles Basin		1		2		2		3		1
Ventura Basin		11		8		11		12		12
Sacramento Basin		59		67		65		37		27


Total		242		260		260		256		260




Total Production (MBoe/d)(a)		154		151		154		148		138

The deferred tax liabilities, net of deferred tax assets of approximately $500 million, were approximately $3.1 billion at December 31, 2013. The current portion of total deferred tax assets was $23 million as of December 31, 2013, which was reported in other current assets. We expect to realize the recorded deferred tax assets through future operating income and reversal of temporary differences.

The following table sets forth the calculation of our effective income tax rate:

	Three months ended March 31,						Years ended December 31,

	2014			2013			2013			2012			2011
	(in millions)
Net sales (including related parties)	$	1,121		$	1,048		$	4,285		$	4,072		$	3,938
Other income		—			—			(1	)		1			(4	)
Production costs		(289	)		(263	)		(1,066	)		(1,314	)		(1,074	)
Selling, general and administrative expenses		(86	)		(69	)		(326	)		(296	)		(287	)
Depreciation, depletion and amortization		(289	)		(281	)		(1,144	)		(926	)		(675	)
Asset impairments and related items		—			—			—			(41	)		—
Taxes other than on income		(52	)		(53	)		(185	)		(167	)		(143	)
Exploration expense		(31	)		(20	)		(116	)		(148	)		(114	)
Provision for income taxes		(151	)		(145	)		(578	)		(482	)		(670	)


Net income	$	223		$	217		$	869		$	699		$	971

Net sales increased 7% for the three months ended March 31, 2014, compared to the same period of 2013, reflecting higher oil volumes and higher realized prices for gas and NGLs, partially offset by lower oil prices and gas volumes. Our daily liquids production increased by 6,000 Boe while our daily natural gas production decreased by 18 MMcf, or 3,000 Boe. The increase in liquids production primarily reflected our

strategy to increase our overall capital expenditure program with a focus on oil drilling while reducing drilling capital for natural gas in light of higher oil prices and lower gas prices in recent years.

Production costs for the three months ended March 31, 2014 increased 10% compared to the same period of 2013, mainly due to higher energy costs and prices for natural gas, which is used in our steamflood operations to generate steam, as well as higher overall volumes.

Selling, general and administrative expenses increased 25% for the three months ended March 31, 2014, compared to the same period of 2013, mainly due to higher compensation and employee related costs, in particular higher equity compensation in part due to the higher price of Occidental's stock.

Net sales increased 5% in 2013, compared to 2012, mainly due to higher volumes and prices for oil and gas, higher volumes for NGLs and higher power sales, partially offset by lower prices for NGLs. Our daily liquids production increased by 5,000 Boe while our daily natural gas production increased by 4 MMcf, or less than 1,000 Boe. The increase in liquids production primarily reflected our strategy to increase our overall capital expenditure program with a focus on oil drilling while reducing drilling capital for natural gas in light of higher oil prices and lower gas prices in recent years. The slight increase in our natural gas production reflected increased production from acquisitions made in 2012 and associated gas produced from oil drilling, partially offset by lower gas production due to reduced investment in natural gas drilling in 2013.

Production costs decreased to $18.99 per Boe in 2013, compared to $24.34 per Boe for 2012, due to a wide range of operational efficiency initiatives implemented in late 2012, including high-grading and more efficient utilization of service rigs, improved job scheduling, more efficient liquids usage and handling, optimization of field supervision and contractor usage, and reduced consumption of purchased fuel, power and field rental equipment.

Selling, general and administrative and other operating expenses increased 10% in 2013, compared to 2012, mostly due to higher compensation and employee related costs, in particular higher headcount and equity compensation in part due to the higher price of Occidental's stock.

Depreciation, depletion and amortization ("DD&A") expense increased due to higher volumes and a $3.23 per Boe increase in the DD&A rate, which was a result of additional capital investments throughout our asset base. In recent years, we have been systematically increasing our investments in IOR and EOR recovery assets and facilities. Significant investment on the front end of these projects is necessary, which has caused an increase in our DD&A rate.

A majority of the $41 million in "Asset Impairments and other related items" in 2012 was related to the impairment of uneconomic properties in various areas, in particular gas properties.

Taxes other than on income increased 11% in 2013, compared to 2012, due to California greenhouse gas costs, which we began incurring at the beginning of 2013.

Exploration expense decreased 22% in 2013, compared to 2012, due to higher success rates resulting in lower dry hole expense in the San Joaquin and Los Angeles basins, partially offset by higher dry hole expense in the Ventura basin.

Net sales increased 3% in 2012 compared to 2011 due to higher oil volumes and prices, partially offset by lower gas volumes and NGLs prices. Our daily liquids production increased by 10,000 Boe, while our daily natural gas production decreased by 4 MMcf, or less than 1,000 Boe. The increase in production volumes from 2011 to 2012, in particular the growth in our liquids production, was a result of production from acreage acquired in 2011 and increased capital expenditures in 2012 compared to 2011.

Production costs in 2012 increased 22% compared to 2011, mainly due to higher oil volumes and higher average operating costs, which resulted from higher downhole maintenance activity and increased field support costs.

DD&A expense increased due to a $3.77 per Boe increase in the DD&A rate, reflecting additional capital investments, largely in the San Joaquin and Sacramento basin operations, and asset acquisitions and higher volumes.

Taxes other than on income increased 17% in 2012, compared to 2011, due to higher ad valorem taxes.

Exploration expense increased by 30% in 2012 due to higher dry hole expense in the Los Angeles and Sacramento basins as compared to 2011.

Our primary sources of liquidity and capital resources to fund our capital programs have historically been cash flows from operations. In the past, we have distributed our cash flows in excess of our capital expenditures to Occidental. However, we have occasionally required funding from Occidental to execute large acquisitions, as was the case in 2012 and 2011. Since 2012, we have not received, and following the spin-off we will not receive, any capital contributions from Occidental. We believe our future needs for capital expenditures and acquisitions will be met by cash generated from operations, and borrowings when necessary. Operating cash flows are largely dependent on oil and gas prices, sales volumes and costs.

We have historically participated in Occidental's corporate treasury management program and have not incurred any debt. Prior to the spin-off, we expect to issue senior notes with maturities extending from to years and incur term debt extending years. Almost all of the proceeds of our debt issuance will be used to make a one-time cash distribution to Occidental. We expect our debt structure to also include a new revolving credit facility for operational needs and letter of credit. We expect the covenants of a revolving credit facility and any senior notes or term debt to be consistent with that obtained by other commercial borrowers with similar credit ratings, such as default of debt covenants, non-payment of principal or interest, fees and a change of control.

We expect the revolving credit facility to bear interest at LIBOR plus a margin, which will depend on market conditions and our credit rating.

Our net cash provided by operating activities increased slightly from $708 million in 2013 to $716 million in 2014 consistent with the slight increase in our net income over the same period.

Our cash flow used in investing activities increased by approximately $130 million for the three months ended March 31, 2014 to $477 million, compared to the same period of 2013. The increase reflected higher capital expenditures for development and exploration activities, in line with our strategy of increasing our focus on oil drilling.

Our cash flow used in financing activities decreased by approximately $120 million for the three months ended March 31, 2014, compared to the same period of 2013, reflecting lower excess cash flow distributed to Occidental.

Our operating cash flows in 2013 increased by approximately $250 million compared to 2012. The increase reflected lower cash operating expenses of $250 million resulting from cost efficiencies and $210 million higher revenues due to higher oil and gas prices and volumes. Other significant items affecting operating cash flows consisted of $520 million of higher tax payments in 2013 and $300 million in positive working capital changes.

Our cash flow used in investing activities decreased by approximately $1.0 billion in 2013 to $1.7 billion, compared to 2012. We reduced our capital expenditures in 2013 by approximately $660 million primarily due to approximately 20% lower drilling costs and lower capital needs for the Elk Hills Cryogenic gas plant, which was completed during 2012. Further, our 2013 acquisitions of $50 million were approximately $380 million lower than the 2012 acquisition amount.

Cash used for financing activities in 2013 reflected excess cash flow distributed to Occidental. Cash provided by financing activities in 2012 reflected contributions from Occidental primarily to fund our acquisitions.

Our operating cash flows in 2012 decreased by approximately $230 million compared to 2011. The decrease reflected $240 million of higher operating expenses in 2012, lower revenues of approximately $185 million from lower gas and NGLs prices and $60 million of higher exploration and other costs, offset by higher revenues of approximately $325 million due to increased volumes and lower tax payments of $240 million. Additionally, working capital changes used an additional $320 million in 2012 compared to 2011.

Our cash flow used in investing activities decreased by $810 million from 2011 to 2012. We increased our capital expenditures by $170 million to $2.3 billion in 2012 from $2.2 billion in 2011. Capital expenditures for the years ended December 31, 2012 and 2011 included expenditures for development and exploration activities of approximately $2.2 billion and $1.9 billion, respectively, as well as infrastructure investments of approximately $150 million and $300 million, mostly for the Elk Hills Cryogenic gas plant which was completed in 2012. The increase in our year-over-year capital expenditures was primarily to fund the growth in the San Joaquin and Ventura basins. In addition, our 2012 acquisition activity fell by approximately $1.0 billion to $400 million in 2012, as compared to $1.4 billion in 2011.

Our cash flows from financing activities decreased by $574 million from 2011 to 2012, reflecting a year-over-year decrease in cash funding from Occidental due to lower acquisition activity in 2012.

During the year ended December 31, 2013, we paid approximately $50 million to acquire certain oil and gas properties in California. An acquisition in the San Joaquin basin also included an obligation to spend at least $250 million on exploration and development activities over a period of five years from the date of acquisition. We currently plan to spend more than this amount in capital in the next five years.

During the year ended December 31, 2012, we paid approximately $380 million for oil and gas properties including $275 million for certain producing and non-producing assets in the Sacramento basin and undeveloped acreage in the San Joaquin basin.

During the year ended December 31, 2011, we acquired approximately $1.4 billion of various oil and gas assets. We paid $720 million for producing and non-producing assets within the San Joaquin basin. We also acquired producing and non-producing assets in the Los Angeles Basin for $330 million and certain assets in the Sacramento basin for $190 million.

We have a 2014 capital budget of $2.1 billion for projects targeting investments in the San Joaquin, Los Angeles and Ventura basins, as compared to $1.7 billion in 2013. We allocated approximately $420 million of our 2014 capital budget to primary recovery projects, $755 million to waterfloods and $345 million to steamfloods. Approximately $480 million of our 2014 capital budget will be deployed to develop resources from unconventional plays. Virtually all of our 2014 capital budget will be directed towards oil-weighted production consistent with 2013. In addition, we expect to continue an active exploration program in California and have allocated approximately $100 million of the 2014 capital budget for exploration spending. Assuming current market conditions and drilling success rates comparable to our historical performance, we expect to fund our entire 2014 capital program with cash flow from our operations.

We have no material off-balance-sheet arrangements other than those noted below.

We, or certain of our subsidiaries, have entered into various operating lease agreements, mainly for field equipment, office space and office equipment. We lease assets when leasing offers greater operating flexibility. Lease payments are generally expensed as part of production costs or selling, general and administrative expenses. For more information, see "Contractual Obligations."

The table below summarizes and cross-references our contractual obligations. This summary indicates on- and off-balance-sheet obligations as of December 31, 2013. There were no material changes to the amounts between December 31, 2013 and March 31, 2014.

In the normal course of business, we or certain of our subsidiaries are involved in lawsuits, claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at March 31, 2014 and December 31, 2013 and 2012 were not material to our balance sheets. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on the balance sheet would not be material to our financial position or results of operations.

We will indemnify Occidental under the Tax Sharing Agreement for taxes incurred as a result of the failure of the spin-off to qualify as tax-free under Section 355 and Section 368(a)(1)(D) of the Code, to the extent caused by our breach of any representations or covenants made in the Tax Sharing Agreement, the Separation and Distribution Agreement, or made in connection with the private letter ruling or the tax opinion or by any other action taken by us. We also have agreed to pay 50% of any taxes arising from the spin-off to the extent that the tax is not attributable to the fault of either party. See "Arrangements Between Occidental and Our Company—Tax Sharing Agreement." In addition, under the Separation and Distribution Agreement, we will also indemnify Occidental and its remaining subsidiaries against claims and liabilities relating to the past operation of our business. See "Arrangements Between Occidental and Our Company."

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

The carrying value of our property, plant and equipment ("PP&E") represents the cost incurred to acquire or develop the asset, including any asset retirement obligations, net of accumulated DD&A and any impairment charges. For assets acquired, initial PP&E cost is based on fair values at the acquisition date.

We use the successful efforts method to account for our oil and gas properties. Under this method, we capitalize costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether we find proved reserves. If we find proved reserves, the costs of exploratory wells remain capitalized. Otherwise, we charge the costs of the related wells to expense. In some cases, we cannot determine whether we have found proved reserves at the completion of exploration drilling, and must conduct additional testing and evaluation of the wells. We generally expense the costs of such exploratory wells if we do not determine we have found proved reserves within a 12-month period after drilling is complete.

We determine depreciation and depletion of oil and gas producing properties by the unit-of-production method. We amortize acquisition costs over total proved reserves, and capitalized development and successful exploration costs over proved developed reserves.

Proved oil and gas reserves and production are used as the basis for recording depreciation and depletion of oil and gas producing properties. Proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—regardless of whether deterministic or probabilistic methods are used for the estimation. We have no proved oil and gas reserves for which the determination of economic producibility is subject to the completion of major additional capital expenditures.

Several factors could change our proved oil and gas reserves. For example, we receive a share of production from arrangements similar to production-sharing contracts to recover costs and generally an additional share for profit. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, our net economic benefit from these contracts is greater at higher product prices. In other cases, particularly with long-lived properties, lower product prices may lead to a situation where production of a portion of proved reserves becomes uneconomical. For such properties, higher product prices typically result in additional reserves becoming economical. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and inflation or deflation of oil field service costs. These factors, in turn, could lead to changes in the quantity of proved reserves. Additional factors that could result in a change of proved reserves include production decline rates and operating performance differing from those estimated when the proved reserves were initially recorded.

Additionally, we perform impairment tests with respect to our proved properties when product prices decline other than temporarily, reserve estimates change significantly, other significant events occur or management's plans change with respect to these properties in a manner that may impact our ability to realize the recorded asset amounts. Impairment tests incorporate a number of assumptions involving expectations of undiscounted future cash flows, which can change significantly over time. These assumptions include estimates of future product prices, which we base on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future expected operating and development costs.

The most significant ongoing financial statement effect from a change in our oil and gas reserves or impairment of our proved properties would be to the DD&A rate. For example, a 5% increase or decrease in the amount of oil and gas reserves would change the DD&A rate by approximately $1.15 per Bbl, which would increase or decrease pre-tax income by approximately $65 million annually at current production rates.

A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At December 31, 2013, the net capitalized costs attributable to unproved properties were approximately $900 million. While exploration and development work progresses, the unproved amounts are not subject to DD&A until they are classified as proved properties. However, if the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results. We believe our current plans and exploration and development efforts will allow us to realize the unproved property balance.

We perform impairment tests on our infrastructure assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would

indicate that the carrying amount may not be recoverable, or when management's plans change with respect to those assets.

We have categorized our assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level 3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period. We primarily apply the market approach for recurring fair value measurement, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management's judgments regarding expectations of projected cash flows and discounts those cash flows using risk-adjusted discount rate.

In the normal course of business, we are involved in lawsuits, claims and other environmental and legal proceedings and audits. We accrue reserves for these matters when it is probable that a liability has been incurred and the liability can be reasonably estimated. In addition, we disclose, if material, in aggregate, our exposure to loss in excess of the amount recorded on the balance sheet for these matters if it is reasonably possible that an additional material loss may be incurred. We review our loss contingencies on an ongoing basis.

Loss contingencies are based on judgments made by management with respect to the likely outcome of these matters and are adjusted as appropriate. Management's judgments could change based on new information, changes in, or interpretations of, laws or regulations, changes in management's plans or intentions, opinions regarding the outcome of legal proceedings, or other factors. See "—Lawsuits, Claims and Contingencies" for additional information.

In April 2014, the Financial Accounting Standards Board ("FASB") issued rules changing the requirements for reporting discontinued operations to where only the disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results will be reported as discontinued operations in the financial statements. These rules are effective for the annual periods beginning on or after December 15, 2014. They are not expected to have a material impact on our financial statements upon adoption and will require assessment on an ongoing basis.

In July 2013, the FASB issued rules requiring net, rather than gross, presentation of a deferred tax asset for a net operating loss or other tax credit and any related liability for unrecognized tax benefits. These rules became effective on January 1, 2014, and did not have a material impact on our financial statements.

Our results are sensitive to fluctuations in oil, NGLs and gas prices. Price changes at current levels of production affect our pre-tax annual income by approximately $29 million for a $1 per Bbl change in oil prices and $8 million for a $1 per Bbl change in NGLs prices. If gas prices varied by $0.50 per Mcf, it would have an estimated annual effect on our pre-tax income of approximately $32 million. These price-change sensitivities include the impact on income of volume changes under arrangements similar to production-

sharing contracts. If production levels change in the future, the sensitivity of our results to prices also will change.

We have only occasionally hedged our commodity price risk and we do not expect to do so in the foreseeable future. However, we entered into financial swap agreements in November 2012 for the sale of 50 MMcf/d of our gas production beginning in January 2013 through March 2014. These agreements qualified as cash-flow hedges and represented approximately 5% of our 2013 total production on a Boe basis. The weighted-average strike price of these swaps was $4.30.

Our credit risk relates primarily to trade receivables. Credit exposure for each customer is monitored for outstanding balances and current activity.

As of December 31, 2013, the substantial majority of the credit exposures related to our business was with investment grade counterparties. We believe exposure to credit-related losses related to our business at December 31, 2013 was not material and losses associated with credit risk have been insignificant for all years presented.

Substantially all of our products have historically been sold to Occidental's marketing subsidiaries. For the years ended December 31, 2013, 2012 and 2011, sales to Occidental subsidiaries accounted for approximately 97%, 97% and 98% of our net sales, respectively. For the years ended December 31, 2013, 2012 and 2011, ConocoPhillips/Phillips 66 Company and Tesoro Refining & Marketing Company LLC each accounted for more than 10% of our net sales and collectively accounted for 42%, 46% and 44%, respectively. No other customer accounted for more than 10% of our net sales during these periods. If a major customer decided to stop purchasing our products, we do not believe the effect on our operating results and financial condition would be material.

Historically, we had no interest rate risk exposure as we have not historically had debt balances. Following the spin-off, any borrowings under our new revolving credit facility could be at a variable interest rate and could expose us to the risk of increasing interest rates.

Following the spin-off from Occidental, we will be an independent oil and natural gas exploration and production company focused on high-growth, high-return conventional and unconventional assets, which are conducted exclusively in California. 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 continental United States based on estimated proved reserves, four of which are in our portfolio. We are the largest producer in California on a gross operated basis and we believe we have established the largest privately-held mineral acreage position in the state, consisting of approximately 2.3 million net acres spanning the state's four major oil and gas basins. We have developed a sizable inventory of over 17,500 identified drilling locations and, as an independent company, we plan to exploit our significant portfolio of conventional and unconventional opportunities to generate double-digit production growth over the longer-term. We produced approximately 154,000 Boe/d net in 2013 and, as of December 31, 2013, we had proved reserves of 744 MMBoe, with approximately 69% proved developed and 72% proved oil reserves and an aggregate PV-10 value of $14.0 billion. For an explanation of the non-GAAP financial measure PV-10 and a reconciliation of PV-10 to Standardized Measure, the most directly comparable GAAP financial measure, see "Summary—Summary Combined Historical Operating and Reserve Data—Non-GAAP Financial Measure and Reconciliations."

California oil and gas development began in 1876, and oil-in-place estimates have generally increased throughout the ensuing decades, with over 29 billion Bbls of oil and 40 Tcf of natural gas produced and over 53,000 currently active producing wells as of December 31, 2013 (according to DOGGR). We began our operations in California in the 1950s and have accumulated extensive, proprietary knowledge and experience in developing this world-class resource base. Over the past decade, we have also built an exceptional 3D seismic library, which covers over 4,250 square miles, representing approximately 90% of the 3D seismic data available for California, and we have developed unique and proprietary stratigraphic and structural models of the subsurface geology and hydrocarbon potential in each of the four basins in which we operate. As a result of our long, successful operating history, our extensive exploration programs, our exceptional 3D seismic library and proprietary subsurface geologic models, we have tested and successfully implemented in recent years various exploration, drilling, completion and enhanced recovery technologies to maximize recoveries, increase growth and optimize returns from our portfolio.

We believe that 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 spending in California, focus on shallow zone thermal projects or investments in other assets in their global portfolios. As an independent company focused exclusively on California, we expect to drive strong production growth through increased application of modern technologies and increased capital spending on development of the significant potential in our portfolio.

Our large acreage position contains numerous growth opportunities due to its varied geologic characteristics and multiple stacked pay reservoirs that, in most cases, are thousands of feet thick. We have a significant portfolio of unconventional growth opportunities, with approximately 4,500 identified drilling locations targeting unconventional reservoirs primarily in the San Joaquin basin. Unconventional reservoirs have low permeability and require enhanced stimulation and extraction techniques. Unconventional reservoirs include both shale and low-permeability sandstone reservoirs. Over the last few years, we have increased our production by exploiting seven discrete stacked pay horizons within the Monterey formation, primarily within the upper Monterey. We continue to drill unconventional wells within these intervals and are also applying the knowledge acquired from these successes to the Kreyenhagen and the Moreno shales, which we believe offer significant development opportunities as well. We also intend to pursue development opportunities in the lower Monterey shale, which contains a variety

of reservoir lithologies and is the principal hydrocarbon source rock within the overall Monterey formation. The lower Monterey has a more limited production history than the upper Monterey, and therefore limited knowledge exists regarding its potential. However, we believe it will be productive over time. Over the last five years, we have drilled and completed over 570 development wells in unconventional reservoirs, primarily in the upper Monterey formation, with a nearly 100% commercial success rate.

We also have a large portfolio of lower-risk, high-growth conventional opportunities in each of California's four major oil and gas basins with approximately 71% of our proved reserves associated with conventional opportunities. Conventional reservoirs are capable of natural flow. We have a proven track record of successful exploration and development using primary, waterflood and steamflood recovery methods. In 2014, we anticipate that 75% of our capital expenditures target conventional development, primarily low-risk waterflood and steamflood projects that we expect to generate significant near-term production and cash flow growth. For example, our Lost Hills and Kern Front steamflood projects and our Huntington field waterflood project are expected to deliver combined production growth of over 35% compounded annually through 2016 from their combined 2013 production of 15,000 Boe/d.

The following table summarizes certain information concerning our acreage and drilling activities (as of December 31, 2013, unless otherwise stated):

(1): Our total identified drilling locations include 2,141 gross (2,024 net) locations associated with proved undeveloped reserves as of December 31, 2013 and 2,344 gross (2,251 net) injector well locations associated with our waterflood and steamflood projects. Our total identified drilling locations excludes 6,400 gross (5,300 net) prospective resource drilling locations. Please see "—Our Reserves and Production Information—Determination of Identified Drilling Locations" 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.
(2): Includes 183 injection wells expected to be drilled in connection with our waterflood and steamflood projects.
(3): Includes drilling and completion expenditures of $180 million associated with injection wells. Our 2014 capital budget of $2.1 billion also includes spending on support equipment, facilities, workovers and exploration.
(4): Excluding Elk Hills, our average working interest in the San Joaquin basin is 97%.
(5): We currently hold approximately 27,173 gross (20,817 net) acres in the Los Angeles basin. Our Los Angeles basin operations are concentrated with pad drilling.

2013. After the spin-off, we intend to reinvest substantially all of our operating cash flow in our capital program for the foreseeable future as we will no longer be required to distribute cash to Occidental. We expect to increase our production by 6-9% on a compound annual basis in 2015 and 2016 with a 15% compound annual increase in our oil production for the same period. Over 90% of our expected production for this period is from currently producing fields where we have existing or permitted capacity in our production facilities.

The table below summarizes our proved reserves as of December 31, 2013, and production for the three months ended March 31, 2014 in each of California's four major oil and gas basins.

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 continental United States based on proved reserves, four of which are in our portfolio. California is also the nation's largest state economy, with significant energy demands that exceed local supply. California imports approximately 62% of its oil, mostly from foreign locations, and 90% of its natural gas. Because of limited crude transportation infrastructure from other parts of the country to California, the California market is generally isolated from the rest of the nation, which allows California producers to typically receive a premium to WTI-based prices. Our operations span the four major oil and gas basins in California and include 130 fields with 8,655 gross active wellbores as of December 31, 2013. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.3 million net acres, and the largest land owner in each of the states' four major oil and gas basins. Approximately 60% of our total mineral interest position is held in fee. A majority of our interests are in producing properties located in reservoirs characterized by what we believe to be long-lived production profiles with repeatable development opportunities. These reservoirs generally have been developed over a long period of time, typically decades. Observing the performance of these fields over many years has helped us develop a greater understanding of production and reservoir characteristics and, we believe, makes our future performance more predictable.

Across all of our California operations, we drilled 779 wells in 2013, of which 83% were producers. Our 2013 drilling capital was $1.0 billion. Our 2013 total capital of $1.7 billion also included spending on support equipment, facilities, workovers and exploration. Our capital program added 89 MMBoe of proved reserves in 2013 representing a 159% reserve replacement ratio, calculated by using the proved reserves additions for 2013 divided by our 2013 production of 56 MMBoe.

Approximately 69% of our estimated proved reserves as of December 31, 2013 and approximately 71% of our average daily net production for the three months ended March 31, 2014 were located in the San Joaquin basin. We actively operate and develop 42 fields in this basin consisting of conventional primary, IOR, EOR and unconventional project types. We currently hold approximately 1.5 million net acres in the San Joaquin basin, approximately 63% of which we hold in fee.

According to DOGGR, approximately 74% of California's daily oil production for 2013 was produced in the San Joaquin basin. Commercial petroleum development began in the basin in the 1800s when asphalt deposits were mined and shallow wells were hand dug and drilled in the Coalinga, McKittrick and Kern River areas. Rapid discovery of many of the largest oil accumulations followed during the next several decades, including the Elk Hills field. We have been redeveloping this field and building our expertise to use in other fields across the state. According to the U.S. Geological Survey, the San Joaquin basin contains three of the 10 largest fields in the United States. Most discovered oil accumulations occur in Eocene-age through Pleistocene-age sedimentary sections. Source rocks are organic-rich shales from the Monterey, Kreyenhagen and Tumey formations.

In the 1960s, introduction of thermal techniques resulted in substantial new additions to reserves in heavy oil fields. We have been successfully developing steamfloods in our Kern Front operations, which are located next to the giant Kern River field and in the northwest portion of the Lost Hills field. Starting in the 1980s, reserves additions have continued in the Monterey formation on the west side of the basin and in our new conventional field discoveries. As shown in the stratigraphic column below, the basin contains multiple stacked formations throughout its areal extent, and we believe that the San Joaquin basin provides an appealing inventory of existing field re-development opportunities, as well as new play discovery and unconventional play potential. The complex stratigraphy and structure in the San Joaquin basin has allowed continuing discoveries of stratigraphic and structural traps. We believe our extensive 3D seismic library, which covers over 2,625 square miles in the San Joaquin basin, including 35% of our San Joaquin acreage, will give us a competitive advantage in exploring this basin.

We have established a large ownership interest in several of the largest existing oil fields in San Joaquin basin, including Elk Hills, our largest producing field, as well as the Buena Vista and Kettleman North Dome fields.

Elk Hills is our world-class onshore asset located 20 miles west of Bakersfield. The field, covering 75 square miles, was discovered in 1911 and has produced over 1.6 BBoe, making it the 8^th most productive field in the United States. Production from Elk Hills' over 3,000 active wells contributes over 40% of California's gas production and 5% of oil production. At Elk Hills, we operate large and efficient gas processing facilities with a combined capacity of 540 MMcf/d. The gas plant facilities are located adjacent to a 550 megawatt combined-cycle power plant and a 46 megawatt cogeneration plant that not only supply sufficient electricity to operate the field, but also, in the case of the Elk Hills power plant, sells excess power to the grid. Please see "—Our Infrastructure" for more information regarding the gas processing facilities and our Elk Hills power plant. Our operations at Elk Hills possess a state-of-the-art central control facility, remote automation control on over 95% of wells and consolidated production facilities for economies of scale, all of which result in high operational efficiencies.

Due to the nature of the multiple stacked pay zones at Elk Hills, we typically deploy a portion of our annual capital to execute well workovers, such as adding additional uphole pay zones, performing stimulation treatments or increasing lift capacity, resulting in incremental production and reserves and mitigating production decline. In 2013, we produced 68,000 Boe/d from our Elk Hills properties, or approximately 44% of our total production, including 46,000 Boe/d of unconventional production from the Monterey shale. In 2013, this property contributed cash flow from operations, after capital spending, of approximately $500 million.

Approximately 21% of our estimated proved reserves as of December 31, 2013 and approximately 18% of our average daily net production for the three months ended March 31, 2014 were located in the Los Angeles basin. We actively operate and develop 10 fields in this urban, coastal basin consisting of conventional primary, IOR, EOR and unconventional project types. We have a leading acreage position within the Los Angeles basin and over 50% of the basin's production comes from the fields we operate. We currently hold 27,173 gross (20,187 net) acres in the Los Angeles basin.

The Los Angeles basin is a northwest-trending plain about 50 miles long and 20 miles wide on the coast of southern California containing Miocene through Pleistocene sediments. The Los Angeles basin has great structural relief and complexity in relation to its geologic youth and small size and is noted for its prolific oil production. The basin's small areal extent, prolific source rocks, thick sandstone reservoirs and large anticlinal traps are considered a nearly ideal petroleum system. As a result, the Los Angeles basin has one of the highest concentrations per acre of crude oil in the world. Sixty-eight oil fields have been named in an area of about 450 square miles. These accumulations of fine-grained sediments with high organic content, interlayered with coarser grained sands, contributed to the formation of large deposits of oil, including the Wilmington field which is the fourth largest field in the United States and where we have significant operations as described further below. Other large active oil fields include the Long Beach field, the Huntington field and the Torrance field. Most of the significant discoveries in the Los Angeles basin date back to the 1920s. A majority of the numerous fields in the basin have either been abandoned or had production greatly scaled back since the early part of the 1990s. Existing fields range in depth from around 2,000 to 10,000 feet. As shown in the stratigraphic chart below, the basin contains multiple stacked formations throughout its depths, and we believe that the Los Angeles basin provides an appealing inventory of existing field re-development opportunities as well as new play discovery potential.

The Wilmington field is our world-class coastal asset located in the Long Beach harbor. The field was discovered in 1932 and has produced over 2.9 BBoe from over 8,000 wells, making it one of the five most productive fields in the United States. During the year ended December 31, 2013, we produced approximately 35,000 Boe/d gross, or approximately 90% of the total Wilmington field daily production for that year, where we operate on behalf of the state of California and the city of Long Beach. Most of our Wilmington production is covered under a set of production-sharing contracts under which we recover all capital and operating costs and our share of profits from production. Please see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Operations" for more information regarding these production-sharing contracts. The field is developed by applying waterflood methods of oil recovery. Waterfloods are low-cost operations that extend the productive life of a reservoir beyond the economic life expected for primary development. Over 90% of the water injected into the reservoir is produced from the field. We currently operate 1,200 producing wells and 700 water injection wells in the Wilmington field. There are five major stacked oil producing zones in the field, ranging in depth from 2,000 to 10,000 feet. We have identified over 1,000 future drilling locations that we plan to develop over the next five years. For a more detailed description of these waterfloods, please see "—Conventional Reservoir Recovery Methods—Waterfloods." In 2013, this property contributed cash flow from operations, after capital spending, of $25 million.

Approximately 7% of our estimated proved reserves as of December 31, 2013 and approximately 6% of our average daily net production for the three months ended March 31, 2014 were located in the Ventura basin. We actively operate and develop 25 fields (nearly 40% of the fields) in this basin consisting of conventional primary, IOR, EOR and unconventional project types. We currently hold approximately 0.3 million net acres in the Ventura basin, approximately 83% of which we hold in fee.

The Ventura basin contains a Cretaceous-age to Pleistocene-age, mostly marine, sedimentary section in a major fold and thrust belt that began developing during the late Pliocene. The Ventura basin is the onshore part of the main structural feature and its offshore extension is the modern Santa Barbara basin. All of the sedimentary section is productive at various locations, and most reservoirs are sandstones with favorable porosity and permeability. In general, most traps are anticlinal, modified to some degree by faults and with significant stratigraphic trapping. As shown in the stratigraphic column below, the basin contains multiple stacked formations throughout its depths, and we believe that the Ventura basin provides an appealing inventory of existing field re-development opportunities, as well as new play discovery and unconventional play potential.

The first fields discovered in the Ventura basin were near the Ojai field in the town of Santa Paula in 1861. Since then, approximately 65 oil and gas fields have been discovered. Multiple source rocks are present with Miocene-age (Monterey and Rincon formations) and Eocene-age (Anita and Cozy Dell formations) sediments. Complex stratigraphy and structural geology enhance the exploration potential in the basin. Only limited use of modern drilling and completion techniques and limited seismic surveys have occurred since the late 1960s, with virtually no exploration drilling. In 2013, we completed the acquisition of, and are currently processing, the first ever 3D seismic survey in the Ventura basin. We believe this 3D seismic data gives us a competitive advantage in exploring this basin.

Approximately 3% of our estimated proved reserves as of December 31, 2013 and approximately 6% of our average daily net production for the three months ended March 31, 2014 were located in the Sacramento basin. We actively operate and develop 53 fields in this basin primarily consisting of dry gas production. We currently hold approximately 0.5 million net acres in the Sacramento basin, approximately 36% of which we hold in fee. We believe our significant acreage position in the Sacramento basin gives us the option for future development and rapid production growth in an attractive gas price environment. We produced approximately 84% of the produced gas in the Sacramento basin during 2013.

The Sacramento basin is a deep, elongated northwest-trending basin located in northern California covering around 12,000 square miles and forming the northern part of California's Central Valley. It contains a thick sequence of sedimentary rocks that range in age from lower Cretaceous to Neogene sediments in an area that is approximately 200 miles long and 45 miles wide. Producing reservoirs range from upper Cretaceous-age to Pliocene-age. The main reservoirs are the Cretaceous Starkey, Winters, Forbes, Kione, and the Eocene Domengine sands. Exploration in the basin started in 1918 and was focused on seeps and topographic highs. In the 1970s, the use of multifold 2D seismic led to large discoveries in the basin. The acquisition of 3D seismic surveys in the mid-1990s helped define trapping mechanisms and reservoir geometries. The Sacramento basin has been extensively explored for petroleum resources, and more than 11 Tcf of natural gas have been produced.

Stratigraphic Chart of San Joaquin, Los Angeles, Ventura and Sacramento Basins

California is home to several basins characterized by extensive production history, long reserve life and multiple producing horizons. As shown in the table below, the state's four major oil and gas basins contain multiple stacked formations throughout their depths that include both conventional and unconventional opportunities. Our current operations in these four basins are focused on the formations

highlighted below, however, we believe the stacked reservoirs within our asset base provide exposure to additional upside potential in several emerging resource plays.

We believe we are well-positioned to successfully execute our business strategies because of the following competitive strengths:

We develop our capital programs by prioritizing rates of return and balancing the short- and long-term growth potential of each of our assets. The diversity of our portfolio allows us to generate attractive investment opportunities in a variety of operating and commodity price environments. We continually monitor internal performance and external factors and adjust our capital program with the objective of achieving the highest total returns on our portfolio of drilling opportunities.

We expect our 2015 capital budget to increase further from 2014 levels to a range of $2.3 billion to $2.5 billion as we reinvest substantially all of our increased cash flow in our capital program.

We determine the development method to use based on reservoir characteristics, reserves potential and expected returns. We seek to optimize the potential of our conventional assets by progressively using primary recovery methods, which may include some well stimulation techniques, IOR methods such as waterflooding and EOR methods like steamflooding, using both vertical and horizontal drilling. All of these techniques are proven technologies we have used extensively in California.

Primary recovery methods are the first techniques we use to develop a reservoir. These methods consist of drilling and producing wells without supplementing the natural reservoir energy. Our successful exploration program continues to provide us with primary recovery opportunities in new reservoirs or through extensions of existing fields. In 2013, 22% of our production came from primary production in conventional reservoirs. We continued to expand our conventional primary recovery programs in 2013, and with our 2014 development plans, we expect this growth pattern to continue. We are planning to drill 171 wells in 2014 that will be produced using conventional primary recovery methods. Our conventional development programs set up future opportunities to convert these reservoirs to waterfloods or steamfloods after their primary production phase.

Waterflooding works by repressurizing a reservoir through water injection and displacing or "sweeping" oil to producing wellbores. Waterfloods are low-cost operations with attractive margins and returns in the current price environment. These operations typically have low and predictable production declines and allow us to extend the productive life of a reservoir and significantly increase our incremental recovery after primary depletion. We use waterfloods extensively in the San Joaquin, Los Angeles and Ventura basins where they have allowed us to reduce production decline or modestly grow our production from mature fields such as Elk Hills and Wilmington. Since 2011, we have achieved 32% production growth from waterflood projects and we expect this growth pattern to continue. We spent $480 million on waterfloods in 2013, drilling 196 wells including 146 producing wells. We plan to increase our capital spending on waterfloods in 2014 by 57% to $754 million and to drill 277 wells.

Our Long Beach and Tidelands properties in the Wilmington field are two of our largest waterflood operations, representing 14% and 5%, respectively, of our revenues for the year ended December 31, 2013.

Upon acquiring the right to serve as operating contractor to the City of Long Beach in April 2000, we implemented a development drilling program to expand operations in this mature reservoir. Since April 2000, we have drilled 434 oil producing wells and 200 water injecting wells at a cost of $930 million. An additional $193 million was invested in facilities repairs and upgrades to support incremental production and injection. Our cumulative production and year end proved reserves from the unit is over twice the proved reserves originally purchased and we continue to find additional reserves. As of January 2014, we have identified over 500 development drilling locations.

Recognizing the success of our Long Beach Unit waterflood efforts, we executed new contracts with the State of California and City of Long Beach to facilitate the development of Tidelands properties. These agreements are similar to our contractual arrangement in the Long Beach Unit and support

development drilling in this mature property. In the ten years preceding execution of these new contracts, drilling on the Tidelands properties was limited to replacing failed wells or relocating wells to accommodate projects of the Port of Long Beach. As a result of executing these new contractual arrangements, we began development drilling on the Tidelands property in January 2011. Since January 2011, we have drilled 122 oil production wells and 49 water injection wells at a cost of $243 million. An additional $95 million was invested in facilities repairs and upgrades to support incremental production and injection. Tidelands gross oil production has increased by more than 50% from 6,400 Bbls/d in January 2010 to 9,800 Bbls/d today. As of January 2014, over 400 development drilling projects have been identified to further develop the Tidelands waterflood.

Steamfloods work by lowering the viscosity of the oil, causing it to flow more easily to wells. Our steamflood properties have seen some of the highest growth in our portfolio over the last year. We have steamflood projects in the San Joaquin and Ventura basins where we produce heavy oil, primarily in Kern County and in fields such as Kern Front and Lost Hills with demonstrated steamflood results. We have gradually increased our capital allocated to steamfloods over the years and expect to continue doing so for as long as the current oil versus gas price spread continues. Our steamfloods are highly profitable in this price environment, allowing us to use inexpensive gas to generate steam, which is then injected into the reservoir to produce oil. Full development of these steamfloods is a multi-year endeavor that involves upfront infrastructure construction for steam and water processing facilities and follow-on development drilling. These steam projects are generally shallower in depth (300-2,500 ft) than our other programs and the wells are relatively inexpensive to drill. Therefore, we can normally implement a drilling program quickly with attractive rates of return. We spent $375 million on steamfloods in 2013, drilling 387 wells, including 304 producing wells. We expect our total capital spending on steamfloods for 2014 to be slightly lower than 2013, although our total drilling capital expenditures are expected to be slightly higher in 2014, with 591 wells expected to be drilled in 2014 as compared to 387 wells in 2013. In 2013, our total production from steamfloods was 25,000 Boe/d gross and we injected an average of 95,000 BS/d gross in our operated fields. We expect to nearly triple our 2013 injection rate by around 2020. We have already made significant infrastructure investments to support the bulk of this planned expansion.

Our Kern Front property is an example of an ongoing successful steamflood project with steamflood expansion occurring laterally across the field. As part of our multi-year development program, we drilled 197 new wells on our Kern Front steamflood in 2013 for $77 million. We have also invested in new steam generators to increase current steam capacity to 115,000 BS/d from 70,000 BS/d at the beginning of 2013. Gross production response increased by 1,900 Bbls/d, or 23%, in 2013. It can take 12 to 18 months following the drilling of a producing well and initiation of a steamflood before the producing wells begin to fully respond. We anticipate additional, steady steamflood expansion to continue for several more years at Kern Front resulting in nearly doubled levels of injection by about 2020. Our Kern Front steamflood represented 7% of our revenues for the year ended December 31, 2013 and we expect it will be a significant contributor to operating cash flow going forward.

We believe our undeveloped unconventional acreage has the potential to provide significant long-term production growth. In total we hold mineral interests in approximately 1.1 million net acres with unconventional potential and have identified 4,682 gross (4,264 net) unconventional drilling locations on this acreage. Over the last five years, we have drilled and completed over 570 unconventional development wells, primarily in the upper Monterey formation, with nearly 100% commercial success rate. As a result of focusing more on these reservoirs over the past few years, approximately 39% of our 2013 production was from unconventional reservoirs, an increase of approximately 160% since the acquisition of our Elk Hills field properties in 1998.

Approximately 3,812 of our unconventional drilling locations are located on our acreage in the Monterey formation in the San Joaquin, Los Angeles and Ventura basins. The geology of the Monterey formation is highly complex and not uniform due to localized and varied faulting and changes in structure and rock characteristics. The potential of our Monterey and our other potential unconventional acreage is difficult to estimate because of these variations in the underlying geology and the relative lack of readily available information about the geology in the public domain. We believe, however, that our own work on unconventional acreage in California, including the study of subsurface geology, well log and seismic data, and observed production results gave us a better understanding of the geology and hydrocarbon potential than had we relied solely on publicly available data.

The Monterey formation is divided into upper and lower intervals. The overwhelming majority of the Monterey shale production to date, both onshore and offshore, has been from the upper Monterey. We have successfully produced from seven discrete stacked pay horizons within the Monterey formation, primarily within the upper Monterey, using modern drilling techniques. In 2013, we produced over 50,000 Boe/d from unconventional reservoirs of the upper Monterey shale. In the upper Monterey we plan to expand the productive area and will continually strive to increase recoveries by applying reduced well spacing and both vertical and horizontal well geometries. To date, production from our unconventional reservoirs has been by primary mechanisms, resulting in recoveries typically below 10%. In the future, we plan to test the application of IOR and EOR methods to increase the recovery factor for these reservoirs.

We are applying the knowledge acquired from our successes in the upper Monterey to other shales in the San Joaquin basin such as the Kreyenhagen and Moreno formations. The Kreyenhagen and Moreno formations are hydrocarbon source rocks that have generated oil and gas, and we believe they offer similar development opportunities to the upper Monterey due to their multiple stacked pay reservoirs.

The lower Monterey is not as thick as the upper Monterey but contains a variety of reservoir lithologies. This is the principal hydrocarbon source rock within the overall Monterey formation but has a more limited production history than the upper Monterey, and therefore limited knowledge exists regarding its potential. We are applying our knowledge and experience from the upper Monterey to the lower Monterey, which we believe will be productive over time.

In the upper Monterey, we plan to expand the productive area and will continually strive to increase recoveries by applying reduced well spacing and both vertical and horizontal well geometries. To date, production from our unconventional reservoirs has been by primary mechanisms, resulting in recoveries typically below 10%. In the future, we plan to test the application of IOR and EOR methods to increase the recovery factor for these reservoirs.

The table below compares certain characteristics of our unconventional reservoir targets to those of other prolific North American shale plays.

Play

Upper Monterey(1)	3,500' - 12,000'	250' - 3,500'	5 - 30	<0.0001 - 2	1 - 12	0.7 - 1.0
Lower Monterey(1)	9,000' - 16,000'	200' - 500'	5 - 12	<0.001 - 0.05	2 - 18	0.8 - 1.0
Kreyenhagen(1)	8,000' - 16,000'	200' - 350'	5 - 15	<0.001 - 0.1	1 - 6	0.7 - 1.2
Moreno(1)	8,000' - 16,000'	200' - 300'	5 - 10	<0.001 - 0.1	2 - 6	0.7 - 1.3
Bakken	3,000' - 11,000'	6' - 145'	2 - 12	0.05	8 - 21	<1
Barnett	5,400' - 9,500'	100' - 500'	4.0 - 9.6	<0.0001 - 0.1	4 - 8	0.8 - 2.0
Eagle Ford	5,000' - 12,000'	100' - 250'	3.4 - 14.6	0.13	2 - 9	1.0 - 1.45

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 develop a pattern of success across these different 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 better direct our capital to higher success projects allowing us to strategically increase our investment levels on unconventional drilling. We expanded our unconventional programs in 2013, and plan to continue this expansion by drilling 150 wells in 2014, all of which will target oil. With continued successful development and expansion, we believe that the unconventional production from these assets will become a significant portion of our production.

We intend to continue our active exploration program in both conventional and unconventional plays where discoveries can quickly be developed into producing fields. We believe our experienced technical staff, leading acreage position and extensive 3D seismic library, covering over 4,250 square miles, or 2.7 million acres, including 47% of our acreage, results in a strong competitive advantage. Our interpretation of this seismic data, covering a large portion of our prospective acreage, and our extensive knowledge of California geology and producing fields has resulted in a large inventory of exploratory projects. Our current drilling inventory includes 7,237 gross (5,117 net) exploration drilling locations that are located in proven formations, the majority of which are located near existing producing fields. Additionally, we have identified 6,400 gross (5,300 net) prospective resource drilling locations in the lower Monterey, Kreyenhagen, and Moreno resource plays.

From 2007 to 2013, we drilled more than 100 exploration wells targeting both conventional and unconventional reservoirs. These projects were primarily in hydrocarbon-rich areas in and around discovered oil and gas fields. As a result, substantially all of our exploration wells encountered strong indications of hydrocarbons. Approximately 70% of these wells produced hydrocarbons and approximately 50% of those wells were converted to commercial production. We believe that many of the remaining exploration wells that produced hydrocarbons could also be converted to commercial production and potentially development projects, although we are currently pursuing higher return projects in lieu of developing these wells.

In 2014, we expect to spend approximately 5% of our total capital, or $100 million, on exploration projects with a continued focus on prospects that can generate near-term returns. Approximately 50% of this amount will target unconventional reservoirs. We expect exploration capital in the future to be focused in the San Joaquin, Ventura and Sacramento basins, and weighted toward programs where we have a proven track record of success. In addition, our program also includes exploration prospects in several high-potential resource plays, where we are the largest holder of unconventional acreage in the state. Success in these plays could generate significant longer-term production growth. We currently expect the portion of our exploration budget targeting such projects to increase following the spin-off.

Our recent investments in infrastructure downstream of the wellhead have been instrumental in maximizing both the efficiencies of our production and the returns from our assets. As a result, we possess a portfolio of facilities that complements our operations and provides a strategic advantage for us in California. For example, our Elk Hills cryogenic gas plant is the largest gas processing complex in California, with capacity of 200 MMScf/d of wellhead gas. This modern plant, constructed in 2012, along with our other facilities, provides us with an aggregate processing capacity of over 540 MMScf/d with adequate redundancy to maximize uptime. These facilities enable us to optimize the amount of NGLs separated from the unprocessed wellhead gas stream and achieve higher overall realized prices for our production. We also own and operate a system of gas processing facilities in the Ventura Basin that is capable of processing equity wellhead gas from the surrounding areas. We continue to identify

opportunities to add incremental gas processing capacity in close proximity to our natural gas producing areas in order to maximize production efficiencies. Our gas processing facilities are interconnected via pipelines to nearby third-party rail and trucking facilities, with access to certain North American NGLs markets. In addition, we have truck rack facilities coupled with a battery of pressurized storage tanks at our Elk Hills gas processing facility for NGLs sales to third parties.

We are a large consumer of electricity, particularly with respect to our EOR waterflood and steamflood operations. We source all of our electricity needs at our Elk Hills operations, which run at about 120 megawatts, through our wholly-owned 550 megawatt combined cycle power plant located adjacent to our Elk Hills processing facilities, and sell the excess. This power plant provides low cost electricity for field operations and steam that further minimizes overall field operating costs. We also operate a 46 megawatt cogeneration facility at Elk Hills that provides resource diversity and additional reliability to support field operations. Within our Long Beach operations, we operate a 45 megawatt power generating facility that provides almost 40% of the Long Beach operation's electricity requirements, reducing operating costs.

To facilitate access to attractive markets, we own an extensive network of over 20,000 miles of oil and gas gathering lines. Virtually all of our natural gas production in California is connected via these facilities, which interconnect with the major third party natural gas pipeline systems. As a result of these connections, we have the ability to access multiple delivery points to improve the prices we obtain for our natural gas production.

As a result of recent investments in infrastructure, we do not anticipate any substantial infrastructure spending during the next several years. We believe the absence of such significant expenditures should support strong cash flows.

We market our crude oil, natural gas, NGLs, and electricity in accordance with standard energy industry practices. Currently, we market our production through a subsidiary of Occidental but, after the spin-off, we will market through our own subsidiary.

Crude Oil. Substantially all of our crude oil production is connected to California markets via our crude oil gathering pipelines. We generally do not transport, refine or process the crude oil we produce and do not have any long-term crude oil transportation arrangements in place. California is heavily reliant on imported sources of energy, with approximately 62% of oil consumed during 2013 imported from outside the state, mostly from foreign locations. We sell almost all of our crude oil into the California refining markets, which we believe are among the most favorable in the U.S. Since California imports a significant percentage of its crude oil requirements, California refiners typically purchase crude oil at international waterborne-based prices at a premium to WTI-based prices. For example, crude prices at the California Buena Vista Hills hub were, on average, an 8% premium to WTI in 2013 and are typically linked to world prices such as Brent. This price is then adjusted for differentials based upon delivery location and quality. Currently, we do not have any crude oil sales contracts with a term extending past 2015. Our average realized price for crude oil in 2013 reflected a 6% premium to WTI index prices.

Natural Gas. Because California imports approximately 90% of the natural gas consumed in the state, we do not have any significant interstate natural gas transportation commitments. We do have intrastate transportation capacity where necessary to access markets. These contracts are required to facilitate deliveries. We sell virtually all of our natural gas production under individually negotiated contracts using market-based pricing on a monthly or shorter basis.

NGLs. We process substantially all of our NGLs through our processing plants, which facilitate access to third party delivery points near the Elk Hills field. We do not have long-term or long-haul

interstate NGLs transportation agreements. We sell virtually all of our NGLs to third parties using market-based pricing. Our NGLs sales are generally pursuant to one-year contracts that are renewed annually.

Electricity. While part of the electric output of our generation facilities is utilized within our production facilities to reduce field operating costs, a significant portion is sold into the California market. Excess electric output and associated electric products are marketed to third parties and offered daily into the California electric market to be dispatched based on pricing and grid requirements.

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

For the years ended December 31, 2013, 2012 and 2011, ConocoPhillips/Phillips 66 Company and Tesoro Refining & Marketing Company LLC each accounted for more than 10% of our revenue and collectively accounted for 42%, 46% and 44%, respectively. No other customer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasing our products, we do not believe the effect on our operating results and financial condition would be material.

The information with respect to our estimated reserves presented below has been prepared in accordance with the rules and regulations of the SEC.

Proved oil, NGLs and natural gas reserves were estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangements. Oil, NGLs and natural gas prices used for this purpose were based on posted benchmark prices and adjusted for price differentials including gravity, quality and transportation costs. For the 2013 disclosures, the calculated average WTI oil price was $96.94 per Bbl. The calculated average NYMEX gas price for 2013 disclosures was $3.65 per MMBtu. The realized prices used for the 2013 disclosures were $102.67 per Bbl for oil $50.53 per Bbl for NGLs and $3.84 per Mcf for natural gas.

The following table summarizes our estimated proved reserves and related PV-10 at December 31, 2013. Reserves are stated net of applicable royalties. Estimated reserves include our economic interests under arrangements similar to production-sharing contracts relating to the Wilmington field in Long

Beach. For a more detailed description of these contractual arrangements, see "Management's Discussion and Analysis of Financial Condition and Results of Operation—Operations."

	At December 31, 2013

	San Joaquin Basin		Los Angeles Basin		Ventura Basin		Sacramento Basin		Total
Proved developed reserves:
Oil (MMBbl)		225		109		29		—		363
NGLs (MMBbl)		47		—		2		—		49
Natural Gas (Bcf)		459		11		25		116		611


Total (MMBoe)(1)(2)		349		111		35		19		514




Proved undeveloped reserves:
Oil (MMBbl)		106		47		16		—		169
NGLs (MMBbl)		21		—		2		—		23
Natural Gas (Bcf)		210		6		10		1		227


Total (MMBoe)(2)		162		48		20		—		230




Total proved reserves:
Oil (MMBbl)		331		156		45		—		532
NGLs (MMBbl)		68		—		4		—		72
Natural Gas (Bcf)		669		17		35		117		838


Total (MMBoe)(2)		511		159		55		19		744

Our total proved reserve additions from all sources were 86 MMBoe in 2013. All of these reserve additions were the result of our development program. We added 89 MMBoe from improved recovery, slightly offset by 3 MMBoe of negative revisions. The total additions to our proved reserves during the year ended December 31, 2013 were as follows:



Improved recovery:
Oil (MMBbl)	49		24		3		—		76
NGLs (MMBbl)	4		—		—		—		4
Natural Gas (Bcf)	47		3		2		—		52


Total (MMBoe)	61		25		3		—		89




Extensions and discoveries:
Oil (MMBbl)	—		—		—		—		—
NGLs (MMBbl)	—		—		—		—		—
Natural Gas (Bcf)	—		—		—		—		—


Total (MMBoe)	—		—		—		—		—




Revisions of previous estimates:
Oil (MMBbl)	(8	)	3		(3	)	—		(8	)
NGLs (MMBbl)	13		—		—		—		13
Natural Gas (Bcf)	(4	)	(4	)	(1	)	(38	)	(47	)


Total (MMBoe)	4		2		(3	)	(6	)	(3	)




Total proved reserve additions:
Oil (MMBbl)	41		27		—		—		68
NGLs (MMBbl)	17		—		—		—		17
Natural Gas (Bcf)	43		(1	)	1		(38	)	5


Total (MMBoe)	65		27		—		(6	)	86

Our ability to add reserves, other than through purchases, depends on the success of improved recovery, extension and discovery projects, each of which depends on reservoir characteristics, technology improvements and oil and gas prices, as well as capital and operating costs. Many of these factors are outside management's control, and will affect whether the historical sources of proved reserve additions continue to provide reserves at similar levels.

In 2013, we added proved reserves of 89 MMBoe from improved recovery through proven IOR and EOR methods, as well as unconventional primary mechanisms. The improved recovery additions in 2013 were mainly associated with the continued development of properties in the San Joaquin and Los Angeles basins. These properties comprise both conventional and unconventional projects. The types of conventional IOR and EOR development methods we use can be applied through existing wells, though additional drilling is frequently required to fully optimize the development configuration. Many of our projects, including unconventional projects, rely on improving permeability to increase flow in the wells. In addition, some improved recovery comes from drilling infill wells that allow recovery of reserves that would not be recoverable from existing wells.

Revisions can include upward or downward changes to previous proved reserve estimates due to the evaluation or interpretation of geologic, production decline or operating performance data. In addition, product price changes affect proved reserves we record. For example, higher prices may increase the economically recoverable reserves, because the extra margin extends the expected life of the operations. Offsetting this effect, higher prices slightly decrease our share of proved reserves under arrangements similar to production-sharing contracts at our Long Beach operations because less oil is required to recover costs. Conversely, when prices drop, our share of proved reserves slightly increases for such arrangements similar to production-sharing contracts and economically recoverable reserves may drop for other operations. In 2013, revisions of previous estimates were negligible resulting in a decrease of 3 MMBoe to proved reserves.

Reserve estimation rules require that estimated ultimate recoveries be more likely to increase or remain constant than to decrease as changes are made due to increased availability of technical data. As a result, apart from the effect of product prices, future proved reserve revisions should be positive in aggregate over time rather than negative.

In 2013, we had proved undeveloped reserve additions of 72 MMBoe from improved recovery, primarily in the San Joaquin and Los Angeles basins, offset slightly by 6 MMBoe of negative revisions. We also transferred 43 MMBoe of proved undeveloped reserves to the proved developed category as a result of the 2013 development programs, of which 91% were in the San Joaquin and Los Angeles basins. We spent approximately $700 million in 2013 to convert proved undeveloped reserves to proved developed reserves. While costs to develop proved undeveloped reserves have generally increased over time, in 2013

drilling costs per barrel decreased by 20% as a result of capital efficiency initiatives. The total changes to our proved undeveloped reserves during the year ended December 31, 2013 were as follows:



Improved recovery:
Oil (MMBbl)	40		20		3		—		63
NGLs (MMBbl)	3		—		—		—		3
Natural Gas (Bcf)	35		2		1		—		38


Total (MMBoe)	49		20		3		—		72




Extensions and discoveries:
Oil (MMBbl)	—		—		—		—		—
NGLs (MMBbl)	—		—		—		—		—
Natural Gas (Bcf)	—		—		—		—		—


Total (MMBoe)	—		—		—		—		—




Revisions of previous estimates:
Oil (MMBbl)	(1	)	(2	)	(1	)	—		(4	)
NGLs (MMBbl)	4		—		—		—		4
Natural Gas (Bcf)	(15	)	—		—		(21	)	(36	)


Total (MMBoe)	—		(2	)	(1	)	(3	)	(6	)




Transfers to proved developed reserves:
Oil (MMBbl)	(24	)	(7	)	(3	)	—		(34	)
NGLs (MMBbl)	(3	)	—		—		—		(3	)
Natural Gas (Bcf)	(30	)	(1	)	(2	)	(4	)	(37	)


Total (MMBoe)	(32	)	(7	)	(3	)	(1	)	(43	)




Proved undeveloped reserve additions, net of transfers:
Oil (MMBbl)	15		11		(1	)	—		25
NGLs (MMBbl)	4		—		—		—		4
Natural Gas (Bcf)	(10	)	1		(1	)	(25	)	(35	)


Total (MMBoe)	17		11		(1	)	(4	)	23

Our estimates of proved reserves and associated future net cash flows as of December 31, 2013 were made by Occidental's technical personnel, including personnel that will work for us after the separation, and are the responsibility of each company's management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and management's funding commitments to develop the reserves. This process involves reservoir engineers, geoscientists, planning engineers and financial analysts. As part of the proved reserves estimation process, all reserve volumes are estimated by a forecast of production rates, operating costs and capital expenditures. Price differentials between benchmark prices (the unweighted arithmetic average of the first-day-of-the-month price for each month within the year) and realized prices and specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including estimates from decline-curve analysis, type-curve analysis, material balance calculations that take into account the volumes of substances replacing the volumes produced and associated reservoir pressure changes, seismic analysis and computer simulation of the reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the

formation being evaluated or in an analogous formation. Operating and capital costs are forecast using the current cost environment applied to expectations of future operating and development activities.

Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods, for which the incremental cost of any additional required investment is relatively minor. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

The current Senior Vice President, Reserves for Occidental's oil and gas operations was responsible for overseeing the preparation of Occidental's reserve estimates, including those related to our properties for 2013, and for ensuring the estimates comply with SEC rules and regulations. He also oversaw the internal audit and review of the oil and gas reserves data. He has over 30 years of experience in the upstream sector of the exploration and production business, and has held various assignments in North America, Asia and Europe. He is a three-time past Chair of the Society of Petroleum Engineers Oil and Gas Reserves Committee, is an American Association of Petroleum Geologists ("AAPG") Certified Petroleum Geologist and currently serves on the AAPG Committee on Resource Evaluation. He is a member of the Society of Petroleum Evaluation Engineers, the Colorado School of Mines Potential Gas Committee and the UNECE Expert Group on Resource Classification. He is also an active member of the Joint Committee on Reserves Evaluator Training. Additionally, he has Bachelor of Science and Master of Science degrees in geology from Emory University in Atlanta.

Occidental has a Corporate Reserves Review Committee ("Reserves Committee"), consisting of senior corporate officers, who reviewed and approved Occidental's oil and gas reserves, which included our oil and gas reserves for 2013. The Reserves Committee reports to the Audit Committee of Occidental's board of directors during the year. Ryder Scott was retained to separately review the oil and gas reserves estimation processes used in 2013 for our properties and to provide the opinion noted below.

Ryder Scott conducted a process review of the methods and analytical procedures used by Occidental's engineering and geological staff to estimate the proved reserves volumes, prepare the economic evaluations and determine reserves classifications as of December 31, 2013. Ryder Scott reviewed the specific application of such methods and procedures for selected oil and gas properties considered to be a valid representation of our 2013 year-end total proved reserves portfolio. In 2013, Ryder Scott reviewed approximately 37% of our proved oil and gas reserves. Since being engaged by Occidental in 2003, Ryder Scott has reviewed the specific application of reserve estimation methods and procedures for approximately 79% of our proved oil and gas reserves that existed at December 31, 2013. Ryder Scott was retained to provide objective third-party input on the methods and procedures used to estimate our oil and gas reserves for 2013 and to gather industry information applicable to the reserve estimation and reporting process for those reserves. Ryder Scott was not engaged to render an opinion as to the reasonableness of our reserves quantities. We filed Ryder Scott's independent report as an exhibit to this Form 10.

Based on its reviews, including the data, technical processes and interpretations presented with respect to our oil and gas reserves, Ryder Scott concluded that the overall procedures and methodologies utilized in estimating the proved reserves volumes, documenting the changes in reserves from prior estimates, preparing the economic evaluations and determining the reserves classifications for the reviewed properties are appropriate for the purpose thereof and comply with current SEC regulations.

Because the separation of CRC from Occidental will occur in late 2014, we will use the established reserves review process described above to estimate 2014 proved reserves. Following the 2014 reserve estimation, we intend to rely more heavily on independent reserves estimation companies, such as Ryder Scott, to estimate our proved reserves volumes.

Based on our reserves report as of December 31, 2013, we have 2,141 gross (2,024 net) drilling locations attributable to our proved undeveloped reserves. We use production data and experience gained from our development programs to identify and prioritize this proven drilling inventory. These drilling locations are included in our inventory only after they have been evaluated technically and are deemed to have a high likelihood of being drilled within a five-year time frame. As a result of rigorous technical evaluation of geologic and engineering data, it can be estimated with reasonable certainty that reserves from these locations will be commercially recoverable in accordance with SEC guidelines. Management considers the availability of local infrastructure, drilling support assets, state and local regulations and other factors it deems relevant in determining such locations.

We have also identified a multi-year inventory of 8,313 gross (8,043 net) drilling locations that are not associated with proved undeveloped reserves but are specifically identified on a field-by-field basis considering the applicable geologic, engineering and production data. We analyze past field development practices and identify analogous drilling opportunities taking into consideration historical production performance, estimated drilling and completion costs, spacing and other performance factors. These drilling locations primarily include (i) infill drilling locations, (ii) additional locations due to field extensions or (iii) potential IOR and EOR project expansions, some of which are currently in the pilot phase across our properties, but have yet to be moved to the proven category. We believe the assumptions and data used to estimate these drilling locations are consistent with established industry practices with well spacing selected based on the type of recovery process we are using.

Our portfolio of prospective drilling locations contains 7,237 gross (5,117 net) unrisked exploration drilling locations that are located in proven formations, the majority of which are located near existing producing fields. We use internally generated information and proprietary models consisting of data from analog plays, 3D seismic data, open hole and mud log data, cores, and reservoir engineering data to help define the extent of the targeted intervals and the potential ability of such intervals to produce commercial quantities of hydrocarbons. Information used to identify exploration locations includes both our own proprietary as well as industry data available in the public domain. After defining the reservoir target area, we identified our exploration drilling locations within the applicable intervals by applying the well spacing we have historically utilized for the applicable type of recovery process used.

In addition, we have 6,400 gross (5,300 net) unrisked prospective resource drilling locations identified in the lower Monterey, Kreyenhagen, and Moreno resource plays based on screening criteria that contain geologic and economic considerations and very limited production information. Prospective play areas are defined by geologic data consisting of well cuttings, hydrocarbon shows, open-hole well logs, geochemical data, available 3D or 2D seismic data and formation pressure data where available. Information used to identify our prospective locations includes both our own proprietary, as well as industry, data available in the public domain. Prospective resource drilling locations were based on an assumption of 80-acre spacing per well throughout the prospective area for each resource play.

Our well spacing determinations in the above categories of identified well locations are based on actual operational spacing within our existing producing fields, which we believe are reasonable for the particular recovery process employed (i.e., primary, waterflood, EOR). Due to the significant vertical

thickness and multiple stacked reservoirs usually encountered by our drilling wells, typical well spacing is generally less than 20 acres and often 10 acres or less in the majority of our fields unless specified differently above. These parameters also meet the general well spacing restrictions imposed on certain oil and gas fields in California.

Our identified drilling locations have been scheduled as part of our current multi-year drilling schedule or are expected to be scheduled in the future. However, we may not drill our identified sites at the times scheduled or at all. We view the risk profile for our exploration drilling locations and our prospective resource drilling locations as being higher than for our other drilling locations due to relatively less available geologic and production data and drilling history, in particular with respect to our prospective resource locations, which are in unproven geologic plays. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate.

Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals, available transportation capacity and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. For a discussion of the risks associated with our drilling program, see "Risk Factors—Risks Related to Our Business—We may not drill our identified sites at the times we scheduled or at all."

The table below sets forth our total identified drilling locations as of December 31, 2013, excluding our prospective drilling locations from new resource plays.

	Proven Drilling Locations				Total Identified Drilling Locations

	Oil and Natural Gas Wells		Injection Wells		Oil and Natural Gas Wells		Injection Wells
San Joaquin Basin
Primary Conventional		156		—		3,760		—
Waterflood		117		59		930		675
Steamflood		758		222		2,212		612
Unconventional		276		—		4,324		323


San Joaquin Basin subtotal		1,307		281		11,226		1,610


Los Angeles Basin
Primary Conventional		—		—		37		—
Waterflood		287		132		1,000		500
Steamflood		—		—		—		—
Unconventional		—		—		—		—


Los Angeles Basin subtotal		287		132		1,037		500


Ventura Basin
Primary Conventional		43		—		1,650		—
Waterflood		36		38		201		234
Steamflood		14		—		190		—
Unconventional		2		—		35		—


Ventura Basin subtotal		95		38		2,076		234


Sacramento Basin
Primary Conventional		1		—		1,008		—


Sacramento Basin subtotal		1		—		1,008		—


Total Identified Drilling Locations		1,690		451		15,347		2,344

Oil, NGLs and natural gas are commodities; therefore, the price that we receive for our production is largely a function of market supply and demand. Product prices are affected by a variety of factors, including changes in consumption patterns, global and local (particularly for gas) economic conditions, inventory levels, production disruptions or threatened disruptions, the actions of OPEC and other oil and natural gas producing countries, currency exchange rates, worldwide drilling and exploration activities, the effects of conservation, weather, geophysical and technical limitations, refining and processing disruptions, transportation bottlenecks and other matters affecting the supply and demand dynamics of oil, gas and NGLs, and the effect of changes in market perceptions. We typically have not hedged commodity price risk and do not expect to have a hedging program in the future.

The following table sets forth information regarding production, realized and benchmark prices, and production costs for the years ended December 31, 2013, 2012 and 2011 and for the three months ended March 31, 2014 and 2013. For additional information on price calculations, see information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations."

	Three Months Ended March 31,				Year Ended December 31,

	2014		2013		2013		2012		2011
Production Data(a)(b):
Oil (MBbl/d)		95		88		90		88		80
NGLs (MBbl/d)		19		20		20		17		15
Natural gas (MMcf/d)		242		260		260		256		260
Average daily combined production (MBoe/d)(c)		154		151		154		148		138
Total combined production (MMBoe)(c)		14		14		56		54		50
Average realized prices:
Oil (per Bbl)	$	102.32	$	107.26	$	104.16	$	104.02	$	103.80
NGLs (per Bbl)	$	60.39	$	48.87	$	50.43	$	52.76	$	70.03
Natural gas (per Mcf)	$	4.78	$	3.40	$	3.73	$	2.94	$	4.31
Average Benchmark prices:
WTI oil ($/Bbl)	$	98.68	$	94.37	$	97.97	$	94.21	$	95.12
NYMEX gas ($/Mcf)	$	4.66	$	3.37	$	3.66	$	2.81	$	4.11
Average costs per Boe:
Production costs	$	20.80	$	19.27	$	18.99	$	24.34	$	21.30
Other operating expenses	$	5.04	$	3.74	$	4.38	$	4.04	$	3.89
Depreciation, depletion and amortization	$	20.83	$	20.59	$	20.38	$	17.15	$	13.38
Taxes other than on income	$	3.76	$	3.90	$	3.29	$	3.09	$	2.84

The following table sets forth our reserves and production by basin and recovery mechanism.

						Average Net Daily Production(MBoe/d)

	Total Proved Reserves (MMBoe)		Oil (%)			Year Ended December 31, 2013		Three Months Ended March 31, 2014
San Joaquin basin
Primary Conventional		68		57	%		16		17
Waterflood		53		80	%		8		8
Steamflood		176		100	%		25		28
Unconventional		214		35	%		59		56


San Joaquin basin subtotal		511		65	%		108		109


Los Angeles basin
Primary Conventional		—		—	%		1		1
Waterflood		159		98	%		25		26
Steamflood		—		—	%		—		—
Unconventional		—		—	%		—		—


Los Angeles basin subtotal		159		98	%		26		27


Ventura basin
Primary Conventional		25		81	%		6		6
Waterflood		26		88	%		2		2
Steamflood		2		100	%		—		—
Unconventional		2		67	%		1		1


Ventura basin subtotal		55		82	%		9		9


Sacramento basin
Primary Conventional		19		—	%		11		9


Sacramento basin subtotal		19		—	%		11		9


Total		744		72	%		154		154

As of December 31, 2013, we had a total of 8,655 gross (7,792 net) producing wells, approximately 90% of which were oil wells. Our average working interests in our producing wells is approximately 92%. Many of our oil wells produce associated gas and some of our gas wells also produce condensate and NGLs.

The following table sets forth our productive oil and natural gas wells (both producing and capable of production) as of December 31, 2013.

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2013. Approximately 60% of our leased acreage was held by production at December 31, 2013.

Work programs are designed to ensure that the exploration potential of any leased property is fully evaluated before expiration. In some instances, we may elect to relinquish leased acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, we have generally been successful in obtaining extensions. Scheduled lease expirations for undeveloped acreage over the next three years are not significant and are not expected to have a material adverse impact on us. Historically, we have not dedicated any significant portion of our capital to prevent lease expirations and do not expect we will need to do so in the future.

The following table sets forth our participation in exploratory and development wells being drilled as of December 31, 2013.

At December 31, 2013, we were participating in 43 waterflood and eight steamflood pressure-maintenance projects. Twenty-five waterflood projects were located in the Los Angeles basin, 12 in the San Joaquin basin and six in the Ventura basin. All of the significant steamflood projects were located in San Joaquin basin.

The following table describes our drilling activity for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any

correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Net wells represent the sum of fractional interests in wells in which we own an interest.



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
2011
Oil
Exploratory	7.0	—	1.0	—	8.0
Development	472.2	68.8	43.3	—	584.3
Natural Gas
Exploratory	—	—	—	—	—
Development	—	—	—	4.0	4.0
Dry
Exploratory	10.3	—	—	—	10.3
Development	—	—	—	—	—

Since December 31, 2013, we have drilled 398 gross (359 net) wells, 187 of which were completed as producing wells and 117 of which are in various stages of completion.

We have made commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. In certain cases, an Occidental subsidiary entered into the commitment on our behalf and to the extent it exists as of the spin-off we will assume the commitment as of our separation from Occidental. As of December 31, 2013, the total amount contracted to be delivered is approximately 36 MBbls/d of oil under 60-day contracts, 3 Bcf of natural gas through 2014 and 1 MMBbl of NGLs through 2014. As of March 31, 2014, the total amount contracted to be delivered is approximately 36 MBbls/d of oil under 60-day contracts, 3 Bcf of natural gas through 2015 and 12 MMBbls of NGLs through 2015. The price for these deliveries is set at the time of delivery of the product at benchmark prices. We have significantly more production capacity than the amounts committed and have the ability to secure additional volumes in

case of a shortfall. None of the commitments in any given year is expected to have a material impact on our financial statements.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties at the time of acquisition. Prior to the commencement of drilling operations on those properties, we conduct a more thorough title examination and perform curative work with respect to significant defects. We generally will not commence drilling operations on a property until we have cured known material title defects on such property. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations, or net profits interest.

We have many competitors, some of which are larger and better funded, may be willing to accept greater risks or have special competencies. See "Risk Factors."

Our operations are regulated under a wide range of federal, state, local and other laws and regulations. California has regulations governing the conservation of oil and natural gas, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells and the regulation of well spacing or density. California also regulates methods of drilling and casing wells, plugging and abandonment of wells, the use and restoration of the surface of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, the disposal of fluids used and produced in connection with operations, the prevention and cleanup of pollutants and other matters, and the venting or flaring of natural gas. In addition, the state requires permits for, among other things, the drilling and stimulation of wells, and requires certain bonding requirements be met in order to drill or operate wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Our competitors in the California oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Our operations are subject to numerous federal, state, local, and other laws and regulations governing health and safety, the release or discharge of materials into the environment or otherwise relating to environmental protection. Generally, these health, safety and environmental laws and regulations may restrict or prohibit certain activities by us or by our contractors, increase costs or lower demand for or restrict the use of our products and services. Applicable federal safety and environmental laws include, but are not limited to, the Occupational Safety and Health Act ("OSHA"), the Clean Air Act ("CAA"), the Clean Water Act ("CWA"), the Safe Drinking Water Act ("SDWA"), the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and the Resource Conservation and Recovery

Act ("RCRA"), and California imposes additional laws that are analogous to, and often more stringent than, such federal laws. These laws and regulations:

Federal, state and local governments frequently revise health, safety and environmental laws and regulations, and any changes that result in delay or more stringent permitting, materials handling, engineering, disposal, cleanup and restoration requirements for the oil and gas industry could have a significant impact on our capital expenditures and operating costs. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and/or criminal fines and penalties and liability for non-compliance, costs of corrective action, cleanup and restoration, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief. Releases or discharges may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or discharges, including any third-party claims for damage to property, natural resources, or persons. Although we believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition or results of operations, we can make no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs in the future.

The CAA and its state analog and regulations restrict the emission of various air pollutants from oil and gas operations through the issuance of permits and the imposition of various pre-construction, monitoring, and reporting requirements. The U.S. Environmental Protection Agency ("EPA"), California Air Resources Board ("CARB") and regional air control districts and other local agencies also regulate such emissions through their permitting processes. Each of these agencies has developed, and continues to develop, stringent regulations governing emissions of air pollutants, which may increase the costs of compliance for our facilities. The control of air emissions from oil and gas operations is expected to be an ongoing focus of federal, state and local agencies for the foreseeable future.

Producing wells and associated equipment, natural gas plants, compressor stations and electric generating facilities generate volatile organic compounds ("VOCs"), particulate matter ("PM"), nitrogen oxides ("NOx") and other air pollutants. Some of our producing wells and associated facilities are in counties that potentially are subject to restrictive emission limitations and permitting requirements for VOCs, PM, NOx and other materials. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego construction, modification, or certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil and/or criminal penalties for non-compliance. Obtaining permits may delay the development of our oil, NGLs and natural gas projects, including the construction and operation of facilities.

The CWA and analogous state laws regulate the discharge of oil and other materials into U.S. and state waters. The scope of the CWA and analogous state laws depends on the definitions of "waters of the U.S." and "state waters," which have expanded from time to time. EPA and analogous California agencies prohibit the discharge of pollutants into regulated waters except in accordance with the terms of a permit or waiver. The CWA and associated regulations also prohibit the discharge of dredged and fill material to regulated waters, including jurisdictional wetlands, without a permit issued by the U.S. Army Corps of Engineers. Obtaining these permits may delay the development of oil, NGLs and natural gas projects and associated facilities. Federal and California state regulatory agencies can impose administrative, civil and/or criminal penalties as well as other enforcement mechanisms for non-compliance. The imposition of new or additional regulations could further limit or prohibit our ability to manage or dispose of wastewater, including produced water, drilling and completion fluids and other wastes associated with our operations.

The Oil Pollution Act of 1990 ("OPA") and associated regulations subject owners and operators of vessels, onshore facilities, and pipelines, as well as lessees or permittees of areas in which offshore facilities are located, to strict liability for removal costs and damages arising from an oil spill in U.S. waters. Although there are certain limits for liabilities that apply under OPA, potential limits on liability do not apply if the spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction, or operating regulation or if a party fails to report a spill or to cooperate fully in the cleanup. OPA imposes ongoing requirements on parties responsible for an oil spill, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs.

CERCLA, or "Superfund", imposes joint and several liability, without regard to fault, for the release of a "hazardous substance" into the environment, on responsible persons including the current and past owners or operators of the site where the release occurred, and companies that disposed or arranged for the transport or disposal of the hazardous substance. Under CERCLA and analogous California laws, responsible persons may be liable for cleanup costs, natural resource damages, and the costs of certain health studies. In addition, third parties may file claims for personal injury, property damage and other losses allegedly caused by the hazardous substances released into the environment. Although petroleum and crude oil fractions are not considered hazardous substances, in the course of our operations, we may use materials that, if released, may be treated as hazardous substances under CERCLA. Thus, governmental agencies or third parties may seek to hold us responsible for all or part of the costs to clean up sites at which such hazardous substances have been deposited.

RCRA and analogous California laws regulate the generation, transportation, treatment, storage, disposal, and cleanup of "hazardous wastes" and the disposal of non-hazardous wastes. Drilling fluids, produced waters, and other wastes associated with the exploration or production of crude oil, natural gas,

or geothermal energy constitute "solid wastes," which are subject to less stringent provisions than hazardous wastes. RCRA and California law also regulate Naturally Occurring Radioactive Materials ("NORM") generated in operations. Legislation or regulations have been proposed that could reclassify certain oil and natural gas exploration and production wastes as hazardous wastes, which would subject the reclassified wastes to more stringent handling, disposal and cleanup requirements. Such legislation, if enacted, could affect our operating costs.

Prior owners may have commenced exploration and production operations on some of our owned or leased property. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other materials or wastes may have been released or discharged at the properties owned or leased by us, or at other locations where such materials or wastes may have been taken for disposal. In addition, a portion of these sites may have been operated by third parties whose waste management and disposal practices were not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove or remediate contamination (potentially including waste disposed of or groundwater contamination caused by prior owners or operators), or to perform plugging or closure operations to prevent future contamination.

Hydraulic fracturing, acid matrix stimulation and similar techniques are important and common practices we use to stimulate production of oil and gas. Hydraulic fracturing involves the injection of water, sand and trace chemicals under pressure into underground oil and gas bearing rock formations to create or enlarge fractures and stimulate the flow of oil and gas into the oil and gas production well. Acid matrix stimulation involves the injection of a low pH solution designed to dissolve the sediments and mud solids that inhibit the permeability of the oil and gas bearing rock. Although these stimulation techniques have been regulated by DOGGR and safely utilized in California for decades, numerous federal and state agencies and certain local governments seek to further regulate them.

In February 2014, the EPA asserted regulatory authority over hydraulic fracturing involving diesel additives under the SDWA's Underground Injection Control ("UIC") Program, and requested comments in May 2014 on a proposal to require disclosure of chemical ingredients in hydraulic fracturing fluids under the Toxic Substances Control Act. In May 2013, the Bureau of Land Management proposed rules governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used, confirmation that wells used in hydraulic fracturing operations meet defined construction standards, and development of plans for managing water that flows back to the surface. In addition, studies by EPA and other federal agencies are underway that focus on environmental aspects of hydraulic fracturing activities, with draft reports expected for public comment and peer review in late 2014. These studies could spur further regulation. Additional regulations adopted at the federal level could result in permitting delays and cost increases.

At the state level, California adopted SB 4 in 2013, mandating additional, comprehensive regulation of well stimulation operations. The law requires, among other things, notification to property owners and tenants in the vicinity of well stimulation operations at least thirty days before the operations start, groundwater testing of an existing well if requested by such owners or tenants, implementation of water management and groundwater monitoring plans and the adoption of new regulations in 2015 governing well and casing construction and additional disclosure of well stimulation fluid constituents. In December 2013, the California Department of Conservation issued interim regulations to implement SB 4 that are currently in effect. The interim rules require approval of Well Stimulation Treatment Notices before starting stimulation treatment, disclosure of the fluids used and implementation of groundwater monitoring and water management plans. They also govern resident notifications, storage and handling of fluids and well integrity.

In April 2014, a California Senate committee proposed legislation that would indefinitely ban hydraulic fracturing and other stimulation activity until the state examines potential environmental effects. In addition, some local governments have proposed or adopted ordinances within their jurisdictions that purport to regulate drilling activities in general, or stimulation and completion activities in particular, or to ban such activities outright. None of the adopted local ordinances is expected to materially impact our current or expected future operations. If new or more stringent federal, state, or local restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs, experience delays or curtailment of our exploration or production activities and potentially be precluded from drilling wells.

The SDWA, the UIC Program and comparable California programs regulate the disposal, treatment, or release of water produced or used during oil and gas development and the drilling and operation of water disposal wells and fluid injection wells to enhance recovery of hydrocarbons. Permits are required to drill wells for water disposal or for fluid injection in EOR, and casing integrity must be periodically monitored to ensure the casing is adequate to prevent fluids from migrating outside of targeted zones. Non-compliance with regulations or groundwater contamination by oil and natural gas drilling operations may result in fines, penalties, and remediation costs, among other enforcement mechanisms under the SDWA and analogous California laws. In addition, landowners and other parties may assert claims for personal injury, alternative water supplies, property damage and other claims. These regulations and attendant liabilities may increase operating costs for some facilities.

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act ("NEPA"). NEPA requires federal agencies, including the Department of Interior and its Bureau of Land Management, to evaluate major agency actions that may significantly impact the environment. Some of our exploration and production activities occur on federal leases. NEPA may require the preparation of Environmental Assessments and more detailed Environmental Impact Statements which may be made available for public review and comment. This process may delay permitting and development of projects, increase costs, and in certain instances could result in the cancellation of existing federal leases.

Like NEPA, the California Environmental Quality Act ("CEQA") requires consideration of potential significant environmental impacts of any project proposed for agency approval. CEQA requires the responsible governmental agency to prepare an Environmental Impact Report ("EIR") that is made available for public comment. The responsible agency also is required to impose measures to mitigate all significant impacts of the proposed action or make a finding of considerations that override the imposition of identified mitigation measures. The party requesting agency action must pay EIR preparation and defense costs. The CEQA process may impose additional delays and expense on the process of obtaining new permits and permit renewals.

Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the federal Endangered Species Act ("ESA"), the California ESA ("CESA"), the Migratory Bird Treaty Act ("MBTA"), and the CWA. The U.S. Fish and Wildlife Service and the California Department of Fish and Game may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands and could delay or prohibit oil and gas development. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or

that may attract migratory birds, we believe that we are in substantial compliance with the ESA, CESA, MBTA and similar statutes, and we are not aware of any proposed species listings that will materially affect our operations. However, there could be new designations of previously unidentified endangered or threatened species, or critical or suitable habitat that would affect our operations.

Federal, state, and local laws and regulations provide detailed requirements for the abandonment of wells, the closure or decommissioning of production and transportation facilities and the environmental restoration of sites where operations have ceased. DOGGR is the principal state agency responsible for regulating the abandonment of wells and associated facilities in California. These regulations can impose significant costs on us related to (i) plugging, abandonment and restoration of facilities; (ii) cleanup costs and compensation for property damage due to releases or discharges; and (iii) penalties imposed for releases or non-compliance with applicable laws and regulations. As is customary in the oil and natural gas industry, we typically have contractually assumed, and may assume in the future, certain obligations relating to plugging and abandonment, cleanup, and other environmental costs in connection with our acquisition of operating interests in oil and gas fields, and these costs can be significant.

A number of federal, state, and regional efforts have emerged that seek to track or reduce emissions of GHGs. EPA has adopted regulations that restrict GHG emissions under existing provisions of the CAA and rules requiring certain operations, including onshore and offshore oil and natural gas production facilities, to monitor and report GHG emissions on an annual basis.

In 2006, California adopted AB 32, which established a statewide "cap-and-trade" program for GHG emissions. The program, which commenced in 2012, sets statewide maximum limits on total GHG emissions and requires the oil and natural gas extraction sector to report GHG emissions. Under the program, the cap will decline annually through 2020. We are required to obtain allowances or qualifying offset credits for each metric ton of GHGs that we emit. The state grants a portion of the allowance, but we must make up any shortfall by purchasing additional allowances either from the state or a third party. The availability of allowances will decline over time, and the cost to acquire such allowances may increase. The cap-and-trade program currently expires in 2020, though pending legislation seeks to extend the program to 2050.

The California cap-and-trade program is scheduled to incorporate transportation fuels beginning in 2015. As planned, petroleum refiners would be responsible for retiring allowances equivalent to the volume of transportation fuels they market in California. CARB also imposed a "low carbon fuels" standard, which requires refiners to reduce the carbon content of fuels they market in California by 10% by 2020. These programs may reduce demand for our products or require further controls on, or modifications to, our operations. Federal and California subsidies and tax incentives for the development and construction of alternative energy-fueled power generation and transportation also may reduce demand for our products and services.

If we are unable to recover or pass through a significant portion of our costs related to complying with climate change regulation, it could materially affect our operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy.

The federal OSHA and analogous California laws regulate the protection of the safety and health of workers. The California Department of Industrial Relations' Division of Occupational Safety and Health

("Cal/OSHA") requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees, state and local government authorities, and the public. Cal/OSHA has adopted and enforces Petroleum Safety Orders that require safety programs, and protective measures in our operations. Failure to comply with Cal/OSHA requirements can lead to the imposition of administrative, civil and/or criminal penalties as well as injunctive relief.

The sales prices of oil, NGLs and natural gas are not presently regulated, but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

Interstate transportation rates for oil, NGLs and other products are regulated by The Federal Energy Regulatory Commission ("FERC"). The price we receive from the sale of oil, natural gas and NGLs is affected by the cost of transporting those products to market. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Under the Energy Policy Act of 2005 ("EP Act 2005"), the FERC possesses regulatory oversight over natural gas markets to prevent market manipulation. The Federal Trade Commission ("FTC") has similar regulatory oversight of oil markets to prevent market manipulation. The Commodity Futures Trading Commission ("CFTC") also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. We are required to observe these anti-market manipulation laws and related regulations enforced by the FERC, the FTC, and/or the CFTC when we engage in physical purchase and sales or gathering of oil, NGLs and natural gas and when we engage in related hedging activity. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

The FERC has issued market transparency rules for the natural gas that may affect some our operations. The FERC issued a final rule in 2007, as amended by subsequent orders on rehearing ("Order 704"), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas, including natural gas producers, gatherers, processors and marketers, to report on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. The FERC has issued a Notice of Inquiry in Docket No. RM13-1-000 seeking comments from the industry regarding whether it should require more detailed information from sellers of natural gas. It is unclear what action, if any, will result and whether our reporting burden will increase or decrease.

Section 1(b) of the federal Natural Gas Act ("NGA") exempts natural gas gathering facilities from the jurisdiction of the FERC. We own certain natural gas pipelines that we believe meet the traditional tests that FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. The

distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, ongoing litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts, or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, "nondiscriminatory take" requirements and in some instances complaint-based rate regulation. Our gathering operations are also subject to state statutes designed to prohibit discrimination favoring producers or sources of supply. The regulations may restrict those with whom we contract to gather natural gas. In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner materially differently than other companies in our areas of operation.

The FERC regulates the sale of electricity at wholesale and the transmission of electricity under the Federal Power Act. The FERC's jurisdiction includes, among other things, authority over the rates, charges and other terms for the sale of electricity at wholesale by public utilities and for transmission services. In most cases, the FERC does not set rates for the sale of electricity at wholesale by generating companies (such as our subsidiary) that qualify for market-based rate authority, enabling companies to negotiate rates based on market conditions. In order to be eligible for market-based rate authority, and to maintain exemptions from certain FERC regulations, our subsidiary must request market based rate authorization from the FERC. With respect to its regulation of the transmission of electricity, the FERC requires transmission providers to provide open access transmission services, which supports the development of competitive power markets by assuring non-discriminatory access of non-utility generators to the transmission grid.

We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration ("PHMSA") of the Department of Transportation ("DOT"), pursuant to the Natural Gas Pipeline Safety Act of 1968 ("NGPSA") and the Pipeline Safety Improvement Act of 2002 ("PSIA"). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in "high consequence areas," such as high population areas, areas with sensitive environmental receptors and commercially navigable waterways. In addition, PHMSA has authorized the California State Fire Marshal and California Public Utilities Commission to enforce federal intrastate pipeline regulations and inspection requirements in California.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the Pipeline Safety Act, expanded the DOT's authority under the PSIA and requires the DOT to evaluate whether integrity management programs should be expanded beyond high consequence areas, authorizes the DOT to promulgate regulations requiring the use of automatic and remote-controlled shut-off valves for new or replaced pipelines, and requires the DOT to promulgate regulations requiring the use of excess flow values where feasible. Our natural gas pipelines have continuous inspection and compliance programs designed to keep facilities in compliance with pipeline safety requirements. Although we do not believe that any regulatory changes will affect us in a way that materially differs from the way they will affect our competitors, any new or amended pipeline safety regulations at the federal or state level may require us to incur additional capital expenditures and may increase our operating costs.

As of December 31, 2013, we had approximately 1,600 California employees. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. Approximately 86 of our employees are represented by labor unions. We have not experienced any strikes or work stoppages. We utilize the services of independent contractors to perform various field and other services.

We are party to various legal proceedings and claims in the ordinary course of our business. On July 23, 2013, the CARB asserted a claim against an Occidental subsidiary regarding reporting and emissions from four pieces of equipment at a facility in Long Beach, California. In May 2014, the subsidiary reached a settlement in principle to pay CARB a penalty of approximately $254,000 without admitting liability. We believe the other various legal proceedings and claims we are subject to in the ordinary course of our business will not have a material adverse effect on our consolidated or combined financial position, results of operations or liquidity.

We are in the process of identifying the individuals who will serve as executive officers following the distribution. These executive officers will be appointed prior to the distribution, and we will include information concerning these executive officers in an amendment to this information statement.

We are in the process of identifying the individuals who will serve as members of our board of directors following the distribution, and we will provide information regarding these individuals in an amendment to this information statement.

We currently expect that, upon the completion of the separation, our board of directors will consist of members, a majority of whom we expect to satisfy the independence standards established by the Sarbanes-Oxley Act of 2002 and the applicable rules of the SEC and the NYSE.

Upon completion of the spin-off, our board of directors will have the following committees:

Our audit committee will be composed of at least one director and a majority of independent directors. The Audit Committee will meet separately with representatives of our independent auditors, our internal audit personnel and representatives of senior management in performing its functions. The Audit Committee will review the general scope of audit coverage, the fees charged by the independent auditors, matters relating to internal control systems and other matters related to accounting and reporting functions. The board of directors is expected to determine that all of the members of the Audit Committee are financially literate and have accounting or related financial management expertise, each as required by the applicable NYSE listing standards. The board of directors is also expected to determine that at least one member of the Audit Committee will qualify as audit committee financial experts under the applicable rules of the Exchange Act.

Our compensation committee will be composed of at least one director and a majority of independent directors. The Compensation Committee will be responsible for (i) making compensation recommendations to the board of directors for our chief executive officer and other executive officers, (ii) overseeing and approving compensation and employee benefit policies and (iii) reviewing and discussing with our management the Compensation Discussion and Analysis and related disclosure included in our annual proxy statement.

Our nominating and corporate governance committee will be composed of at least one director and a majority of independent directors. The Nominating and Corporate Governance Committee will make proposals to the board of directors for candidates to be nominated by the board of directors to fill vacancies or for new directorship positions, if any, which may be created from time to time. The Nominating and Corporate Governance Committee will also develop and recommend a set of corporate governance guidelines to our board of directors and oversee evaluation of our board and management.

To qualify as "independent" under the NYSE listing standards, a director must meet objective criteria set forth in the NYSE listing standards, and the board of directors must affirmatively determine that the director has no material relationship with us (either directly or as a partner, stockholder or officer of an organization that has a relationship with us) that would interfere with his or her exercise of independent judgment in carrying out his or her responsibilities as a director. The NYSE independence criteria include that the director not be our employee and not have engaged in various types of business dealings with us.

The board of directors will review all direct or indirect business relationships between each director (including his or her immediate family) and us, as well as each director's relationships with charitable organizations, to assess director independence as defined in the listing standards of the NYSE.

Upon completion of the spin-off, our board of directors will adopt corporate governance policies to help ensure that the board of directors has the necessary authority and practices in place to make decisions that are independent from management, that the board of directors adequately performs its function as the overseer of management and to help ensure that the interests of the board of directors and management are aligned with the interests of the stockholders.

Our business ethics and corporate policies will require that all our directors, officers and employees act ethically in conducting company business.

Substantially all of our employees will be required to complete online training on a regular basis, which includes a review of business ethics and corporate policies and an acknowledgement that the employee has read and understands the policies.

During the fiscal year ended December 31, 2013 and the three months ended March 31, 2014, the California business was operated by subsidiaries of Occidental and not through an independent company and therefore did not have a compensation committee or any other committee serving a similar function. Decisions as to the compensation of those who will serve as our executive officers will be made initially by Occidental. See "Executive Compensation—Compensation Discussion and Analysis" included elsewhere in this information statement.

The persons who we expect will be our named executive officers as of the distribution date have not yet been determined and will be included in a subsequent amendment. For purposes of the Compensation Discussion and Analysis, we refer to them collectively as our "named executive officers." Our expectation is that, prior to the separation, most (if not all) of our named executive officers will have been employed by Occidental or its subsidiaries; therefore, the compensation information provided for 2013 will reflect compensation earned at Occidental or its subsidiaries and the design and objectives of the executive compensation programs in place prior to the spin-off.

Compensation decisions for our named executive officers prior to the spin-off will be made by Occidental. To the extent such persons are executive officers of Occidental, the decisions will be made by the Compensation Committee of the board of directors of Occidental (the "Occidental Compensation Committee"), which is composed entirely of independent directors. Executive compensation decisions following the spin-off will generally be made by the Compensation Committee of CRC.

Because we are currently part of Occidental and not an independent company, our Compensation Committee has not yet been formed. This Compensation Discussion and Analysis discusses Occidental's historical compensation practices with respect to its executive officers. Initially, we anticipate that our compensation practices will reflect in some ways those practices employed at Occidental. However, given the differences between Occidental and us, we expect that the compensation practices ultimately approved by our Compensation Committee and Board of Directors will be designed to support our strategies and may differ in many ways from Occidental's practices outlined below. Information regarding our compensation programs, to the extent determined, will be included in subsequent amendments to this information statement.

The Occidental Compensation Committee measures executive performance by evaluating both long-term performance of the company and the consistent achievement of short-term financial goals. This approach is intended to link executive compensation to company performance and help maximize value creation for stockholders. The Occidental Compensation Committee developed a compensation program designed not only to be consistent with industry practice, but also to attract and retain outstanding

executives, and to provide incentives to reward them for superior performance that supports Occidental's long-term strategic objectives.

In 2013, the Occidental Compensation Committee reviewed the peer company group used by Occidental in 2012 to ensure continued comparability to Occidental. The considerations taken into account, as a whole, were:

Within the oil and gas industry, Occidental has a unique combination of revenue, market capitalization and proportion of production and reserves attributable to oil. Investors take this into account when making investment choices in the energy industry and Occidental competes for these investor dollars with companies of varying revenue and market capitalization levels, including companies with much larger levels. Occidental's level of investment analyst coverage is comparable to many of the peer companies. Occidental competes for talent, projects and acquisitions worldwide against companies with both significantly larger and smaller levels of revenue and market capitalization and very different oil production profiles. This was taken into consideration in formulating an appropriate peer company group for executive compensation purposes.

The peer group does not include companies primarily in energy-related businesses such as (i) refining, (ii) midstream (transportation, storage and logistics) and marketing, or (iii) the sale and distribution of products because these companies have different investor bases, do not compete with Occidental for the same projects, and typically do not compete with Occidental for the same talent. Additionally, publicly traded limited partnerships are not included in the group because they have significantly different investor bases, corporate structures and compensation structures.

The Occidental Compensation Committee's review of the 2012 peer group and the factors discussed above resulted in replacing Royal Dutch Shell plc with Marathon Oil Corporation, whose market capitalization, revenues, lines of business and geographical presence are more comparable to Occidental's. In addition to Occidental, the peer companies (collectively, the "peer group"), effective beginning with Occidental's 2013 long-term incentive awards, are:

The Occidental Compensation Committee designated this group of companies as the peer group for purposes of the total shareholder return ("TSR") award granted to Occidental's executive officers in 2013.

The Occidental Compensation Committee also reviewed information regarding the oil and gas industry and the peer group companies' executive compensation practices, programs and data that was publicly disclosed or available. Additionally, the Occidental Compensation Committee reviewed and considered broad-based compensation surveys and related materials. The purpose of reviewing this information was to evaluate and understand how Occidental's executive compensation program compares within the oil and gas industry, particularly with respect to types of awards, performance metrics for awards and reported levels of compensation. The information was not used to establish compensation benchmarks and Occidental does not benchmark executive compensation to a specific percentile within the peer group.

The Occidental Compensation Committee believes that overall executive compensation should include elements that reward executives for consistent performance of basic job requirements and achievement of certain short-term goals which, over time, contribute to long-term growth of stockholder value. Consistent with the Occidental Compensation Committee's goal of emphasizing long-term compensation, salary and other annual compensation generally represent the smaller portion of the 2013 compensation packages of Occidental's executive officers. Short-term compensation for Occidental's executive officers generally includes base salary and other compensation, plus an award under Occidental's Executive Incentive Compensation Plan. Certain other compensation and benefits that apply to senior executives of Occidental are described under "Other Occidental Compensation and Benefits" beginning on page 131.

The Annual Incentive is composed of a Non-Equity Incentive portion (60% of target value) and a Bonus portion (40% of target value). The Occidental Compensation Committee sets target amounts for each senior executive based on a review of commercially available compensation surveys and other publicly available information. In setting targets for each executive, the Occidental Compensation Committee considers each executive's ability to influence Occidental's performance during the one-year performance period.

Occidental Non-Equity Incentive Award (Performance-Based Portion). The Non-Equity Incentive portion (60% of target value) is a performance-based cash award that is based on Occidental's performance during the year as measured against Occidental's EPS targets established in the first quarter of the year. For purposes of the Performance-Based Portion of the Annual Incentive, Core, Occidental's Basic Earnings Per Share ("EPS") is computed by excluding the "Significant Items Affecting Earnings" from Occidental's Net Income and dividing this amount by the weighted-average basic shares of Occidental outstanding. For a discussion of "Significant Items Affecting Earnings," see "Management Discussion and Analysis of Financial Condition and Results of Operations" on page 25 of Occidental's Annual Report on Form 10-K for the year ended December 31, 2013 ("Form 10-K") and, for Basic Earnings Per Common Share see page 44 of Occidental's Form 10-K. Occidental's EPS was chosen as the financial target for all of Occidental's corporate executives because it directly impacts stockholder value, is a readily determinable measure of annual performance and rewards the executives for current operating performance. In early 2013, the Occidental Compensation Committee set the 2013 EPS targets with $7.00 per share as the target, $6.26 per share as the threshold for any payout, and $7.75 per share resulting in the maximum payout of 200% of the target value. The payout percentage for EPS values from $6.25 to $7.75 is based on a linear interpolation of values from 0% to 200%. These targets were chosen based on consideration of management's financial models, as well as a review of analysts' estimates of Occidental's earnings per share for 2013 and then-current estimates of global oil prices for 2013. The EPS for 2013 as certified by Occidental's Compensation Committee was $6.95, which resulted in a payout percentage of 93% for all executives participating in this bonus program.

Occidental Bonus Award (Discretionary Portion). The Bonus portion (40% of target value) is a discretionary cash award designed to link incentive compensation directly to the performance of the particular executive. Payout is determined by the Occidental Compensation Committee's subjective assessment of an executive's handling of certain key performance areas within such executive's area of responsibility, as well as the executive's response to unanticipated challenges during the year. Key performance areas assessed by the Occidental Compensation Committee include:

This portion of Occidental's compensation program consists of performance-based awards that provide incentives for achieving results consistent with the goal of sustained growth in stockholder value. The Occidental Compensation Committee believes that long-term compensation should represent the largest portion of an executive's total compensation package and that the levels of payouts should reflect the company's performance levels. During the process of determining the values of each of Occidental's named executive officer's compensation package, the Occidental Compensation Committee evaluated many factors, including the following:

This portion of the executive compensation program includes three types of awards: (i) an incentive based on either return on capital employed ("ROCE") (for executives with primarily corporate level responsibilities) or two return on asset ("ROA") awards (one for the oil & gas division as a whole and the other for the regional oil & gas division for which the executive is responsible); (ii) performance incentives based on TSR; and (iii) performance-based restricted stock incentives ("RSI"). The Occidental Compensation Committee awarded long-term incentives to Occidental's named executive officers in the following percentages: 40% to either one ROCE award or to two ROA awards, 30% to the TSR award and 30% to the RSI award.

The table following this paragraph and subsequent descriptions summarize the key features of the long-term incentive components of the 2013 compensation program for Occidental's named executive officers. Effective as of the spin-off, we currently expect that the awards described below that are held by our named executive officers will be converted into awards with respect to shares of our common stock in the manner described below under the heading "—Effects of Spin-off on Outstanding Executive and Other Compensation Awards—Equity Based and other Long-Term Incentive Awards."

Occidental Return on Capital Employed Incentive Award. This award is a new award implemented in 2013 to ensure a high level of executive focus on the key objective of ensuring efficient use of capital. This award is denominated in performance shares, each of which is equal to one share of Occidental's common stock. Key terms of the award are set forth in the table on page 128. At the end of the performance period, dividend equivalents will be paid with respect to the performance share level achieved in an amount equal to the dividends declared per share of Occidental common stock during the performance period. As described below, in connection with the spin-off, we expect that these awards that are held by our named executive officers will be converted into time-vested restricted shares of our common stock that will no longer be subject to performance conditions.

Occidental Return on Assets Incentive Awards. These new awards were implemented in 2013 to reward operating unit executives for performance within their direct areas of responsibility and influence. These awards are denominated in performance shares, each of which is equal to one share of Occidental common stock. Key terms of the awards are set forth in the table on page 128. At the end of the performance period, dividend equivalents will be paid with respect to the performance share level achieved in an amount equal to the dividends declared per share of Occidental common stock during the performance period. As described below, in connection with the spin-off, we expect that these awards that are held by our named executive officers will be converted into time-vested restricted shares of our common stock that will no longer be subject to performance conditions.

Occidental Total Shareholder Return Incentive Award. The Occidental Compensation Committee believes that the comparison of Occidental's TSR over a specified period of time to peer companies' returns over that same period is an objective external measure of the company's effectiveness in translating its results into stockholder returns. TSR is the change in price of a share of Occidental common stock plus reinvested dividends, over a specified period of time, and is an indicator of management's achievement of long-term growth in stockholder value. TSR awards use both comparative peer company and S&P 500 Index TSRs to determine payout amounts and are not based on internal performance metrics. The TSR award also takes into account whether TSR is negative or positive. The TSR awards were designed to:

The TSR awards are denominated in performance share units, each of which is equivalent to one share of Occidental common stock. The percentage of such number of performance share units that will be payable at the end of the three-year performance period, which runs from July 1, 2013 through June 30, 2016, will depend on Occidental's TSR performance as described in the table on page 128. Cumulative dividend equivalents will be paid at the end of the three-year performance period and will be paid only on performance share units earned. As described below, in connection with the spin-off, we expect that these awards that are held by our named executive officers will be converted into time-vested restricted shares of our common stock that will no longer be subject to performance conditions.

Occidental Restricted Stock Incentive Award. Consistent with the executive compensation programs of a majority of the peer group companies, the Occidental Compensation Committee selected Restricted Stock Incentive awards (RSI awards) as a component of executive long-term incentive compensation. The RSI award is a grant of shares of Occidental's common stock and key terms of the award are set forth in the table on page 128. The Occidental Compensation Committee increased the performance goal from the

2012 level of $10 billion in cumulative net income to $12 billion in cumulative net income in order to make the achievement of the goal more challenging. Dividends will be paid on the shares from the grant date. As described below, in connection with the spin-off, we expect that these awards that are held by our named executive officers will be converted into time-vested restricted shares of our common stock that will no longer be subject to performance conditions.

The Occidental Compensation Committee sets compensation for Occidental's senior executives. Occidental's chief executive officer is involved in making recommendations relating to compensation payable to senior executives other than himself.

In 2013, Occidental participated in compensation surveys conducted by independent compensation consultants in order to better understand general external compensation practices, including executive compensation. From time to time, Occidental, through its executive compensation department or the Occidental Compensation Committee, engages a consultant to provide advice on specific compensation issues. The Occidental Board's policy on retention of independent compensation consultants, adopted in 2009, is set forth in Occidental's corporate governance policies at www.oxy.com. In 2013, the Occidental Compensation Committee engaged Pay Governance LLC as compensation consultants to advise and recommend on the design of long-term incentives for executives and on the design of director compensation programs.

In addition, Occidental has also retained Pay Governance LLC to advise and recommend on the treatment of Occidental compensation awards held by our senior officers in connection with the spin-off and, as described in greater detail below, with respect to the design of CRC's ongoing executive compensation programs.

The Occidental Compensation Committee reviewed the independence of Pay Governance LLC under the Securities and Exchange Commission and New York Stock Exchange Listed Company Manual Standards and found it to be independent and without conflicts of interest.

Although the executive compensation program has a high percentage of pay that is performance-based, the Occidental Compensation Committee believes its program does not encourage unnecessary or excessive risk-taking. The Occidental Compensation Committee believes that the program, through a balanced set of performance metrics, enhances business performance by encouraging appropriate levels of risk-taking by executives. The Occidental Compensation Committee believes that any potential risk of the executive compensation program influencing behavior that could be inconsistent with the overall interests of Occidental and its stockholders is mitigated by several factors:

The following paragraphs provide brief descriptions of some additional Occidental compensation and benefits programs. Our compensation and benefits programs that will be in effect after the spin-off are still being developed and may differ from Occidental's programs described below. Information concerning our compensation programs, to the extent developed, will be included in subsequent amendments to this information statement under the section entitled "—Our Compensation Programs."

Occidental does not have a defined benefit pension program that provides salaried employees, other than a limited group of acquired employees, a fixed monthly retirement payment.

All salaried employees on the U.S. dollar payroll are eligible to participate in one or more tax-qualified, defined contribution plans. The defined contribution retirement plan provides for periodic contributions by Occidental based on annual cash compensation and age, up to certain levels pursuant to Internal Revenue Service (IRS) regulations. Occidental generally matches employee contributions with Occidental common stock on a dollar-for-dollar basis, in an amount up to 6% of the employee's base salary.

Substantially all employees whose participation in Occidental's qualified defined contribution retirement and savings plans is limited by applicable tax laws are eligible to participate in Occidental's nonqualified defined contribution retirement plan, which provides additional retirement benefits outside of those limitations.

Annual plan allocations for each participant restore the amounts that would have accrued for salary, bonus and non-equity incentive compensation under the qualified plans, but for the tax law limitations. Account balances are fully vested after three years of service and are payable following separation from service, or upon attainment of a specified age elected by the participant, as described below.

Interest on nonqualified retirement plan accounts is allocated monthly to each participant's account, based on the opening balance of the account in each monthly processing period. The amount of interest earnings is calculated using a rate equal to the five-year U.S. Treasury Note rate on the last business day of the processing month plus 2%, converted to a monthly allocation factor.

In order to provide greater financial planning flexibility to participants while not increasing costs under the plan, the Supplemental Retirement Plan II (SRP II) allows in-service distribution of a participant's account at a specified age, but not earlier than age 60, as elected by the participant when initially participating in the plan.

Occidental also sponsors a nonqualified deferred compensation plan referred to as the Modified Deferred Compensation Plan (MDCP), which provides for elective deferrals of compensation. Under the MDCP, the maximum amount that may be deferred for any one year is limited to $75,000. A participant's overall plan balance must be less than $1 million at the end of any given year to enable a participant to defer compensation for the subsequent year. Deferred amounts earn interest at a rate equal to the five-year U.S. Treasury Note rate plus 2%, except for amounts deferred prior to 1994, which will continue to earn interest at a minimum interest rate of 8%.

Personal security services, including home detection and alarm systems and personal security guards, are provided to certain of Occidental's senior executives to address perceived risks, at allocated costs based on actual charges and presented to the Occidental Compensation Committee.

A select group of Occidental's executive officers are eligible to receive reimbursement for financial planning and investment advice, including legal advice related to tax and financial matters. Eligible Occidental executives are required to have their personal tax returns prepared by a tax professional qualified to practice before the Internal Revenue Service in order to ensure compliance with applicable tax laws.

Occidental offers a variety of health coverage options to all employees. Occidental's senior executives participate in these plans on the same terms as other employees. In addition, for all employees above a certain job level, Occidental will pay for an annual physical examination. Occidental provides all salaried employees with life insurance equal to twice the employee's base salary. For certain senior employees, Occidental increases that insurance coverage to three times base salary. Occidental also provides senior executives with excess liability insurance coverage.

In connection with the spin-off, we and Occidental will enter into an Employee Matters Agreement which will address, among other things, the treatment of certain outstanding Occidental executive and other compensation awards in connection with the spin-off. The spin-off is not expected to result in a "change in control" or similar transaction under any of Occidental's executive compensation programs.

Below is a brief summary of what is currently anticipated to occur with respect to outstanding Occidental executive and other compensation awards that may be held by our executive officers upon the spin-off.

We currently expect that effective as of the spin-off, each Occidental equity-based or other long-term incentive award held by an individual who will be employed by us following the spin-off will be converted

into an award with respect to shares of CRC common stock. Specifically, we currently expect that the following will occur:

In the event the spin-off occurs during 2014, we anticipate that our employees will receive a full 2014 annual incentive plan award under Occidental's annual incentive programs, which will be paid out based on Occidental's actual performance for 2014.

In the event the spin-off occurs during 2015, we anticipate that our employees will not be eligible to receive an award under Occidental's annual incentive programs for 2015, but instead would be eligible for a full-year award under our annual incentive program to be established in connection with the spin-off.

Effective as of the spin-off, our employees are expected to cease active participation in all other compensation and benefit plans sponsored by Occidental and its subsidiaries and commence participation in corresponding plans that we and our subsidiaries maintain, to the extent that we sponsor such plans.

Our compensation programs that will be in effect following the spin-off are still being developed and have not yet been finalized.

Occidental has retained Pay Governance LLC to assist in the design and implementation of our compensation programs to be in effect following the spin-off. Specifically, Pay Governance LLC is working with Occidental and us to develop a peer group for purposes of conducting market analyses and to determine the level and form of executive and broad-based compensation from and after the spin-off.

Additional detail regarding our post-spin-off compensation programs will be included in an amendment to this information statement, to the extent known at the time of such amendment.

Because our named executive officers have not yet been determined, this information statement does not include any tables relating to the compensation of our named executive officers during 2013. Such tables will be included in a subsequent amendment.

As of the date of this information statement, all outstanding shares of our common stock are owned beneficially and of record by Occidental. After the spin-off, Occidental will hold the Retained Securities for a maximum of two years. The following table sets forth information with respect to the anticipated beneficial ownership of our common stock by:

Except as otherwise noted below, we based the share amounts shown on each person's beneficial ownership of Occidental common stock on , 2014, and a distribution ratio of shares of our common stock for each share of Occidental common stock held by such person.

To the extent persons who are directors or executive officers or who are expected to serve as directors or executive officers upon completion of the spin-off own Occidental common stock at the record date of the spin-off, they will participate in the distribution on the same terms as other holders of Occidental common stock.

Immediately following the spin-off, we expect to have approximately stockholders of record, based on the number of registered stockholders of Occidental common stock on , 2014, and approximately million shares of our common stock outstanding. The actual number of shares of our common stock outstanding following the spin-off will be determined on , 2014, the record date. As of , 2014, Occidental had approximately stockholders of record and approximately million shares of Occidental common stock outstanding.

To our knowledge, except as indicated in the footnotes to this table or as provided by applicable community property laws, the persons named in the table have sole voting and investment power with respect to the shares of common stock indicated. Unless otherwise indicated, the address for each director and executive officer listed is: c/o California Resources Corporation, .

This section provides a summary description of agreements between Occidental and us relating to our restructuring transactions and our relationship with Occidental after the spin-off. This description of the agreements between Occidental and us is a summary and, with respect to each such agreement, is qualified by reference to the terms of the agreement, a form of each of which will be filed as an exhibit to the registration statement of which this information statement is a part. We encourage you to read the full text of these agreements. We will enter into these agreements with Occidental prior to the completion of the spin-off; accordingly, we will enter into these agreements with Occidental in the context of our relationship as a wholly-owned subsidiary of Occidental. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties.

The terms of the agreements described below have not yet been finalized. Changes, some of which may be material, may be made prior to our separation from Occidental, in Occidental's sole discretion. No changes may be made after the spin-off without our consent.

The Separation and Distribution Agreement will govern the terms of the separation of the California business from Occidental's other businesses. Generally, the Separation and Distribution Agreement will include the agreements of Occidental and us on the steps to be taken to complete the separation, including the assets and rights to be transferred, liabilities to be assumed or retained, contracts to be assigned and related matters. Subject to the receipt of required governmental and other consents and approvals, in order to accomplish the separation, the Separation and Distribution Agreement will provide for Occidental and us to transfer specified assets and liabilities between the two companies to separate the California business from Occidental's remaining businesses. As a result of this transfer, we will own all assets exclusively related to the California business, and certain other assets related to the California business specifically allocated to us. We will also be responsible for all liabilities to the extent relating to the California business. Occidental will retain all other assets and liabilities, including assets and liabilities related to discontinued businesses (other than those businesses that were a part of the California business prior to being discontinued). The Separation and Distribution Agreement will require Occidental and us to endeavor to obtain consents, approvals and amendments required to novate or assign the assets and liabilities that are to be transferred pursuant to the Separation and Distribution Agreement as soon as reasonably practicable.

Unless otherwise provided in the Separation and Distribution Agreement or any of the related ancillary agreements, all assets will be transferred on an "as is, where is" basis. Generally, if the transfer of any assets or liabilities requires a consent that will not be obtained before the distribution, or if any assets or liabilities are erroneously transferred or if any assets or liabilities are erroneously not transferred, each party will agree to hold the relevant assets or liabilities for the intended party's use and benefit (at the intended party's expense) until they can be transferred to the intended party.

The Separation and Distribution Agreement will also govern the treatment of all aspects relating to indemnification and insurance, and will generally provide for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of the remaining Occidental business with Occidental. The Separation and Distribution Agreement will also establish procedures for handling claims subject to indemnification and related matters. We and Occidental will also generally release each other from all claims arising prior to the spin-off other than claims arising under the transaction agreements, including the indemnification provisions described above.

The Separation and Distribution Agreement will specify those conditions that must be satisfied or waived by Occidental prior to the distribution. In addition, Occidental will have the right to determine the date and terms of the distribution, including payment by us of a special distribution of $ billion to

Occidental, and will have the right, at any time until completion of the distribution, to determine to abandon or modify the distribution and to terminate or modify the Separation and Distribution Agreement.

The Transition Services Agreement will set forth the terms on which Occidental will provide to us, and we will provide to Occidental, on a temporary basis, certain services or functions that the companies historically have shared. Transition services may include administrative, payroll, human resources, data processing, environmental health and safety, financial audit support, financial transaction support, marketing support and other support services, information technology systems and various other corporate services. We expect the agreement will provide for the provision of specified transition services, generally for a period of up to 12 months, with a possible extension of 6 months (an aggregate of 18 months), on a cost or a cost-plus basis.

The Tax Sharing Agreement will govern the respective rights, responsibilities, and obligations of Occidental and us with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and other matters regarding taxes. The Tax Sharing Agreement will remain in effect until the parties agree in writing to its termination; however, notwithstanding such termination, the Tax Sharing Agreement will remain in effect with respect to any payments or indemnification due for all taxable periods prior to such termination during which the agreement was in effect.

Occidental has requested a private letter ruling from the IRS substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates for federal income tax purposes. In addition, the spin-off is conditioned on Occidental's receipt of an opinion from its tax counsel, in form and substance acceptable to Occidental, that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes, and (ii) the spin-off qualifies as a tax-free transaction under Section 355 and/or Section 368(a)(1)(D) of the Code. The opinion will rely on the private letter ruling as to matters covered by the private letter ruling.

CRC will agree to certain restrictions that are intended to preserve the tax-free status of the contribution, distribution, and related transactions. After Occidental's initial distribution of more than 80% of CRC common stock and during the two-year period following Occidental's final disposition of the Retained Securities, these covenants will restrict CRC's ability to sell assets outside the ordinary course of business, to issue or sell its common stock or other securities (including securities convertible into its common stock), or to enter into any other corporate transaction that would cause CRC to undergo either a 50% or greater change in the ownership of its voting stock or a 50% or greater change in the ownership (measured by value) of all classes of its stock. CRC may take certain actions otherwise subject to these restrictions only if Occidental consents to the taking of such action or if CRC obtains, and provides to Occidental, a private letter ruling from the IRS and/or an opinion from an independent law firm or accounting firm, in either case, acceptable to Occidental in its sole discretion, to the effect that such action would not jeopardize the tax-free status of the contribution, distribution, or related transactions.

The Employee Matters Agreement will govern Occidental's and our compensation and employee benefit obligations with respect to the current and former employees of each company, and generally will allocate liabilities and responsibilities relating to employee compensation and benefit plans and programs. The Employee Matters Agreement will provide for the treatment of outstanding Occidental equity awards. The Employee Matters Agreement is also expected to set forth the general principles relating to employee matters, including with respect to the assignment of employees and the transfer of employees from Occidental to us, the assumption and retention of liabilities and related assets, expense reimbursements, workers' compensation, leaves of absence, employee service credits, the sharing of employee information and the duplication or acceleration of benefits.

The AMI Agreement will set forth the terms upon which Occidental may acquire an interest in and rights with respect to certain oil and gas properties (the "AMI Interests") in the United States (excluding California and federal waters offshore California) (the "AMI Area"). Pursuant to the terms of the AMI Agreement, for a period of one year after notice from us, Occidental may elect to exercise an option to acquire an interest in the AMI Interest. Upon exercise, Occidental will acquire an undivided % interest in the subject AMI Interest for consideration equal to the sum of (i) % of the net acquisition price paid by us for such AMI Interest and (ii) % of the drilling and/or operating costs paid by us (net of any reimbursements) in respect of such AMI Interests attributable to any periods after the date of our acquisition of such AMI Interests, and less (iii) % of the revenue attributable to such AMI Interests after the date of our acquisition of such AMI Interests, subject to certain limited exceptions. If applicable, in connection with the exercise of Occidental's option, we will resign as operator and vote for Occidental or its designee as the replacement operator. The term of the AMI Agreement will be five years.

Pursuant to the Confidentiality and Trade Secret Protection Agreement, we will agree to keep confidential and not misuse certain information we learned about Occidental prior to the spin-off. In order to preserve Occidental's trade secrets and confidential information and to protect the goodwill transferred to us in connection with the spin-off, among other things, CRC and Occidental will agree (i) not to hire the other party's employees for a period of one year following the completion of the spin-off and (ii) not to solicit the other party's employees for an additional four years following the expiration of the non-hire restrictions.

The Intellectual Property License Agreement will set forth the terms on which Occidental, on behalf of itself and its affiliates, will license certain intellectual property and documentation to us, including software owned by Occidental and its affiliates. We will have the right to create derivative works of the software and use it for our internal business purposes.

Prior to the distribution, we and Occidental will enter into a Stockholder's and Registration Rights Agreement pursuant to which we will agree that, upon the request of Occidental, we will use our best efforts to effect the registration under applicable federal and state securities laws of the disposition of shares of our common stock retained by Occidental after the distribution and to cooperate with Occidental to facilitate its disposition of the Retained Securities through one or more exchanges for Occidental common stock. In addition, Occidental will grant us a proxy to vote the shares of our common stock that Occidental retains immediately after the distribution in proportion to the votes cast by our other stockholders. This proxy, however, will be automatically revoked as to a particular share upon any transfer of such share from Occidental to a person other than Occidental, and neither the voting agreement nor the proxy will limit or prohibit any transfer.

In addition to the related party transactions described in "Arrangements Between Occidental and Our Company" above, this section discusses other transactions and relationships with related persons during the past three fiscal years. As a current subsidiary of Occidental, we engage in related party transactions with Occidental. Those transactions are described in more detail in the notes to the accompanying combined financial statements.

Substantially all of our marketing of oil, gas and NGLs has historically been transacted through Occidental's marketing subsidiaries. For the years ended December 31, 2013, 2012 and 2011, sales to Occidental's marketing subsidiaries accounted for approximately $4.2 billion, $4.0 billion and $3.9 billion of our net sales respectively. After the spin-off, we expect to market our products through a wholly-owned marketing subsidiary.

Policies and Procedures with Respect to Related Party Transactions and Conflicts of Interest

Prior to the spin-off, our board of directors will adopt policies restricting related party transactions. We will review all relationships and transactions in which we and our directors and executive officers or their immediate family members are participants to determine whether such persons have a direct or indirect material interest. Our Corporate Secretary's office will develop and implement procedures to obtain information from the directors and executive officers with respect to related party transactions. Determinations as to whether an executive officer or directors has a direct or indirect material interest and whether such an interest is permissible will be determined by the audit committee of our board of directors. Agreements that embody transactions that are material in amount or significance will be filed with the SEC as required, and the transactions will be disclosed in our proxy statement as required.

Our business ethics and corporate policies will prohibit significant conflicts of interest. Any waivers of these policies will require approval by a compliance officer, the corporate compliance committee or uninvolved members of the audit committee (in the case of conflicts of our executive officers or directors). Under the business ethics and corporate policies, conflicts of interest will occur when private or family interests interfere or compete with the interests of our Company.

We will have multiple processes for reporting conflicts of interests, including related party transactions. Under the business ethics and corporate policies, all our directors and employees will be required to report any known or apparent, actual or potential conflict of interest, or potential conflict of interest, to their supervisors, a compliance officer, the corporate compliance committee or the audit committee as appropriate. As part of any review, the following factors will generally be considered:

We also will have other policies and procedures to prevent conflicts of interest, including related person transactions. For example, the charter of our Nominating & Governance Committee will require

that committee members assess the independence of the non-management directors at least annually, including a requirement that it determine whether any such directors have a material relationship with us, either directly or indirectly, as defined therein and as further described above under "Management—Board of Directors—Director Independence."

Guidelines will be contained in our business ethics and corporate policies to establish restrictions with regard to corporate participation in the political system as imposed by law.

In connection with the separation, we expect to incur an aggregate of $ billion in new debt for which we will not retain any substantial amount of cash following the separation. We expect that this indebtedness may consist of long-term notes, term loans or borrowings under a revolving credit facility or a combination thereof.

In addition, we expect to that our revolving credit facility will be available for working capital and for general corporate purposes including issuance of letters of credit.

We will describe the terms and covenants of any notes to be issued, bank debt to be incurred or liquidity facilities to be entered into in an amendment to the registration statement of which this information statement is a part.

The following is a description of the material terms of our capital stock as provided in our amended and restated certificate of incorporation and amended and restated bylaws, as each is anticipated to be in effect upon the completion of the spin-off. The summaries and descriptions below do not purport to be complete statements of the relevant provisions of these documents. For a complete description, we refer you to, and the following summaries and descriptions are qualified in their entirety by reference to, our amended and restated certificate of incorporation and amended and restated bylaws, copies of which will be filed as exhibits to the registration statement of which this information statement forms a part.

Following completion of the spin-off, our authorized capital stock will consist of (i) shares of common stock, par value $0.01 per share, of which shares will be issued and outstanding based on the number of shares of Occidental's common stock expected to be outstanding as of the record date and (ii) shares of preferred stock, par value $0.01 per share, of which no shares will be issued and outstanding.

Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock are not entitled to vote on any amendment to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the DGCL. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably in proportion to the shares of common stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of the-spin off will be fully paid and non-assessable. The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets in proportion to the shares of common stock held by then that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any.

Our amended and restated certificate of incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion or exchange rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of our Amended and Restated Certificate of Incorporation, our Amended and Restated Bylaws and Delaware Law

Some provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws will contain provisions that could make acquisitions of us by means of a tender offer, a proxy contest or otherwise or removal of our incumbent officers and directors more difficult. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interests or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

We will be subject to Section 203 of the DGCL, which generally prohibits a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder (which is defined generally as a person owning 15% or more of a Delaware corporation's outstanding voting stock) or its affiliates or associates for a period of three years following the date that the stockholder became an interested stockholder, unless:

We may elect in the future to not be subject to the provisions of Section 203 of the DGCL.

Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

Provisions of our amended and restated certificate of incorporation and amended and restated bylaws, which will become effective following the spinoff, may delay or discourage transactions involving an actual or potential change in control or change in our management, or transactions that our stockholders might otherwise deem to be in their best interests or in our best interests, including transactions that might result in a premium over the market price for our shares. Therefore, these provisions could adversely affect the price of our common stock.

Among other things, upon the completion of the spin-off, our amended and restated certificate of incorporation and amended and restated bylaws will:

Our amended and restated certificate of incorporation will also provide that any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of and to have consented to this forum selection provision. However, it is possible that a court could find our forum selection provision to be inapplicable or unenforceable.

Our amended and restated certificate of incorporation limits the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our amended and restated certificate of incorporation and amended and restated bylaws also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated certificate of incorporation and amended and restated bylaws also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person's actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We may from time to time enter into indemnification agreements with our directors and officers. These agreements will typically require us to indemnify these individuals to the

fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision in our amended and restated certificate of incorporation and any indemnification agreements we enter into will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Upon our incorporation, we issued 1,000 shares of our common stock, par value $0.01 per share, to Occidental upon payment by Occidental of $10.00 pursuant to Section 4(2) of the Securities Act. We did not register the issuance of these shares under the Securities Act because such issuance did not constitute a public offering.

Following the distribution, all inquiries regarding our common stock should be directed to the following:

We have filed with the SEC a Registration Statement on Form 10 for our shares of common stock that Occidental stockholders will receive in the distribution. This information statement does not contain all of the information contained in the Form 10 and the exhibits to the Form 10. We have omitted some items in accordance with the rules and regulations of the SEC. For additional information relating to us and the spin-off, we refer you to the Form 10 and its exhibits, which are on file at the offices of the SEC. Statements contained in this information statement about the contents of any contract or other document referred to may not be complete, and in each instance, if we have filed the contract or document as an exhibit to the Form 10, we refer you to the copy of the contract or other documents so filed. We qualify each statement in all respects by the relevant reference.

You may inspect and copy the Form 10 and exhibits that we have filed with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the Public Reference Room. In addition, the SEC maintains an Internet site at www.sec.gov, from which you can electronically access the Form 10, including its exhibits.

We maintain an Internet site at www. .com. We do not incorporate our Internet site, or the information contained on that site or connected to that site, into the information statement or our Registration Statement on Form 10.

As a result of the distribution, we will be required to comply with the full informational requirements of the Exchange Act. We will fulfill those obligations with respect to these requirements by filing periodic reports and other information with the SEC.

We plan to make available free of charge on our website, all materials that we file electronically with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports and amendments to these reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC. You also can obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

You should rely only on the information contained in this information statement or to which we have referred you. We have not authorized any person to provide you with different information or to make any representation not contained in this information statement.


%Ro or vitrinite reflectance		A measurement of the maturity of organic matter with respect to whether it has generated hydrocarbons or could be an effective source rock.
100% commercial success rate		All wells were completed and produce in commercially viable quantities.
Basin		A large natural depression on the earth's surface in which sediments generally brought by water accumulate.
Bbl		One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
BBoe		One billion Boe.
Bcf		One billion cubic feet of natural gas.
Boe		One stock tank barrel of oil equivalent, using the ratio of six Mcf of natural gas to one barrel of crude oil.
BS		One barrel of steam, cold water equivalent.
Completion		The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.
Condensate		A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Conventional Reservoir		A reservoir in which buoyant forces keep hydrocarbons in place below a sealing caprock. Reservoir and fluid characteristics of conventional reservoirs typically permit oil or natural gas to flow readily into wellbores.
/d		Per day.
Development drilling or development wells		Drilling or wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Disposal well		A well utilized to dispose of excess produced fluids that are not reused in normal operations.
Economically Producible		A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.
EOR		Enhanced oil recovery.
Exploration activities		The initial phase of oil and natural gas operations that includes the generation of a prospect or play and the drilling of an exploration well.
Exploration well		Refers to a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Extension Well		A well drilled to extend the limits of a known reservoir.


Field		An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Formation		A layer of rock which has distinct characteristics that differs from nearby rock.
Gross acres or gross wells		The total acres or wells, as applicable, in which a working interest is owned.
Infill drilling		Drilling of an additional well or wells at less than existing spacing to more adequately drain a reservoir.
Injection well		A well in which water, gas or steam is injected, the primary objective typically being to maintain reservoir pressure and/or improve hydrocarbon recovery.
IOR		Improved oil recovery.
Maximum Efficiency Rate		The maximum sustainable daily oil or gas withdrawal rate from a reservoir which will permit economic development and depletion of that reservoir without detriment to ultimate recovery.
MBbl		One thousand barrels.
MBoe		One thousand Boe.
Mcf		One thousand cubic feet of natural gas. For the purposes of this report, this volume is stated at the legal pressure base of the state or area in which the reserves are located and at 60 degrees Fahrenheit.
mD		One millidarcy.
MMBbl		One million barrels.
MMBoe		One million Boe.
MMBtu		One million British thermal units. A British thermal unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
MMcf		One million cubic feet of natural gas. For the purposes of this report, this volume is stated at the legal pressure base of the state or area in which the reserves are located and at 60 degrees Fahrenheit.
Natural gas liquids or NGLs		Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
Net acres or net wells		The gross acres or wells, as applicable, multiplied by the working interests owned.
NYMEX		The New York Mercantile Exchange.
Oil		Crude oil or condensate.
Pay zone		A geological deposit in which oil and natural gas is found in commercial quantities.
Permeability		The ability, or measurement of a rock's ability, to transmit fluids.


Porosity		The total pore volume per unit volume of rock.
Primary Recovery		The first stage of hydrocarbon production, in which natural reservoir energy, such as gasdrive, waterdrive or gravity drainage, displaces hydrocarbons from the reservoir, into the wellbore and up to surface. During primary recovery, only a small percentage of the initial hydrocarbons in place are produced, typically around 10% for oil reservoirs. Primary recovery is also called primary production.
Productive Wells		Producing wells and wells mechanically capable of production.
Proved developed non-producing reserves		Proved developed reserves that do not qualify as proved developed producing reserves, including reserves that are expected to be recovered from (i) completion intervals that are open at the time of the estimate, but have not started producing, (ii) wells that are shut in because pipeline connections are unavailable or (iii) wells not capable of production for mechanical reasons.
Proved developed reserves		Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or for which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved developed producing reserves		Reserves that are being recovered through existing wells with existing equipment and operating methods.
Proved reserves or proved oil and gas reserves		Refers to the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
Proved undeveloped reserves or PUDs		Undeveloped reserves that qualify as proved reserves.
PV-10		PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and 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.
Recompletion		The completion for production of an existing wellbore in a different formation or producing horizon, either deeper or shallower, from that in which the well was previously completed.
Secondary recovery		The second stage of hydrocarbon production during which a substance such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to support reservoir pressure and to displace hydrocarbons toward the wellbore.


Shut in		A well suspended from production or injection but not abandoned.
Tcf		One trillion cubic feet of natural gas.
Thermal Maturity		The degree of heating of a source rock in the process of transforming kerogen into hydrocarbon.
Thickness		The thickness of a layer or stratum of sedimentary rock measured perpendicular to its lateral extent, presuming deposition on a horizontal surface.
Total Organic Carbon		The concentration of organic material in source rocks as represented by the weight percent of organic carbon.
Unconventional Resource		Oil and gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs.
Undeveloped acreage		Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether the acreage contains proved oil or natural gas reserves.
Undeveloped reserves		Refers to reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Working interest		The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production, subject to all royalties, overriding royalties and other burdens, all costs of exploration, development and operations and all risks in connection therewith.
Workover		Remedial operations on a well conducted with the intention of restoring or increasing production from the same zone, including by plugging back, squeeze cementing, reperforating, cleanout and acidizing.

CALIFORNIA RESOURCES CORPORATION

Combined Condensed Balance Sheets

(unaudited)

	March 31, 2014			December 31, 2013

	(in millions)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	—
Trade receivables, net		22			30
Inventories		75			75
Other current assets		142			149


Total current assets		239			254


PROPERTY, PLANT AND EQUIPMENT		21,429			20,972
Accumulated depreciation, depletion and amortization		(7,256	)		(6,964	)


		14,173			14,008


OTHER ASSETS		35			35


TOTAL ASSETS	$	14,447		$	14,297




CURRENT LIABILITIES
Accounts payable	$	480		$	448
Accrued liabilities		255			241


Total current liabilities		735			689


DEFERRED INCOME TAXES		3,232			3,122
OTHER LONG-TERM LIABILITIES		501			497


		3,733			3,619
NET INVESTMENT
Accumulated other comprehensive income		(22	)		(24	)
Net parent company investment		10,001			10,013


Total net investment		9,979			9,989


TOTAL LIABILITIES AND NET INVESTMENT	$	14,447		$	14,297

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

CALIFORNIA RESOURCES CORPORATION

Combined Condensed Statements of Income

(unaudited)

	For the three months ended March 31,

	2014			2013
	(in millions)
REVENUES
Net sales to related parties	$	1,098		$	1,024
Net sales to third parties		23			24


		1,121			1,048


COSTS AND OTHER DEDUCTIONS
Production costs		289			263
Selling, general and administrative expenses		86			69
Depreciation, depletion and amortization		289			281
Taxes other than on income		52			53
Exploration expense		31			20


		747			686


INCOME BEFORE INCOME TAXES		374			362
Provision for income taxes		(151	)		(145	)


NET INCOME	$	223		$	217

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

CALIFORNIA RESOURCES CORPORATION

Combined Condensed Statements of Comprehensive Income

(unaudited)

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

CALIFORNIA RESOURCES CORPORATION

Combined Condensed Statements of Cash Flows

(unaudited)

	For the three months ended March 31,

	2014			2013
	(in millions)
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	223		$	217
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization of assets		289			281
Deferred income tax provision		119			80
Other noncash charges to income		14			12
Dry hole expenses		24			13
Changes in operating assets and liabilities, net		47			105


Net cash provided by operating activities		716			708


CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(475	)		(337	)
Payments for purchases of assets and businesses, and other		(2	)		(9	)


Net cash used by investing activities		(477	)		(346	)


CASH FLOW FROM FINANCING ACTIVITIES
Distributions to parent company		(239	)		(362	)


Net cash used by financing activities		(239	)		(362	)


Increase (decrease) in cash and cash equivalents		—			—
Cash and cash equivalents—beginning of period		—			—


Cash and cash equivalents—end of period	$	—		$	—

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

CALIFORNIA RESOURCES CORPORATION

Notes to Combined Condensed Financial Statements

(unaudited)

On February 14, 2014, Occidental Petroleum Corporation ("Occidental") announced that its board of directors had authorized Occidental's management to pursue the separation of its California oil and gas exploration and production operations and related assets, which CRC will assume in connection with the spin-off, into a stand-alone, publicly traded company (California Resources Corporation and its subsidiaries). Unless otherwise stated or the context otherwise indicates, references to "CRC," "us", "our" or "we" refer to California Resources Corporation, or as the context requires, the California business.

The separation will be completed through a spin-off that is being executed in accordance with a separation and distribution agreement and several other agreements between us and Occidental. The spin-off is intended to be tax-free to the stockholders of Occidental and to Occidental and us for United States federal income tax purposes. Occidental intends to distribute, on a pro-rata basis, over 80% of the outstanding shares of our common stock to the Occidental stockholders as of the record date for the spin-off. Upon completion of the spin-off, which does not require shareholder approval, we will be an independent, stand-alone company from Occidental. The spin-off is, among other things, subject to final approval by Occidental's board of directors, receipt of a private letter ruling from the Internal Revenue Service regarding certain aspects of the spin-off and an opinion of tax counsel, with respect to the tax-free nature of the spin-off for federal income tax purposes, the registration statement on Form 10 being declared effective and the execution of the separation and distribution and related agreements.

We were incorporated in Delaware as a wholly-owned subsidiary of Occidental on April 23, 2014. We are an oil and gas exploration and production company operating properties exclusively within the state of California. Additionally, we gather, process and market these products, and produce and sell power.

The accompanying combined condensed financial statements were prepared in connection with the spin-off and were derived from the consolidated financial statements and accounting records of Occidental. These combined condensed financial statements reflect the historical results of operations, financial position and cash flows of Occidental's California business, which comprises exploration and production of oil and gas properties located exclusively in California. We account for our share of oil and gas exploration and production ventures, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets and statements of income and cash flows.

The combined statements of income also include expense allocations for certain corporate functions and centrally-located activities historically performed by Occidental. These functions include executive oversight, accounting, treasury, tax, financial reporting, finance, internal audit, legal, risk management, information technology, government relations, public relations, investor relations, human resources, procurement, engineering, drilling, exploration, marketing, ethics and compliance, and certain other shared services. These allocations are based primarily on specific identification of time or activities associated with us, employee headcount or our relative size compared to Occidental. Our management believes the assumptions underlying the combined condensed financial statements, including the assumptions regarding allocating expenses from Occidental, are reasonable. However, the combined condensed financial statements may not include all of the actual expenses that would have been incurred,

NOTE 1 THE SPIN-OFF AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

may include duplicative costs and may not reflect our combined results of operations, financial position and cash flows had we operated as a stand-alone public company during the periods presented. Actual costs that would have been incurred if we had been a stand-alone company would depend on multiple factors, including organizational structure and strategic and operating decisions.

The assets and liabilities in the combined financial statements are presented on a historical cost basis. We have eliminated all of our significant intercompany transactions and accounts. We have historically participated in Occidental's centralized treasury management program. Excess cash generated by our business has been distributed to Occidental, and likewise our cash needs have been provided by Occidental, in the form of an investment. We have not included debt or related interest expense in the combined condensed financial statements since there was no specifically identifiable debt associated with our operations.

In the opinion of our management, the accompanying combined condensed financial statements contain all adjustments (consisting of normal recurring adjustments) necessary to fairly present our combined condensed financial position as of March 31, 2014, and the combined condensed statements of income, comprehensive income and cash flows for the three months ended March 31, 2014 and 2013, as applicable. The income and cash flows for the periods ended March 31, 2014 and 2013 are not necessarily indicative of the income or cash flows to be expected for the full year.

Events and transactions subsequent to the balance sheet date have been evaluated through June 2, 2014, the date these combined condensed financial statements were issued, for potential recognition or disclosure in the combined condensed financial statements.

Inventories as of March 31, 2014 and December 31, 2013, consisted of the following (in millions):

Other current assets include amounts due from joint venture partners of approximately $107 million and $97 million at March 31, 2014 and December 31, 2013, respectively. Accrued liabilities include amounts due for property taxes of approximately $46 million and $9 million at March 31, 2014 and December 31, 2013. Other long-term liabilities include asset retirement obligations of $388 million at both March 31, 2014 and December 31, 2013.

We only occasionally hedge our oil and gas production, and, when we do so, the volumes are usually insignificant.

We entered into financial swap agreements in November 2012 for the sale of a portion of our natural gas production. These swap agreements hedged 50 MMcf of natural gas per day beginning in January 2013 through March 2014 and qualified as cash-flow hedges. The weighted-average strike price of these swaps was $4.30. The gross and net fair values of these derivatives as of March 31, 2014 and December 31, 2013 were not material, as determined using Level 2 inputs in the fair value hierarchy.

The after-tax gains and losses recognized in, and reclassified to income from, Accumulated Other Comprehensive Income (AOCI) for derivative instruments classified as cash-flow hedges for the three month periods ended March 31, 2014 and 2013, and the ending AOCI balances for each period were not material. The gains and losses reclassified to income were recognized in net sales, and the amount of the ineffective portion of cash-flow hedges was immaterial for the three months ended March 31, 2014 and 2013.

There were no fair value hedges as of and during the three month periods ended March 31, 2014 and 2013.

We or certain of our subsidiaries are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at March 31, 2014 and December 31, 2013, were not material to our balance sheets. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on the balance sheet would not be material to our financial position or results of operations.

We will indemnify Occidental under the Tax Sharing Agreement for taxes incurred as a result of the failure of the spin-off to qualify as tax-free under Section 355 and Section 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended, to the extent caused by our breach of any representations or covenants made in the Tax Sharing Agreement, the Separation and Distribution Agreement, or made in connection with the private letter ruling or the tax opinion or by any other action taken by us. We also have agreed to pay 50% of any taxes arising from the spin-off to the extent that the tax is not attributable to the fault of either party. In addition, under the Separation and Distribution Agreement, we will also indemnify Occidental and its remaining subsidiaries against claims and liabilities relating to the past operation of our business.

The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the three months ended March 31, 2014 and 2013 (in millions):

We did not make any contributions in either of the three-month periods ended March 31, 2014 and 2013, to our defined benefit pension plans.

During the periods ended March 31, 2014 and 2013, we entered into the following related-party transactions (in millions):

Substantially all of our products were historically sold to Occidental's marketing subsidiaries at market prices and have been settled at the time of sale to those entities. For each of the periods ended March 31, 2014 and 2013, sales to Occidental subsidiaries accounted for approximately 98% of our net sales.

The combined statements of income include expense allocations for certain corporate functions and centrally-located activities historically performed by Occidental. These functions include executive oversight, accounting, treasury, tax, financial reporting, finance, internal audit, legal, risk management, information technology, government relations, public relations, investor relations, human resources, procurement, engineering, drilling, exploration, marketing, ethics and compliance, and certain other shared services. Charges from Occidental for these services are reflected in selling, general and administrative expenses.

Purchases from related parties reflect products purchased at market prices from Occidental's subsidiaries and are used in our operations. These purchases are included in production costs. There are no significant related party receivable or payable balances at March 31, 2014 and 2013.

We have audited the accompanying combined balance sheets of California Resources Corporation (the "Company") as of December 31, 2013 and 2012, and the related combined statements of income, comprehensive income, net investment and cash flows for each of the years in the three-year period ended December 31, 2013. These combined financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

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

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of California Resources Corporation as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013 in conformity with U.S. generally accepted accounting principles.

California Resources Corporation

Combined Balance Sheets

As of December 31, 2013 and 2012

	2013			2012

	(in millions)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	—
Trade receivables, net		30			22
Inventories		75			81
Other current assets		149			142


Total current assets		254			245


PROPERTY, PLANT AND EQUIPMENT		20,972			19,324
Accumulated depreciation, depletion and amortization		(6,964	)		(5,825	)


		14,008			13,499


OTHER ASSETS		35			20


TOTAL ASSETS	$	14,297		$	13,764




CURRENT LIABILITIES
Accounts payable	$	448		$	371
Accrued liabilities		241			180


Total current liabilities		689			551


DEFERRED INCOME TAXES		3,122			2,842
OTHER LONG-TERM LIABILITIES		497			511


		3,619			3,353


CONTINGENT LIABILITIES AND COMMITMENTS
NET INVESTMENT		9,989			9,860


TOTAL LIABILITIES AND NET INVESTMENT	$	14,297		$	13,764

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

California Resources Corporation

Combined Statements of Income

For the years ended December 31, 2013, 2012 and 2011

	2013			2012			2011

	(in millions)
REVENUES AND OTHER INCOME
Net sales to related parties	$	4,174		$	3,970		$	3,862
Net sales to third parties		111			102			76
Other income		(1	)		1			(4	)


		4,284			4,073			3,934


COSTS AND OTHER DEDUCTIONS
Production costs		1,066			1,314			1,074
Selling, general and administrative expenses		326			296			287
Depreciation, depletion and amortization		1,144			926			675
Asset impairments and related items		—			41			—
Taxes other than on income		185			167			143
Exploration expense		116			148			114


		2,837			2,892			2,293


INCOME BEFORE INCOME TAXES		1,447			1,181			1,641
Provision for income taxes		(578	)		(482	)		(670	)


NET INCOME	$	869		$	699		$	971

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

California Resources Corporation

Combined Statements of Comprehensive Income

For the years ended December 31, 2013, 2012 and 2011

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

California Resources Corporation

Combined Statements of Net Investment

For the years ended December 31, 2013, 2012 and 2011

	Accumulated Other Comprehensive Income (Loss)			Net Parent Company Investment			Total

	(in millions)
Balance, December 31, 2010	$	(42	)	$	6,599		$	6,557
Net income		—			971			971
Other comprehensive loss, net of tax		(10	)		—			(10	)
Net contributions from parent company		—			1,106			1,106


Balance, December 31, 2011	$	(52	)	$	8,676		$	8,624
Net income		—			699			699
Other comprehensive income, net of tax		5			—			5
Net contributions from parent company		—			532			532


Balance, December 31, 2012	$	(47	)	$	9,907		$	9,860
Net income		—			869			869
Other comprehensive income, net of tax		23			—			23
Net distributions to parent company		—			(763	)		(763	)


Balance, December 31, 2013	$	(24	)	$	10,013		$	9,989

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

CALIFORNIA RESOURCES CORPORATION

Combined Statements of Cash Flows

For the years ended December 31, 2013, 2012 and 2011

	2013			2012			2011

	(in millions)
CASH FLOW FROM OPERATING ACTIVITIES
Net income	$	869		$	699		$	971
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization of assets		1,144			926			675
Deferred income tax provision		260			603			586
Other noncash charges to income		29			28			27
Asset impairments and related items		—			41			—
Dry hole expenses		72			128			74
Changes in operating assets and liabilities:
(Increase) decrease in trade receivables, net		(8	)		20			(31	)
Decrease (increase) in inventories		8			(23	)		(2	)
Decrease (increase) in other current assets		2			(49	)		(15	)
Increase (decrease) in accounts payable and accrued liabilities		100			(150	)		171


Net cash provided by operating activities		2,476			2,223			2,456


CASH FLOW FROM INVESTING ACTIVITIES
Capital expenditures		(1,669	)		(2,331	)		(2,164	)
Payments for purchases of assets and businesses		(48	)		(427	)		(1,405	)
Other, net		4			3			4


Net cash used by investing activities		(1,713	)		(2,755	)		(3,565	)


CASH FLOW FROM FINANCING ACTIVITIES
(Distributions to) contributions from parent company		(763	)		532			1,106


Net cash (used) provided by financing activities		(763	)		532			1,106


Increase (decrease) in cash and cash equivalents		—			—			(3	)
Cash and cash equivalents—beginning of year		—			—			3


Cash and cash equivalents—end of year	$	—		$	—		$	—

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

The accompanying combined financial statements were prepared in connection with the spin-off and were derived from the consolidated financial statements and accounting records of Occidental. These combined financial statements reflect the historical results of operations, financial position and cash flows of Occidental's California oil and gas operations, which comprises exploration and production of oil and gas properties located exclusively in California. We account for our share of oil and gas exploration and production ventures, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on the balance sheets and statements of income and cash flows.

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

NOTE 1 THE SPIN-OFF AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

have been incurred if we had been a stand-alone company would depend on multiple factors, including organizational structure and strategic and operating decisions.

The assets and liabilities in the combined financial statements are presented on a historical cost basis. We have eliminated all of our significant intercompany transactions and accounts. We have historically participated in Occidental's centralized treasury management program. Excess cash generated by our business has been distributed to Occidental, and likewise our cash needs have been provided by Occidental, in the form of an investment. We have not included debt or related interest expense in the combined financial statements since there was no specifically identifiable debt associated with our operations.

Events and transactions subsequent to the balance sheet date have been evaluated through June 2, 2014, the date these combined financial statements were issued, for potential recognition or disclosure in the combined financial statements.

The process of preparing financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the combined financial statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of our financial statements.

We recognize revenue from oil and gas production when title has passed from us to the transportation company or the customer, as applicable. We recognize our share of revenues net of any royalties and other third-party share.

In our combined balance sheets, net investment represents Occidental's historical investment in us, our accumulated net income and the net effect of transactions with, and allocations from, Occidental.

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

The carrying value of our property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations, net of accumulated depreciation, depletion and amortization (DD&A) and any impairment charges. For assets acquired, PP&E cost is based

NOTE 1 THE SPIN-OFF AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

on fair values at the acquisition date. Asset retirement obligations are capitalized and amortized over the lives of the related assets.

We use the successful efforts method to account for oil and gas properties. Under this method, we capitalize costs of acquiring properties, costs of drilling successful exploration wells and development costs. The costs of exploratory wells are initially capitalized pending a determination of whether we find proved reserves. If we find proved reserves, the costs of exploratory wells remain capitalized. Otherwise, we charge the costs of the related wells to expense. In some cases, we cannot determine whether we have found proved reserves at the completion of the exploration drilling, and must conduct additional testing and evaluation of the wells. We generally expense the costs of such exploratory wells if we do not determine we have found proved reserves within a 12-month period after drilling is complete.

The following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:

We expense annual lease rentals, the costs of injection used in production and exploration, geological, geophysical and seismic costs as incurred. Cost of maintenance and repairs are expensed as incurred, except that the costs of replacements that expand capacity or add proven oil and gas reserves are capitalized.

Proved oil and gas reserves and production are used as the basis for recording depreciation and depletion of oil and gas properties. Proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—regardless of whether deterministic or probabilistic methods are used for the estimation. We have no proved oil and gas reserves for which the determination of economic producibility is subject to the completion of major additional capital expenditures.

Our gas plant and power plant assets are depreciated over the estimated useful lives of the assets, using the straight-line method, with expected useful lives of the assets ranging from 2 to 30 years. Other

NOTE 1 THE SPIN-OFF AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

property and equipment is depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two to 20 years.

We perform impairment tests with respect to proved properties when product prices decline other than temporarily, reserve estimates change significantly, other significant events occur or management's plans change with respect to these properties in a manner that may impact our ability to realize the recorded asset amounts. Impairment tests incorporate a number of assumptions involving expectations of undiscounted future cash flows, which can change significantly over time. These assumptions include estimates of future product prices, which we base on forward price curves and, when applicable, contractual prices, estimates of oil and gas reserves and estimates of future expected operating and development costs. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.

A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At December 31, 2013, the net capitalized costs attributable to unproved properties were approximately $900 million. The unproved amounts are not subject to DD&A until they are classified as proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the properties become subject to DD&A. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results. In 2012, management decided not to pursue development of certain of our gas properties which were impacted by persistently low gas prices. As a result, we recorded an impairment charge in 2012, which is reflected in asset impairments and related charges in the combined statement of income. We believe the current plans and exploration and development efforts will allow us to realize the unproved property balance.

We perform impairment tests on our infrastructure assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management's plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.

We recognize the fair value of asset retirement obligations in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalize the cost by increasing the related PP&E balances. If the estimated future cost of the asset retirement obligation changes, we record an adjustment to both the asset retirement obligation and PP&E. Over time, the liability is increased and expense is recognized for accretion, and the capitalized cost is depreciated over the useful life of the asset.

NOTE 1 THE SPIN-OFF AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

At certain of our facilities, we have identified asset retirement obligations that are related mainly to plant and field decommissioning, including plugging and abandonment of wells. We do not know or cannot estimate when we may settle these obligations. Therefore, we cannot reasonably estimate the fair value of these liabilities. We will recognize these asset retirement obligations in the periods in which sufficient information becomes available to reasonably estimate their fair values. Additionally, for certain plants, we do not have a legal obligation to decommission them and accordingly we have not recorded a liability.

The following table summarizes the activity of the asset retirement obligation, of which $388 million and $367 million is included in other long-term liabilities, with the remaining current portion in accrued liabilities at December 31, 2013 and 2012, respectively.

Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. We apply hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the combined statements of income. Ineffectiveness is primarily created by a lack of correlation between the hedged item and the hedging instrument due to location, quality, grade or changes in the expected quantity of the hedged item. Gains and losses from derivative instruments are reported net in the combined statements of income.

A hedge is regarded as highly effective such that it qualifies for hedge accounting if, at inception and throughout its life, we expect that changes in the fair value or cash flows of the hedged item will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an exposure to variations in cash flows that could ultimately affect reported net income or loss. We discontinue hedge accounting when we determine that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

NOTE 1 THE SPIN-OFF AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

A majority of our employees participated in postretirement benefit plans sponsored by Occidental, which included participants from other Occidental subsidiaries. These plans do not have any assets and are funded as benefits are paid. We recognized a liability in the accompanying balance sheets for the employees of the California operations. The related postretirement expenses were allocated to us from Occidental based on headcount.

For defined benefit pension and postretirement plans that are sponsored by us, we recognize the net overfunded or underfunded amounts in the financial statements using a December 31 measurement date.

We determine our defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date. We estimate the rate of return on assets with regard to current market factors but within the context of historical returns.

Pension plan assets are measured at fair value. Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available. When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets. Common and collective trusts are valued at the fund units' net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active market. Short-term investment funds are valued at the fund units' NAV provided by the issuer.

Actuarial gains and losses that have not yet been recognized through income are recorded in accumulated other comprehensive income within net investment, net of taxes, until they are amortized as a component of net periodic benefit cost.

We have categorized our assets and liabilities that are measured at fair value in a three-level fair value hierarchy, based on the inputs to the valuation techniques: Level 1—using quoted prices in active markets for the assets or liabilities; Level 2—using observable inputs other than quoted prices for the assets or liabilities; and Level 3—using unobservable inputs. Transfers between levels, if any, are recognized at the end of each reporting period. We primarily apply the market approach for recurring fair value measurements, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management's judgments regarding expectations of projected cash flows and discounts those cash flows using a risk-adjusted discount rate.

Cash flow hedges are carried at fair value. We utilize the mid-point between bid and ask prices for valuing these instruments. In addition to using market data in determining these fair values, we make assumptions about the risks inherent in the inputs to the valuation technique. These instruments are Over-the-Counter (OTC) bilateral financial commodity contracts, which are generally valued using quotations provided by brokers. Substantially all of these inputs are observable data or are supported by observable prices at which transactions are executed in the marketplace. We classify these measurements as Level 2.

NOTE 1 THE SPIN-OFF AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The carrying amounts of on-balance-sheet financial instruments approximate fair value.

Other current assets include amounts due from joint venture partners of approximately $97 million and $71 million at December 31, 2013 and 2012, respectively.

Accrued liabilities include accrued compensation-related costs of approximately $70 million and $50 million at December 31, 2013 and 2012, respectively.

We have not made United States federal and state income tax payments directly to taxing jurisdictions; rather, our share of our parent's tax payments or refunds were paid or received, as applicable, by our parent and are reflected as part of the net parent company investment. Such amounts paid during the year ended December 31, 2013 and 2011 were approximately $318 million and $84 million, respectively, while the year ended December 31, 2012 resulted in a net refund of approximately $121 million. We also paid taxes other than on income, consisting mostly of property taxes, of approximately $185 million, $171 million and $143 million during the years ended December 31, 2013, 2012 and 2011, respectively.

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

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income.

During the year ended December 31, 2013, we paid approximately $50 million to acquire certain oil and gas properties in California. One of our acquisitions in the San Joaquin basin also included an obligation to spend at least $250 million on exploration and development activities over a period of five years from the date of acquisition. We currently plan to spend more than this amount in the next five years.

During the year ended December 31, 2012, we paid approximately $380 million for oil and gas properties, almost all of which was allocated to PP&E, including an acquisition for $275 million for certain

producing and non-producing assets in the Sacramento basin and undeveloped acreage in the San Joaquin basin.

During the year ended December 31, 2011, we acquired approximately $1.4 billion of various oil and gas assets, almost all of which was allocated to PP&E. We paid $720 million for producing and non-producing assets within the San Joaquin basin. We also acquired producing and non-producing assets in the Los Angeles Basin for $330 million and certain assets in the Sacramento basin for $190 million.

In July 2013, the Financial Accounting Standards Board (FASB) issued rules requiring net, rather than gross, presentation of a deferred tax asset for a net operating loss or other tax credit and any related liability for unrecognized tax benefits. These rules became effective on January 1, 2014, and did not have a material impact on our financial statements.

In April 2014, the FASB issued rules changing the requirements for reporting discontinued operations so that only the disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results will be reported as discontinued operations in the financial statements. These rules are effective for annual periods beginning on or after December 15, 2014. They are not expected to have a material impact on our financial statements upon adoption. We will assess them on an ongoing basis.

We have entered into various operating lease agreements, mainly for office equipment, field equipment and office space. We lease assets when leasing offers greater operating flexibility. Lease payments are generally expensed as part of production costs or selling, general and administrative expenses. At December 31, 2013, future net minimum lease payments for noncancelable operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) totaled:

Rental expense for operating leases was $11 million in 2013, $12 million in 2012 and $8 million in 2011.

We only occasionally hedge our oil and gas production, and, when we do so, the volumes are usually insignificant. Refer to Note 1 for our accounting policy on derivatives.

We entered into financial swap agreements in November 2012 for the sale of a portion of our natural gas production. These swap agreements hedged 50 MMcf of natural gas per day beginning in January 2013 through March 2014 and qualified as cash-flow hedges. The weighted-average strike price of these swaps was $4.30. The gross and net fair values of these derivatives as of December 31, 2013 and 2012 were not material, as determined using Level 2 inputs in the fair value hierarchy

The after-tax gains and losses recognized in, and reclassified to income from, Accumulated Other Comprehensive Income (AOCI), for derivative instruments classified as cash-flow hedges for the year ended December 31, 2013 and 2012, and the ending AOCI balances for each period were not material. We expect to reclassify an insignificant amount, based on the valuation as of December 31, 2013, of net after-tax derivative losses from AOCI into income during the next 12 months. We recognized gains and losses reclassified to income in net sales. The amount of the ineffective portion of cash-flow hedges was immaterial for the year ended December 31, 2013 and 2012.

There were no fair value hedges as of and during the years ended December 31, 2013, 2012 and 2011.

We or certain of our subsidiaries are involved, in the normal course of business, in lawsuits, environmental and other claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at December 31, 2013 and 2012, were not material to our balance sheets. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on the balance sheet would not be material to our financial position or results of operations.

We have certain commitments under contracts, including purchase commitments for goods and services. At December 31, 2013, total purchase obligations were approximately $650 million, which included approximately $250 million, $80 million, $40 million, $30 million and $230 million that will be paid in 2014, 2015, 2016, 2017 and 2018, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2014 and thereafter, which were approximately $270 million.

We will indemnify Occidental under the Tax Sharing Agreement for taxes incurred as a result of the failure of the spin-off to qualify as tax-free under Section 355 and Section 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended, to the extent caused by our breach of any representations or covenants made in the Tax Sharing Agreement, the Separation and Distribution Agreement, or made in connection with the private letter ruling or the tax opinion or by any other action taken by us. We also have agreed to pay 50% of any taxes arising from the spin-off to the extent that the tax is not attributable to the fault of either party. In addition, under the Separation and Distribution Agreement, we will also indemnify Occidental and its remaining subsidiaries against claims and liabilities relating to the past operation of our business.

The provisions (credits) for federal, state and local income taxes consisted of the following:

The following reconciliation of the United States federal statutory income tax rate to our effective tax rate is stated as a percentage of pre-tax income:

The tax effects of temporary differences resulting in deferred income taxes at December 31, 2013 and 2012 were as follows:

The current portion of total deferred tax assets was $23 million and $15 million as of December 31, 2013 and 2012, respectively, which was reported in other current assets. The noncurrent portion of total deferred tax assets was reported net against deferred tax liabilities. We expect to realize the recorded deferred tax assets through future operating income and reversal of temporary differences.

Accumulated other comprehensive loss consisted of the following after-tax amounts:

As discussed in Note 1, a majority of our employees participated in postretirement benefit plans sponsored by Occidental, which included participants of other Occidental subsidiaries and certain employees were part of pension and postretirement plans sponsored by us.

All of our employees were eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by us, our subsidiaries or Occidental, based on plan-specific criteria, such as base pay, age, level and employee contributions. Certain salaried employees participated in a supplemental retirement plan that restored benefits lost due to governmental limitations on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $17 million and $11 million as of December 31, 2013 and 2012, respectively, and we expensed $34 million in 2013, $35 million in 2012 and $31 million in 2011 under the provisions of these defined contribution and supplemental retirement plans.

Participation in defined benefit pension and postretirement plans sponsored by us is limited. Approximately 270 employees, mainly union, nonunion hourly and certain employees that joined us from acquired operations with grandfathered benefits, are currently accruing benefits under these plans.

Pension costs for the defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees.

We provided postretirement medical and dental benefits and life insurance coverage for our employees not covered by our sponsored plans and their eligible dependents through Occidental sponsored plans. The benefits were generally funded as they were paid during the year. These benefit costs were approximately $18 million in 2013, $17 million in 2012 and $12 million in 2011.

The following tables show the amounts recognized in our combined balance sheets related to pension and postretirement benefit plans, including our share of obligations for Occidental-sponsored plans as well as plans that we or our subsidiaries sponsor, and their funding status, obligations and plan asset fair values (in millions):

	Pension Benefits						Postretirement Benefits

	For the years ended December 31,
	2013			2012			2013			2012
Changes in the benefit obligation:
Benefit obligation—beginning of year	$	108		$	108		$	74		$	67
Service cost—benefits earned during the period		5			4			4			4
Interest cost on projected benefit obligation		3			4			3			3
Actuarial (gain) loss		(2	)		7			(18	)		—
Benefits paid		(11	)		(15	)		—			—


Benefit obligation—end of year	$	103		$	108		$	63		$	74


Changes in plan assets:
Fair value of plan assets—beginning of year	$	74		$	70		$	—		$	—
Actual return on plan assets		13			7			—			—
Employer contributions		15			12			—			—
Benefits paid		(11	)		(15	)		—			—


Fair value of plan assets—end of year	$	91		$	74		$	—		$	—


(Unfunded) status:	$	(12	)	$	(34	)	$	(63	)	$	(74	)

The following table sets forth the accumulated and projected benefit obligations and fair values of assets of the defined benefit pension plans:

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $2 million and zero, respectively. The estimated net loss and prior service cost for the defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $1 million and zero, respectively.

The following table sets forth the weighted-average assumptions used to determine our benefit obligations and net periodic benefit cost:

For pension plans and postretirement benefit plans that we or our subsidiaries sponsor, we based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 2013 and 2012. The weighted-average rate of increase in future compensation levels is consistent with our past and anticipated future compensation increases for employees participating in retirement plans that determine benefits using compensation. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end.

The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial assumptions and healthcare cost trend rates projected at an assumed U.S. Consumer Price Index (CPI) increase of 2.36 percent and 2.39 percent as of December 31, 2013 and 2012, respectively. A 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates would result in an increase of $6 million or a reduction of $5 million, respectively, in the postretirement benefit obligation as of December 31, 2013. The annual service and interest costs would not be materially affected by these changes.

The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that, depending on the nature of the changes, could cause increases or decreases in the plan assets and liabilities.

We employ a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the long-term return of plan assets at a prudent level of risk. The investments were monitored by Occidental's Investment Committee in its role as fiduciary. The Investment Committee, consisting of senior Occidental executives, selected and employed various external professional investment management firms to manage specific investments across the spectrum of asset classes. Equity investments were diversified across United States and non-United States stocks, as well as differing styles and market capitalizations. Other asset classes, such as private equity and real estate, may have been used by the investment management firms with the goals of enhancing long-term returns and improving portfolio

diversification. The target allocation of plan assets was 65 percent equity securities and 35 percent debt securities. Investment performance was measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.

The fair values of our pension plan assets by asset category are as follows (in millions):

The activity during the years ended December 31, 2013 and 2012, for the assets using Level 3 fair value measurements was insignificant.

We do not expect to contribute to our defined benefit pension plans during 2014.

Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows:

During 2013, 2012 and 2011, we entered into the following related-party transactions:

Substantially all of our products are historically sold to Occidental's marketing subsidiaries at market prices and have been settled at the time of sale to those entities. For the years ended December 31, 2013, 2012 and 2011, sales to Occidental subsidiaries accounted for approximately 97%, 97% and 98% of our net sales, respectively.

As discussed in Note 1, the combined statements of income include expense allocations for certain corporate functions and centrally-located activities historically performed by Occidental. These functions include executive oversight, accounting, treasury, tax, financial reporting, internal audit, legal, risk management, information technology, government relations, public relations, investor relations, human resources, procurement, engineering, drilling, exploration, finance, marketing, ethics and compliance, and certain other shared services. Charges from Occidental for these services are reflected in selling, general and administrative expenses.

The following tables set forth our net interests in quantities of proved developed and undeveloped reserves of oil (including condensate), natural gas liquids and natural gas and changes in such quantities. Reserves are stated net of applicable royalties. Estimated reserves include our economic interests under arrangements similar to production-sharing contracts (PSCs) relating to the Wilmington field in Long Beach. All of our proved reserves are located within the state of California.

	San Joaquin Basin

	(In millions of barrels (MMBbl))
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2010		340		110		39		—	489
Revisions of previous estimates		(58	)	—		—		—	(58	)
Improved recovery		51		12		3		—	66
Extensions and discoveries		7		—		1		—	8
Purchases of proved reserves		16		16		—		—	32
Sales of proved reserves		—		—		—		—	—
Production		(20	)	(7	)	(2	)	—	(29	)


Balance at December 31, 2011		336		131		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		311		139		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		331		156		45		—	532




PROVED DEVELOPED RESERVES
December 31, 2010		266		83		27		—	376




December 31, 2011		239		97		30		—	366




December 31, 2012		220		104		30		—	354




December 31, 2013(b)		225		109		29		—	363




PROVED UNDEVELOPED RESERVES
December 31, 2010		74		27		12		—	113




December 31, 2011		97		34		11		—	142




December 31, 2012		91		35		17		—	143




December 31, 2013		106		47		16		—	169

	San Joaquin Basin

	(In MMBbl)
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2010		72		—	4		—	76
Revisions of previous estimates		(5	)	—	(1	)	—	(6	)
Improved recovery		3		—	—		—	3
Extensions and discoveries		1		—	—		—	1
Purchases of proved reserves		—		—	—		—	—
Sales of proved reserves		—		—	—		—	—
Production		(5	)	—	—		—	(5	)


Balance at December 31, 2011		66		—	3		—	69
Revisions of previous estimates		(14	)	—	—		—	(14	)
Improved recovery		12		—	1		—	13
Extensions and discoveries		—		—	—		—	—
Purchases of proved reserves		—		—	—		—	—
Sales of proved reserves		—		—	—		—	—
Production		(6	)	—	—		—	(6	)


Balance at December 31, 2012		58		—	4		—	62
Revisions of previous estimates		13		—	—		—	13
Improved recovery		4		—	—		—	4
Extensions and discoveries		—		—	—		—	—
Purchases of proved reserves		—		—	—		—	—
Sales of proved reserves		—		—	—		—	—
Production		(7	)	—	—		—	(7	)


Balance at December 31, 2013		68		—	4		—	72




PROVED DEVELOPED RESERVES
December 31, 2010		40		—	4		—	44




December 31, 2011		42		—	3		—	45




December 31, 2012		42		—	2		—	44




December 31, 2013(a)		47		—	2		—	49




PROVED UNDEVELOPED RESERVES
December 31, 2010		32		—	—		—	32




December 31, 2011		24		—	—		—	24




December 31, 2012		16		—	2		—	18




December 31, 2013		21		—	2		—	23

	San Joaquin Basin

	(In billions of cubic feet (Bcf))
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2010		1,170		12		39		3		1,224
Revisions of previous estimates		(357	)	5		(1	)	4		(349	)
Improved recovery		39		—		1		6		46
Extensions and discoveries		35		—		—		—		35
Purchases of proved reserves		1		9		1		38		49
Sales of proved reserves		—		—		—				—
Production		(80	)	(1	)	(4	)	(10	)	(95	)


Balance at December 31, 2011		808		25		36		41		910
Revisions of previous estimates		(150	)	(6	)	(3	)	(9	)	(168	)
Improved recovery		100		1		9		1		111
Extensions and discoveries		6		—		—		6		12
Purchases of proved reserves		2		—		—		154		156
Sales of proved reserves		—		—		—				—
Production		(74	)	(1	)	(4	)	(14	)	(93	)


Balance at December 31, 2012		692		19		38		179		928
Revisions of previous estimates		(4	)	(4	)	(1	)	(38	)	(47	)
Improved recovery		47		3		2		—		52
Extensions and discoveries		—		—		—		—		—
Purchases of proved reserves		—		—		—		—		—
Sales of proved reserves		—		—		—		—		—
Production		(66	)	(1	)	(4	)	(24	)	(95	)


Balance at December 31, 2013		669		17		35		117		838




PROVED DEVELOPED RESERVES
December 31, 2010		584		9		31		3		627




December 31, 2011		548		19		31		41		639




December 31, 2012		473		14		28		147		662




December 31, 2013(a)		459		11		25		116		611




PROVED UNDEVELOPED RESERVES
December 31, 2010		586		3		8		—		597




December 31, 2011		260		6		5		—		271




December 31, 2012		219		5		10		32		266




December 31, 2013		210		6		10		1		227

	San Joaquin Basin

	(In MMBoe(a))
PROVED DEVELOPED AND UNDEVELOPED RESERVES
Balance at December 31, 2010		606		112		52		—		770
Revisions of previous estimates		(122	)	1		(2	)	—		(123	)
Improved recovery		61		12		3		1		77
Extensions and discoveries		15		—		1		—		16
Purchases of proved reserves		16		17		—		6		39
Sales of proved reserves		—		—		—		—		—
Production		(39	)	(7	)	(2	)	(2	)	(50	)


Balance at December 31, 2011		537		135		52		5		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		142		58		28		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		159		55		19		744




PROVED DEVELOPED RESERVES
December 31, 2010		402		84		39		—		525




December 31, 2011		372		100		40		5		517




December 31, 2012		341		106		38		23		508




December 31, 2013(c)		349		111		35		19		514




PROVED UNDEVELOPED RESERVES
December 31, 2010		204		28		13		—		245




December 31, 2011		165		35		12		—		212




December 31, 2012		145		36		20		5		206




December 31, 2013		162		48		20		—		230

Capitalized costs relating to oil and gas producing activities and related accumulated DD&A were as follows:

	San Joaquin Basin			Los Angeles Basin			Ventura Basin			Sacramento Basin			Total

	(In millions)
December 31, 2013
Proved properties	$	15,592		$	2,487		$	1,479		$	542		$	20,100
Unproved properties		584			105			91			92			872


Total capitalized costs(a)		16,176			2,592			1,570			634			20,972
Accumulated depreciation, depletion and amortization		(5,923	)		(571	)		(342	)		(128	)		(6,964	)


Net capitalized costs	$	10,253		$	2,021		$	1,228		$	506		$	14,008




December 31, 2012
Proved properties	$	14,817		$	1,974		$	1,327		$	286		$	18,404
Unproved properties		639			97			92			92			920


Total capitalized costs(a)		15,456			2,071			1,419			378			19,324
Accumulated depreciation, depletion and amortization		(5,039	)		(424	)		(272	)		(90	)		(5,825	)


Net capitalized costs	$	10,417		$	1,647		$	1,147		$	288		$	13,499




December 31, 2011
Proved properties	$	12,611		$	1,904		$	1,227		$	199		$	15,941
Unproved properties		641			52			12			69			774


Total capitalized costs(a)		13,252			1,956			1,239			268			16,715
Accumulated depreciation, depletion and amortization		(4,214	)		(405	)		(279	)		(39	)		(4,937	)


Net capitalized costs	$	9,038		$	1,551		$	960		$	229		$	11,778

Costs incurred includes capital expenditures, exploration (whether expensed or capitalized), acquisitions, and asset retirement obligations, as follows:

	San Joaquin Basin		Los Angeles Basin		Ventura Basin		Sacramento Basin		Total

	(In millions)
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		1,092		371		110		15		1,588


Costs incurred	$	1,256	$	381	$	112	$	23	$	1,772




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		1,732		348		124		26		2,230


Costs incurred	$	1,998	$	361	$	125	$	311	$	2,795




FOR THE YEAR ENDED DECEMBER 31, 2011
Property acquisition costs
Proved properties	$	351	$	413	$	106	$	149	$	1,019
Unproved properties		438		—		6		68		512
Exploration costs		146		29		9		1		185
Development costs		1,703		207		54		40		2,004


Costs incurred	$	2,638	$	649	$	175	$	258	$	3,720

Our oil and gas producing activities, which exclude items such as asset dispositions and corporate overhead, were as follows:

	San Joaquin Basin		Los Angeles Basin		Ventura Basin		Sacramento Basin			Total

	(In millions)
FOR THE YEAR ENDED DECEMBER 31, 2013
Revenues(a)	$	2,969	$	968	$	259	$	89		$	4,285
Production costs(b)		658		306		75		27			1,066
Other operating expenses		153		56		19		18			246
Depreciation, depletion and amortization		866		108		73		97			1,144
Taxes other than on income		123		43		9		10			185
Exploration expenses		94		1		13		8			116


Pretax income		1,075		454		70		(71	)		1,528
Income tax expense		428		181		28		(28	)		609


Results of operations	$	647	$	273	$	42	$	(43	)	$	919




FOR THE YEAR ENDED DECEMBER 31, 2012
Revenues(a)	$	2,843	$	921	$	262	$	46		$	4,072
Production costs(b)		885		331		81		17			1,314
Other operating expenses		138		52		18		10			218
Depreciation, depletion and amortization		742		79		61		44			926
Taxes other than on income		114		37		9		7			167
Asset impairments and related items		31		10		—		—			41
Exploration expenses		112		29		1		6			148


Pretax income		821		383		92		(38	)		1,258
Income tax expense		335		156		38		(15	)		514


Results of operations	$	486	$	227	$	54	$	(23	)	$	744




FOR THE YEAR ENDED DECEMBER 31, 2011
Revenues(a)	$	2,898	$	766	$	231	$	43		$	3,938
Production costs(b)		721		264		77		12			1,074
Other operating expenses		127		50		13		6			196
Depreciation, depletion and amortization		543		58		44		30			675
Taxes other than on income		101		29		8		5			143
Exploration expenses		113		—		—		1			114


Pretax income		1,293		365		89		(11	)		1,736
Income tax expense		528		149		36		(4	)		709


Results of operations	$	765	$	216	$	53	$	(7	)	$	1,027

	San Joaquin Basin		Los Angeles Basin		Ventura Basin		Sacramento Basin			Total

FOR THE YEAR ENDED DECEMBER 31, 2013
Revenue from each barrel of oil equivalent ($/Boe)(a)(b)	$	75.58	$	101.17	$	79.28	$	22.09		$	76.32
Production costs		16.75		31.98		22.96		6.70			18.99
Other operating expenses		3.89		5.85		5.82		4.47			4.38
Depreciation, depletion and amortization		22.05		11.29		22.34		24.08			20.38
Taxes other than on income		3.13		4.49		2.75		2.48			3.29
Exploration expenses		2.39		0.10		3.98		1.99			2.07


Pretax income		27.37		47.46		21.43		(17.63	)		27.21
Income tax expense		10.90		18.92		8.57		(6.95	)		10.85


Results of operations	$	16.47	$	28.54	$	12.86	$	(10.68	)	$	16.36




FOR THE YEAR ENDED DECEMBER 31, 2012
Revenue from each barrel of oil equivalent ($/Boe)(a)(b)	$	71.96	$	102.45	$	81.85	$	20.09		$	75.42
Production costs		22.40		36.82		25.30		7.42			24.34
Other operating expenses		3.49		5.78		5.62		4.37			4.04
Depreciation, depletion and amortization		18.78		8.79		19.06		19.21			17.15
Taxes other than on income		2.89		4.12		2.81		3.06			3.09
Asset impairments and related items		0.78		1.11		—		—			0.76
Exploration expenses		2.83		3.23		0.31		2.62			2.74


Pretax income		20.79		42.60		28.75		(16.59	)		23.30
Income tax expense		8.48		17.35		11.87		(6.55	)		9.52


Results of operations	$	12.31	$	25.25	$	16.88	$	(10.04	)	$	13.78




FOR THE YEAR ENDED DECEMBER 31, 2011
Revenue from each barrel of oil equivalent ($/Boe)(a)(b)	$	75.10	$	103.99	$	82.38	$	25.67		$	78.08
Production costs		18.68		35.84		27.46		7.16			21.30
Other operating expenses		3.29		6.79		4.64		3.58			3.89
Depreciation, depletion and amortization		14.07		7.87		15.69		17.91			13.38
Taxes other than on income		2.62		3.94		2.85		2.99			2.84
Exploration expenses		2.93		—		—		0.60			2.26


Pretax income		33.51		49.55		31.74		(6.57	)		34.41
Income tax expense		13.68		20.23		12.84		(2.39	)		14.06


Results of operations	$	19.83	$	29.32	$	18.90	$	(4.18	)	$	20.35

Standardized Measure, Including Year-to-Year Changes Therein, of Discounted Future Net Cash Flows

For purposes of the following disclosures, future cash flows were computed by applying to our proved oil and gas reserves the unweighted arithmetic average of the first-day-of-the-month price for each month within the years ended December 31, 2013, 2012 and 2011, respectively. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the current cost environment applied to expectations of future operating and development activities. Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits and allowances) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10-percent discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 2013, 2012 and 2011. Such assumptions, which are prescribed by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.

	Total

	(In millions)
AT DECEMBER 31, 2013
Future cash inflows	$	60,884
Future costs
Production costs and other operating expenses		(29,523	)
Development costs(a)		(6,327	)
Future income tax expense		(8,213	)


Future net cash flows		16,821
Ten percent discount factor		(7,598	)


Standardized measure of discounted future net cash flows	$	9,223




AT DECEMBER 31, 2012
Future cash inflows	$	57,468
Future costs
Production costs and other operating expenses		(26,968	)
Development costs(a)		(5,961	)
Future income tax expense		(8,059	)


Future net cash flows		16,480
Ten percent discount factor		(7,407	)


Standardized measure of discounted future net cash flows	$	9,073




AT DECEMBER 31, 2011
Future cash inflows	$	60,872
Future costs
Production costs and other operating expenses		(26,642	)
Development costs(a)		(5,015	)
Future income tax expense		(9,925	)


Future net cash flows		19,290
Ten percent discount factor		(8,943	)


Standardized measure of discounted future net cash flows	$	10,347

Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserve Quantities

	For the years ended December 31,

	2013			2012			2011
	(In millions)
Beginning of year	$	9,073		$	10,347		$	7,051


Sales and transfers of oil and gas produced, net of production costs and other operating expenses		(3,082	)		(2,695	)		(2,840	)
Net change in prices received per Bbl, net of production costs and other operating expenses		575			(1,431	)		4,837
Extensions, discoveries and improved recovery, net of future production and development costs		1,914			1,897			2,662
Change in estimated future development costs		(1,047	)		(2,560	)		(1,878	)
Revisions of quantity estimates		(62	)		2,073			1,732
Development costs incurred during the period		1,544			(1,405	)		(1,839	)
Accretion of discount		1,292			1,512			1,048
Net change in income taxes		(95	)		984			(1,960	)
Purchases and sales of reserves in place, net		4			221			1,065
Changes in production rates and other		(893	)		130			469


Net change		150			(1,274	)		3,296


End of year	$	9,223		$	9,073		$	10,347

The following table set forth the production volumes of oil, NGLs and natural gas per day for each of the three years in the period ended December 31, 2013.



Oil (MBbl/d)
San Joaquin Basin(b)	58	58	56
Los Angeles Basin(c)	26	24	19
Ventura Basin	6	6	5
Sacramento Basin	—	—	—


Total	90	88	80


NGLs (MBbl/d)
San Joaquin Basin(b)	19	16	14
Los Angeles Basin	—	—	—
Ventura Basin	1	1	1
Sacramento Basin	—	—	—


Total	20	17	15


Natural gas (MMcf/d)
San Joaquin Basin(b)	182	204	220
Los Angeles Basin(c)	2	3	1
Ventura Basin	11	12	12
Sacramento Basin	65	37	27


Total	260	256	260


Total Production (MBoe/d)(a)	154	148	138

	Three Months Ended March 31, 2014	Year Ended December 31, 2013

	(in millions)
Interest expense on $ billion of newly incurred indebtedness	$	$
Amortization of debt issuance costs (see note (g))
Commitment fee on revolving credit facility


Total pro forma adjustment	$	$


Reclassification of Occidental Petroleum Corporation's net investment in us		$
New liabilities recorded on our books (see note (i))
Distributions to Occidental (see note (f))


Total additional paid-in capital		$


Anadarko Petroleum Corporation		Devon Energy Corporation
Apache Corporation		EOG Resources, Inc.
Canadian Natural Resources Limited		ExxonMobil Corporation
Chevron Corporation		Hess Corporation
ConocoPhillips		Marathon Oil Corporation
Total S.A.

		Page

SUMMARY			1
RISK FACTORS			28
FORWARD-LOOKING STATEMENTS			43
THE SPIN-OFF			45
TRADING MARKET			56
DIVIDEND POLICY			58
CAPITALIZATION			59
SELECTED HISTORICAL COMBINED FINANCIAL DATA			60
UNAUDITED PRO FORMA COMBINED FINANCIAL DATA			61
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			70
BUSINESS			83
MANAGEMENT			122
EXECUTIVE COMPENSATION			124
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			135
ARRANGEMENTS BETWEEN OCCIDENTAL AND OUR COMPANY			136
OTHER RELATED PARTY TRANSACTIONS			140
DESCRIPTION OF MATERIAL INDEBTEDNESS			142
DESCRIPTION OF CAPITAL STOCK			143
WHERE YOU CAN FIND MORE INFORMATION			148
GLOSSARY OF TECHNICAL TERMS			149
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION			F-1


Dividend Policy		We intend to pay a cash dividend of $0.01 per share per quarter, or $0.04 per share per year. We do not anticipate increasing the dividend on our common stock in the foreseeable future as we currently intend to retain the remainder of our future earnings to support the growth and development of our business. In addition, we will be authorized to implement a share repurchase program if circumstances warrant. See "Dividend Policy."
Transfer Agent		.


Cash received from incurrence of new debt, net of debt issuance costs (see note (g))		$
Cash paid to Occidental as capital distribution


Cash pro forma adjustment		$



Oil as a percentage of average WTI	106	%	110	%	109	%
NGLs as a percentage of average WTI	51	%	56	%	74	%
Gas as a percentage of NYMEX	102	%	105	%	105	%

	Payments Due by Year

Contractual Obligations(a)	Total		2014		2015 and 2016		2017 and 2018		2019 and thereafter
	(in millions)
On-Balance Sheet
Long-term liabilities(b)	$	117	$	—	$	7	$	8	$	102
Off-Balance Sheet
Operating leases		33		9		11		9		4
Purchase obligations(c)		653		247		123		260		23


Total	$	803	$	256	$	141	$	277	$	129

																			2014 Projected Development Drilling Capital ($MM)(3)

	Acreage (in millions)												Identified Drilling Locations(1)				2014 Projected Gross Development Wells(2)
					Gross Acreage Held in Fee (%)					Average Working Interest (%)
								Producing Wells, gross
	Gross		Net					Producing Wells, gross					Gross		Net
San Joaquin basin(4)		1.8		1.5		59	%		5,764		90	%		12,836		11,127		975	$	932
Los Angeles basin(5)		<0.1		<0.1		73	%		1,382		95	%		1,537		1,478		175		394
Ventura basin		0.3		0.3		77	%		780		98	%		2,310		1,716		32		73
Sacramento basin		0.6		0.5		36	%		729		100	%		1,008		864		7		6


Total		2.7		2.3		56	%		8,655		92	%		17,691		15,185		1,189	$	1,405

	At December 31, 2013

PV-10 of proved reserves (in millions)(1)	$	14,018
Standardized measure (in millions)	$	9,223



Oil
Gross(a)(b)	9,353	(1,066	)	1,562	(56	)	1,684	(32	)	—	—		12,599	(1,154	)
Net(a)(c)	8,237	(833	)	1,459	(51	)	1,622	(31	)	—	—		11,318	(915	)
Gas
Gross(a)(b)	382	(104	)	8	—		—	—		1,053	(52	)	1,443	(156	)
Net(a)(c)	333	(87	)	8	—		—	—		937	(46	)	1,278	(133	)

	San Joaquin Basin

	(in thousands)
Developed(1)
Gross(2)		409	11	63	268	751
Net(3)		375	11	60	246	692
Undeveloped(4)
Gross(2)		1,383	16	234	365	1,998
Net(3)		1,110	10	196	288	1,604



Exploratory and development wells
Gross	23	10	—	—	33
Net	21	9	—	—	30

	Amount and Nature of Beneficial Ownership

Name of Beneficial Owner	Number	Percentage


All executive officers and directors as a group ( persons)

		Page

Interim unaudited combined condensed financial statements
Combined Condensed Balance Sheets as of March 31, 2014 and December 31, 2013 (unaudited)			F-2
Combined Condensed Statements of Income for the three months ended March 31, 2014 and 2013 (unaudited)			F-3
Combined Condensed Statements of Comprehensive Income for the three months ended March 31, 2014 and 2013 (unaudited)			F-4
Combined Condensed Statements of Cash Flows for the three months ended March 31, 2014 and 2013 (unaudited)			F-5
Notes to Combined Condensed Financial Statements (unaudited)			F-6
Annual audited combined financial statements
Report of Independent Registered Public Accounting Firm			F-10
Combined Balance Sheets as of December 31, 2013 and 2012			F-11
Combined Statements of Income for the Years Ended December 31, 2013, 2012 and 2011			F-12
Combined Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011			F-13
Combined Statements of Net Investment for the Years Ended December 31, 2013, 2012 and 2011			F-14
Combined Statement of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011			F-15
Notes to Combined Financial Statements			F-16
Supplemental Financial Information
Supplemental Oil and Gas Information (unaudited)			F-33

	2014					2013

Net Periodic Benefit Costs	Pension Benefits			Postretirement Benefits		Pension Benefits			Postretirement Benefits
Service cost	$	1		$	4	$	1		$	5
Interest cost		1			3		1			3
Expected return on plan assets		(1	)		—		(1	)		—
Recognized actuarial loss		—			1		1			2


Total	$	1		$	8	$	2		$	10

	2014		2013

Sales	$	1,098	$	1,024
Allocated costs for services provided by affiliates	$	36	$	28
Purchases	$	21	$	12

	2013			2012		2011

	(in millions)
Net income	$	869		$	699	$	971
Other comprehensive income (loss) items:
Unrealized (losses) gains on derivatives(a)		(2	)		3		—
Pension and postretirement gains (losses)(b)		27			2		(10	)
Reclassification to income of realized (gains) losses on derivatives(c)		(2	)		—		—


Other comprehensive income (loss), net of tax		23			5		(10	)


Comprehensive income	$	892		$	704	$	961

	2013			2012			2011

	(in millions)
Balance—Beginning of Year	$	18		$	63		$	24
Additions to capitalized exploratory well costs pending the determination of proved reserves		46			62			85
Reclassifications to property, plant and equipment based on the determination of proved reserves		(31	)		(61	)		(34	)
Capitalized exploratory well costs charged to expense		(15	)		(46	)		(12	)


Balance—End of Year	$	18		$	18		$	63

	Amount

	(in millions)
2014	$	9
2015		6
2016		5
2017		5
2018		4
Thereafter		4


Total minimum lease payments	$	33

For the years ended December 31,	United States Federal			State and Local		Total

	(in millions)
2013
Current	$	227		$	91	$	318
Deferred		222			38		260


	$	449		$	129	$	578




2012
Current	$	(140	)	$	19	$	(121	)
Deferred		518			85		603


	$	378		$	104	$	482




2011
Current	$	22		$	62	$	84
Deferred		504			82		586


	$	526		$	144	$	670

	2013					2012

Tax effects of temporary differences	Deferred Tax Assets		Deferred Tax Liabilities			Deferred Tax Assets		Deferred Tax Liabilities
	(in millions)
Property, plant and equipment differences	$	—	$	(3,583	)	$	—	$	(3,270	)
Postretirement benefit accruals		14		—			28		—
Deferred compensation and benefits		60		—			46		—
Asset retirement obligations		182		—			170		—
Federal benefit of state income taxes		208		—			170		—
All other		22		(2	)		31		(2	)


Total deferred taxes	$	486	$	(3,585	)	$	445	$	(3,272	)

	Pension Benefits						Postretirement Benefits

	As of December 31,
	2013			2012			2013			2012
Amounts recognized in the consolidated balance sheet:
Accrued liabilities	$	—		$	—		$	(1	)	$	(1	)
Other long-term liabilities		(12	)		(34	)		(62	)		(73	)


	$	(12	)	$	(34	)	$	(63	)	$	(74	)




AOCI included the following after-tax balances:
Net loss	$	19		$	31		$	4		$	19

	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		3		—		—		3
Growth funds		3		—		—		3
Guaranteed deposit account		—		—		9		9


Total pension plan assets(b)	$	14	$	69	$	9	$	92