S-4/A 1 forms-40302151.htm S-4/A FormS-4030215 (1)
        


As filed with the Securities and Exchange Commission on March 30, 2015
Registration No. 333-202704       

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 1
to
FORM S-4
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933
California Resources Corporation*
(Exact name of registrant as specified in its charter)
 
   
 
Delaware
1311
46-5670947
(State or other jurisdiction of
incorporation or organization)
(Primary Standard Industrial
Classification Code Number)
(I.R.S. Employer
Identification Number)
 
 
 
 
10889 Wilshire Blvd.
Los Angeles, California 90024
(888) 848 4754
 
(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)
 
   
 
Michael L. Preston
Executive Vice President, General Counsel and Corporate Secretary
10889 Wilshire Blvd.
Los Angeles, California 90024
(888) 848-4754
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
 
   
 
 
Copy to: 
Sarah K. Morgan
Vinson & Elkins L.L.P.
First City Tower
1001 Fannin, Suite 2500
Houston, Texas 77002-6760
(713) 758-2222
 
    
*
Includes subsidiaries of California Resource Corporation identified in the Table of Additional Registrant Guarantors below.
Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this registration statement.
If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o    Accelerated filer o        Non-accelerated filer x    Smaller reporting company o
(Do not check if a smaller reporting company)






If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:
Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer)    o
Exchange Act Rule 14d-1(d) (Cross-Border Third Party Tender Offer)    o

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.




Due to a filing error, the Registration Statement on Form S-4 (333-202704), filed on March 12, 2015 by California Resources Corporation and the Additional Registrant Guarantors referenced therein was filed on behalf of California Resources Corporation, and was not filed on behalf of the following Additional Registrant Guarantors: California Heavy Oil, Inc., California Resources Elk Hills, LLC, California Long Beach, Inc., California Resources Petroleum Corporation, California Resources Production Corporation, California Resources Tidelands, Inc., California Resources Wilmington, LLC, CRC Construction Services, LLC, CRC Marketing, Inc., CRC Services, LLC, Elk Hills Power, LLC, Socal Holding, LLC, Southern San Joaquin Production, Inc., Thums Long Beach Company, and Tidelands Oil Production Company. The filing is hereby amended to add the foregoing as Additional Registrant Guarantors. There have been no other changes to the previously filed Registration Statement other than those changes made to correct such filing error.






TABLE OF ADDITIONAL REGISTRANT GUARANTORS
The following are additional Registrants that guarantee the notes:
Exact Name of Registrant Guarantor(1)
State or Other Jurisdiction of Incorporation or Organization
IRS Employer Identification Number
California Heavy Oil, Inc.
Delaware
98-0234630
California Resources Elk Hills, LLC
Delaware
95-4657310
California Resources Long Beach, Inc.
Delaware
95-4236046
California Resources Petroleum Corporation
Delaware
30-0339218
California Resources Production Corporation
Delaware
77-0535342
California Resources Tidelands, Inc.
Delaware
20-4110192
California Resources Wilmington, LLC
Delaware
20-4110263
CRC Construction Services, LLC
Delaware
47-3127030
CRC Marketing, Inc.
Delaware
46-5660941
CRC Services, LLC
Delaware
46-5676989
Elk Hills Power, LLC
Delaware
95-4729983
Socal Holding, LLC
Delaware
46-5693524
Southern San Joaquin Production, Inc.
Delaware
37-1694423
Thums Long Beach Company
Delaware
95-2381774
Tidelands Oil Production Company
Texas
33-0335764
    
(1)
The address for the additional registrant guarantors is 10889 Wilshire Blvd., Los Angeles, California 90024, and the telephone number for the registrant guarantors is (888) 848-4754. The Primary Industrial Classification Code for each of the registrant guarantors is 1311 except Elk Hills Power, LLC for which the code is 4991.






Subject to completion, dated , 2015
The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the United States Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
California Resources Corporation
    
Offer to Exchange up to
$1,000,000,000 Principal Amount Outstanding of 5% Senior Notes due 2020,
$1,750,000,000 Principal Amount Outstanding of 5 1/2% Senior Notes due 2021, and
$2,250,000,000 Principal Amount Outstanding of 6% Senior Notes due 2024
That Have Not Been Registered Under
The Securities Act of 1933
For
$1,000,000,000 Principal Amount Outstanding of 5% Senior Notes due 2020,
$1,750,000,000 Principal Amount Outstanding of 5 1/2% Senior Notes due 2021, and
$2,250,000,000 Principal Amount Outstanding of 6% Senior Notes due 2024
That Have Been Registered Under
The Securities Act of 1933
This Exchange Offer will expire at 5:00 p.m.,
New York City time, on 2015, unless extended.
    
California Resources Corporation is offering to exchange registered 5% Senior Notes due 2020 (the “2020 exchange notes”), 5 1/2% Senior Notes due 2021 (the “2021 exchange notes”) and 6% Senior Notes due 2024 (the “2024 exchange notes”) or collectively, the “exchange notes,” for any and all of the relevant series of its unregistered 5% Senior Notes due 2020 (the “2020 original notes”), 5 1/2% Senior Notes due 2021 (the “2021 original notes”) and 6% Senior Notes due 2024 (the “2024 original notes”), or collectively, the “original notes,” that were issued pursuant to a private placement on October 1, 2014. We refer to the original notes and the exchange notes together in this prospectus as the “Notes” or “notes.” We refer to the offer to exchange the 2020 exchange notes for the 2020 original notes, the offer to exchange the 2021 exchange notes for the 2021 original notes, and the offer to exchange the 2024 exchange notes for the 2024 original notes collectively as the “exchange offer.” The terms of the exchange notes are substantially identical to the relevant series of original notes except the exchange notes are registered under the Securities Act of 1933, as amended (the “Securities Act”), and the transfer restrictions and registration rights, and related special interest provisions, applicable to the original notes will not apply to the exchange notes. The exchange notes will represent the same debt as the relevant series of original notes, and we will issue the exchange notes under the same indenture used in issuing the original notes.
Terms of the exchange offer:
The exchange offer expires at 5:00 p.m., New York City time, on               , 2015, unless we extend it.
The exchange offer is subject to customary conditions, which we may waive.


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We will exchange all outstanding original notes that are validly tendered and not withdrawn prior to the expiration of the exchange offer for an equal principal amount of the relevant series of exchange notes. All interest due and payable on the original notes will become due and payable on the same terms under the relevant series of exchange notes.
You may withdraw your tender of original notes at any time prior to the expiration of the exchange offer.
If you fail to tender your original notes, you will continue to hold unregistered, restricted securities, and your ability to transfer them could be adversely affected.
We believe that the exchange of original notes for exchange notes will not be a taxable event for U.S. federal income tax purposes, but you should see the discussion under the caption “Certain United States Federal Income Tax Considerations” for more information.
We will not receive any proceeds from the exchange offer.
    
See “Risk Factors” beginning on page 9 for a discussion of risks you should consider in connection with the exchange offer and the exchange notes.
Each broker-dealer that receives exchange notes pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of exchange notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, such broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of the exchange notes received in exchange for original notes where such original notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. Until             , 2015 all dealers that effect transactions in the exchange notes, whether or not participating in this exchange offer, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions. We have agreed that, until , 2015, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “The Exchange Offer—Purpose and Effects of the Exchange Offer” and “Plan of Distribution.”
    
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
You should read this entire document and the accompanying letter of transmittal and related documents and any amendments or supplements carefully before making your decision to participate in the exchange offer.
    
The date of this prospectus is , 2015.


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TABLE OF CONTENTS
Cautionary Note Regarding Forward-Looking Statements
iv
Notice To New Hampshire Residents Only
v
Industry and Market Data
v
About This Prospectus
v
Prospectus Summary
1
Risk Factors
9
The Exchange Offer
22
Use of Proceeds
31
Capitalization
31
Selected Financial Data
32
Management’s Discussion and Analysis of Financial Condition and Results of Operations
33
Business
52
Management
80
Executive Compensation
87
Executive Compensation Tables
99
Certain Relationships and Related Party Transactions
111
California Resources Corporation and Subsidiaries Computation of Total Enterprise Ratio of Earnings to Fixed Charges
118
Description of Exchange Notes
119
Book-Entry; Delivery and Form
139
Certain United States Federal Income Tax Considerations
142
Plan of Distribution
143
Legal Matters
144
Independent Registered Public Accounting Firm
144
Independent Petroleum Engineers
144
Where You Can Find More Information
144
Index to Financial Statements and Supplementary Information
F - 1




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YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS AND IN THE ACCOMPANYING LETTER OF TRANSMITTAL. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH ANY OTHER OR DIFFERENT INFORMATION. IF YOU RECEIVE ANY UNAUTHORIZED INFORMATION, YOU MUST NOT RELY ON IT. THIS PROSPECTUS MAY ONLY BE USED WHERE IT IS LEGAL TO EXCHANGE THE ORIGINAL NOTES FOR THE EXCHANGE NOTES, AND THIS PROSPECTUS IS NOT AN OFFER TO EXCHANGE OR A SOLICITATION TO EXCHANGE THE ORIGINAL NOTES FOR THE EXCHANGE NOTES IN ANY JURISDICTION WHERE AN OFFER OR EXCHANGE WOULD BE UNLAWFUL. YOU SHOULD ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS ACCURATE ONLY AS OF THE DATE OF THIS PROSPECTUS.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
The information in this prospectus 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 investments, projected production growth, projected costs, plans and objectives of management for future operations and possible future strategic transactions. For any such forward-looking statement that 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 prospectus.
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:
commodity pricing;
vulnerability to economic downturns and adverse developments in our business due to our debt;
insufficiency of our operating cash flow to fund planned capital investments;
inability to implement our capital investment program profitably or at all;
compliance with regulations or changes in regulations and the ability to obtain government permits and approvals;
uncertainties associated with drilling for and producing oil and natural gas;
tax law changes;
competition for oilfield equipment, services, qualified personnel and acquisitions;
the subjective nature of estimates of proved reserves and related future net cash flows;
concentration of operations in a single geographic area;
restrictions on our ability to obtain, use, manage or dispose of water;
inability to drill identified locations when planned or at all;
concerns about climate change and other air quality issues;
risks related to our acquisition activities;


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catastrophic events for which we may be uninsured or underinsured;
cyber attacks;
operational issues that restrict market access; and
uncertainties related to the Spin-off, the agreements related thereto and the anticipated effects of restructuring or reorganizing our business.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Unless legally required, 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.
NOTICE TO NEW HAMPSHIRE RESIDENTS ONLY
NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES ("RSA") WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE OF NEW HAMPSHIRE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXCEPTION OR EXEMPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CUSTOMER OR CLIENT, ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.
INDUSTRY AND MARKET DATA
The market data and certain other statistical information used throughout this prospectus includes industry data and forecasts that are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third‑party sources are reliable as of their respective dates, we have not independently verified the accuracy or completeness of this information. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section of this prospectus entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.
ABOUT THIS PROSPECTUS
We have filed a registration statement on Form S-4 with respect to the exchange notes with the SEC. This prospectus, which forms part of such registration statement, does not contain all the information included in the registration statement, including its exhibits and schedules. For further information about us and the notes described in this prospectus, you should refer to the registration statement and its exhibits and schedules. Statements we make in this prospectus about certain contracts or other documents are not necessarily complete.
When we make such statements, we refer you to the copies of the contracts or documents that are filed as exhibits to the registration statement, because those statements are qualified in all respects by reference to those exhibits. The registration statement, including the exhibits and schedules, is available at the SEC’s website at www.sec.gov.


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We have not authorized anyone to give any information or to make any representations concerning the exchange offer except that which is in this prospectus. If anyone gives or makes any other information or representation, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy securities in any circumstances in which the offer or solicitation is unlawful. You should not interpret the delivery of this prospectus, or any sale of securities, as an indication that there has been no change in our affairs since the date of this prospectus. You should also be aware that information in this prospectus may change after its date.
We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available over the Internet at the SEC’s website at www.sec.gov. You may also read and copy any document that we file at the SEC’s public reference room at 100 F. Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for more information on the public reference room and its copy charges.
You may also obtain documents referenced in this prospectus without charge by writing or telephoning us at the following address and telephone number:
California Resources Corporation
Attention: Investor Relations
10889 Wilshire Blvd.
Los Angeles, California 90024
Phone: (888) 848-4754
You will not be charged for any of these documents that you request. In order to ensure timely delivery of the documents, any request should be made at least five days prior to the Expiration Date (as defined herein).



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PROSPECTUS SUMMARY
This summary highlights selected information about us and the exchange offer contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information that may be important to you or that you should consider before participating in the exchange offer or making an investment in the exchange notes. To understand the exchange offer fully and for a more complete description of the legal terms of the exchange notes, you should carefully read this entire prospectus, particularly the risks of investing in the exchange notes discussed under “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our audited and unaudited historical consolidated and combined financial statements and the notes thereto included elsewhere in this prospectus and the accompanying letter of transmittal.
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 and (2) all references to “Occidental” refer to Occidental Petroleum Corporation, our former parent, and its subsidiaries. Except as otherwise indicated or unless the context otherwise requires, references in this prospectus to drilling locations are to “gross” drilling locations and exclude our prospective resource drilling locations.
Our Company
We are an independent oil and natural gas exploration and production company operating properties exclusively within the State of California. Our business is focused on conventional and unconventional assets, exclusively in California, which can generate positive cash flow throughout the oil and natural gas price cycle and have the capacity to provide significant production and cash flow growth in a higher price environment. We are the largest oil and gas 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 2.4 million net acres spanning the state’s four major oil and natural gas basins. We produced on average approximately 159 MBoe/d net for the year ended December 31, 2014. As of December 31, 2014, we had proved reserves of 768 MMBoe, with approximately 72% proved developed. Oil represented 72% of our proved reserves. Our aggregate PV-10 value was $16.1 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 “Our Reserves and Production Information" section below. Our current drilling inventory comprises a diversified portfolio of oil and natural gas locations, which allows us to target drilling projects that are economically viable even in a low commodity price environment.
On November 30, 2014, our company was separated from Occidental in a series of transactions (the consummation of such transactions, the “Spin-off”). Prior to the Spin-off, we were an indirect, wholly-owned subsidiary of Occidental. In connection with the Spin-off, Occidental transferred its California oil and gas exploration and production operations and related assets, liabilities and obligations to us. On November 30, 2014, Occidental distributed shares of our common stock pro rata to Occidental stockholders and we became an independent, publicly traded company. Occidental retained approximately 18.5% of our outstanding shares of common stock, which it has stated it intends to divest within 18 months after November 30, 2014.
Our principal executive offices are located at 10889 Wilshire Boulevard, Los Angeles, California 90024. Our telephone number is (888) 848-4754. Our website is located at www.crc.com. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.


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Summary of the Exchange Offer
On October 1, 2014, we completed an unregistered offering of the original notes. As part of that offering, we entered into a registration rights agreement with the initial purchasers of the original notes, which we refer to as the registration rights agreement, in which we agreed, among other things, to offer to exchange the original notes for the exchange notes. The following is a summary of the principal terms of the exchange offer. A more detailed description is contained in the section of this prospectus titled “The Exchange Offer.”
Original Notes
5% senior notes due 2020 (“2020 original notes”), 5½% senior notes due 2021 (“2021 original notes”), and 6% senior notes due 2024 (“2024 original notes”), which were issued by California Resources Corporation in a private placement on October 1, 2014.
Exchange Notes
5% senior notes due 2020 (“2020 exchange notes”), 5½% senior notes due 2021 (“2021 exchange notes”), and 6% senior notes due 2024 (“2024 exchange notes”), issued by California Resources Corporation. The terms of the exchange notes are substantially identical to the related original notes except the exchange notes are registered under the Securities Act of 1933, as amended (the "Securities Act"), and the transfer restrictions and registration rights, and related special interest provisions, applicable to the original notes will not apply to the exchange notes. The exchange notes will represent the same debt as the related original notes, and we will issue the exchange notes under the same indenture used in issuing the original notes.
Exchange Offer
We are offering to exchange up to $5.0 billion in aggregate principal amount of our exchange notes that have been registered under the Securities Act for an equal aggregate principal amount of our original notes. You may exchange your 2020 original notes for 2020 exchange notes, your 2021 original notes for 2021 exchange notes and your 2024 original notes for 2024 exchange notes.
Expiration Date
The exchange offer will expire at 5:00 p.m., New York City time, on            , 2015, which we refer to as the “Expiration Date,” unless we decide to extend it or terminate it early. We do not currently intend to extend the exchange offer. We will issue the exchange notes on the Expiration Date or promptly after that date. A tender of original notes pursuant to this exchange offer may be withdrawn at any time on or prior to the Expiration Date if we receive a valid written withdrawal request before the expiration of the exchange offer.
Conditions to the Exchange Offer
The exchange offer is subject to customary conditions which include, among other things, the absence of any applicable law or any applicable interpretation of the staff of the Securities and Exchange Commission ("SEC") which, in our reasonable judgment, would materially impair our ability to proceed with the exchange offer. The exchange offer is not conditioned upon any minimum principal amount of original notes being submitted for exchange. Please see “The Exchange Offer—Conditions to the Exchange Offer” for more information regarding the conditions to the exchange offer.


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Procedures for Tendering Original Notes
All of the original notes are held in book-entry form through the facilities of the Depository Trust Company (“DTC”). To participate in the exchange offer, you must follow the Automated Tender Offer Program (“ATOP”) procedures established by DTC for tendering original notes held in book-entry form. The ATOP procedures required that the exchange agent receive, prior to the expiration date of the exchange offer, a computer-generated message known as an “agent’s message” that is transmitted through ATOP and that DTC confirm that:
DTC has received instructions to exchange your original notes; and
you agree to be bound by the terms of the letter of transmittal.
By using the ATOP procedures and thus binding yourself to the terms of the letter of transmittal, you will represent to us that, among other things:
you are acquiring exchange notes in the ordinary course of your business;
you have no arrangement or understanding with any person or entity to participate in a distribution of the exchange notes;
you are not our “affiliate” as defined in Rule 405 of the Securities Act;
if you are not a broker-dealer, that you are not engaged in, and do not intend to engage in, the distribution of the exchange notes; and
if you are a broker-dealer that will receive exchange notes for your own account in exchange for original notes that were acquired by you as a result of market-making or other trading activities, that you will deliver a prospectus in connection with any resale of such exchange notes.
If you are a broker-dealer, you may not participate in the exchange offer as to any original notes you purchased directly from us.
Special Procedures for Beneficial Owners
Beneficial owners of original notes should contact their broker, dealer, commercial bank, trust company or other nominee for assistance in tendering their original notes in the exchange offer. If you wish to tender on your own behalf, you must, before instructing such nominee to tender and deliver original notes on your behalf, either arrange to have your original notes registered in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take a long time.
Guaranteed Delivery Procedures
None.




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Acceptance of Original Notes and
If you comply with the procedures of the exchange offer we will
Delivery of Exchange Notes
accept for exchange any and all original notes that are properly tendered in the exchange offer and not validly withdrawn prior to the Expiration Date. The exchange notes will be delivered promptly after the Expiration Date.

Withdrawal; Non-Acceptance
You may withdraw any original notes tendered in the exchange offer by sending a notice of withdrawal to the exchange agent using the ATOP procedures at any time prior to the Expiration Date. Any withdrawn original notes will be credited to the tendering holders’ account at DTC. For further information regarding the withdrawal of tendered original notes, please see “The Exchange Offer—Withdrawal of Tenders.” If any tendered original notes are not accepted for exchange because they do not comply with the procedures set forth in this prospectus and the accompanying letter of transmittal, or because of our withdrawal of the exchange offer, the occurrence of certain other events set forth herein or otherwise, such unaccepted original notes will be returned, without expense, to the tendering holder promptly after the Expiration Date or our withdrawal of the exchange offer. For further information regarding conditions to the exchange offer, please see “The Exchange Offer—Conditions to the Exchange Offer.”
Accounting Treatment
We will not recognize a gain or loss for accounting purposes as a result of the exchange offer.
Certain United States Federal Income
The exchange of original notes for exchange notes in the exchange
Tax Considerations
offer will not be a taxable event for U.S. federal income tax purposes. Please see "Certain United States Federal Income Tax Considerations" for more information regarding the tax consequences to you of the exchange offer.

Use of Proceeds
The issuance of the exchange notes will not provide us with any proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement we entered into with the initial purchasers of the original notes.
Fees and Expenses
We will pay all expenses incident to the exchange offer. Please see “The Exchange Offer—Fees and Expenses” for more information regarding payment of fees and expenses related to the exchange offer.
Exchange Agent; Paying Agent and Registrar
Wells Fargo Bank, National Association is serving as the exchange agent in connection with the exchange offer and will initially act as paying agent and registrar for the exchange notes. Wells Fargo Bank, National Association also serves as trustee under the indenture governing the notes. You can find the address and telephone number of the exchange agent elsewhere in this prospectus under the caption “The Exchange Offer—Exchange Agent.”
Not Exchanging Your Original Notes
If you do not exchange your original notes in this exchange offer, you will continue to hold unregistered original notes and you will


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no longer be entitled to registration rights or the special interest provisions related thereto. See “The Exchange Offer—Consequences of Failure to Exchange.” In addition, while your original notes will continue to accrue interest until maturity in accordance with the terms of the original notes, you will not be able to resell, offer to resell or otherwise transfer your original notes unless you do so in a transaction exempt from the registration requirements of the Securities Act and applicable state securities laws or unless we register the offer and resale of your original notes under the Securities Act. Following the exchange offer, we will be under no obligation to, and we do not intend to, register your original notes. As a result of such restrictions, and the availability of registered exchange notes, your original notes are likely to be a much less liquid security than before.
Additional Documentation; Further
Any questions of requests for assistance or additional
Information; Assistance
documentation regarding the exchange offer may be directed to the exchange agent.



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The Exchange Notes
The terms of the exchange notes and those of the outstanding original notes are substantially identical, except that the exchange notes are registered under the Securities Act, and the transfer restrictions and registration rights, and related special interest provisions, applicable to the original notes will not apply to the exchange notes. The exchange notes represent the same debt as the original notes for which they are being exchanged. Both the original notes and the exchange notes are governed by the same indenture. The brief summary below describes the principal terms of the exchange notes. Some of the terms and conditions described below are subject to important limitations and exceptions. The “Description of Exchange Notes” section of this prospectus contains a more detailed description of the terms and conditions of the exchange notes.
Issuer
California Resources Corporation.
Exchange Notes Offered
We are offering $5.0 billion aggregate principal amount of notes registered under the Securities Act of the following series:
$1,000,000,000 aggregate principal amount of 5% senior notes due 2020;
$1,750,000,000 aggregate principal amount of 5 1/2% senior notes due 2021; and
$2,250,000,000 aggregate principal amount of 6% senior notes due 2024.
Maturity Date
The 2020 exchange notes will mature on January 15, 2020, the 2021 exchange notes will mature on September 15, 2021 and the 2024 exchange notes will mature on November 15, 2024.
Interest
The 2020 exchange notes will bear interest at a rate of 5% per annum, the 2021 exchange notes will bear interest at a rate of 5 1/2% per annum and the 2024 exchange notes will bear interest at a rate of 6% per annum.
Interest Payment Dates
Interest on the 2020 exchange notes will be paid semi-annually in arrears on January 15 and July 15 of each year, beginning on July 15, 2015. Interest on the 2021 exchange notes will be paid semi-annually in arrears on March 15 and September 15 of each year, beginning on March 15, 2015. Interest on the 2024 exchange notes will be paid semi-annually in arrears on May 15 and November 15 of each year, beginning on May 15, 2015.
Guarantees
The exchange notes will initially be fully and unconditionally guaranteed on a senior unsecured basis by all of our material subsidiaries. Please see “Description of Exchange Notes—Certain Covenants— Guarantees” and “Description of Exchange Notes—Guarantees.”
Ranking
The exchange notes will be our general senior unsecured obligations and will rank:
pari passu in right of payment with any of our senior unsecured indebtedness, including indebtedness incurred under our Revolving Credit Facility and our Term Loan


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Facility (each as defined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Credit Facilities”);
effectively junior to any of our future secured indebtedness and other obligations to the extent of the value of the collateral securing such indebtedness and obligations;
structurally subordinated to any indebtedness and other liabilities (other than indebtedness and liabilities owed to us) of our subsidiaries that do not guarantee the exchange notes; and
senior in right of payment to any of our future subordinated indebtedness.
As of December 31, 2014, we and our subsidiaries had approximately $6.36 billion of consolidated indebtedness, comprised of $5.0 billion of original notes, $1.0 billion of borrowings outstanding under our Term Loan Facility and $360 million of borrowings outstanding under our Revolving Credit Facility. We currently have the ability to incur total net borrowings of up to $1.25 billion under our Revolving Credit Facility. In addition, as of December 31, 2014 we had letters of credit in an aggregate amount of $25 million that were issued to support ordinary course marketing, regulatory and other matters under uncommitted letter of credit lines.
Non-guarantor subsidiaries represented less than 1% of our total assets and had no indebtedness as of December 31, 2014, and represented less than 1% of revenues for the twelve months ended December 31, 2014.
Optional Redemption
We may redeem the exchange notes of each series, in whole or in part, at any time and from time to time, at our option at the applicable redemption prices set forth under “Description of Exchange Notes—Optional Redemption.”
Offer to Repurchase Following
If we experience a change of control (as defined in the indenture
Change of Control
governing the exchange notes) accompanied by a ratings decline with respect to a series of exchange notes, we must offer to repurchase the exchange notes of such series at 101% of their principal amount, plus accrued and unpaid interest. See “Description of Exchange Notes—Change of Control.”

Certain Covenants
The indenture governing the exchange notes, among other things, restricts our ability, and our restricted subsidiaries’ ability, to incur debt secured by liens. These covenants will also restrict our ability to merge or consolidate with, or transfer all or substantially all of our assets to, another entity. These and other covenants that are contained in the indenture are subject to important exceptions and qualifications, which are described under “Description of Exchange Notes.”


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No Prior Market
The exchange notes will be new securities for which there is currently no market. Although the initial purchasers have informed us that they intend to make a market in the exchange notes, they are not obligated to do so and may discontinue market-making at any time without notice. Accordingly, we cannot assure you that a liquid market for the exchange notes will develop or be maintained.
Book-Entry Form
The exchange notes will be issued in book-entry form and will be represented by one or more global securities registered in the name of Cede & Co., as nominee for The Depository Trust Company, or DTC. Beneficial interests in the exchange notes will be evidenced by, and transfers will be effected only through, records maintained by DTC participants.
Form and Denomination
The exchange notes will be issuable in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.
Risk Factors
You should consider carefully all the information included and incorporated by reference in this prospectus and, in particular, you should evaluate the specific factors set forth under “Risk Factors” in this prospectus, before deciding whether to participate in the exchange offer.





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RISK FACTORS
You should carefully consider the information included in this prospectus, including the matters addressed under “Cautionary Note Regarding Forward-Looking Statements,” and the following risks before deciding to exchange your original notes for exchange notes pursuant to this exchange offer.
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 and results of operations, 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 and results of operations.
Risks Related to Our Business
Commodity pricing can fluctuate widely and 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. Recently, global energy commodity prices have declined significantly. For example, Brent crude prices declined from over $115 per barrel in June 2014 to below $47 per barrel in January 2015. In a declining price environment we may incur costs to terminate drilling rig contracts, and may be required to write-down property values, such as we did in recent months. Product prices can fluctuate widely and are affected by a variety of factors, including changes in consumption patterns, global and local (particularly for natural gas) economic conditions, the actions of OPEC and other oil and natural gas producing countries, inventory levels, actual or threatened production disruptions, 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, natural gas and NGLs, and the effect of changes in market perceptions. These and other factors make it impossible to predict realized prices reliably. 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.
Any sustained periods of low prices for oil and natural gas may materially and adversely affect our financial position, the quantities of natural gas and oil reserves that we can economically produce, our cash flow available for capital investments and our ability to access funds under our revolving credit facility and through the capital markets.
We 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.
As of December 31, 2014, we had $6.36 billion of consolidated indebtedness, comprising $5.0 billion of senior notes, $1.0 billion of borrowings outstanding under our Term Loan Facility and $360 million of borrowings outstanding under our Revolving Credit Facility, and we had the ability to incur $1.64 billion of additional borrowings under our Revolving Credit Facility, which has effectively been reduced under the first amendment to our credit facilities discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources". As of December 31, 2014, we had letters of credit in an aggregate amount of approximately $25 million that were issued to support ordinary course marketing, regulatory and other matters. In addition, the indenture relating to the notes and the Credit Facilities (as defined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources-Credit Facilities”) permits us to incur certain defined obligations, unrestricted by debt incurrence or lien covenants, or that do not constitute indebtedness (as defined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities”).
Indebtedness outstanding under our Credit Facilities bears interest at a variable rate, therefore a rise in interest rates will generate greater interest expense if and to the extent we do not purchase interest rate hedges.
Our level of indebtedness will have several important effects on our future operations, including, without limitation:
increasing our vulnerability to adverse changes in our business and to general economic and industry conditions, and putting us at a disadvantage against other competitors that have lower fixed obligations and more cash flow to devote to their businesses;
limiting our ability to obtain additional financing for working capital, capital investments, general corporate and other purposes; and

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limiting our flexibility in operating our business and preventing us from engaging in certain transactions that might otherwise be beneficial to us.
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 may be unattractive 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. Any of these factors could result in a material adverse effect on our business, financial condition, results of operations, cash flow and ability to satisfy our obligations under the notes.
Our business requires substantial capital investments. We may be unable to fund these investments 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 investments for the development and exploration of oil and gas reserves. We have developed a multi-year capital investment program to execute our strategy. We invested approximately $2.1 billion of capital on development and exploration activities during the year ended December 31, 2014, funded by our operating cash flow of $2.4 billion. Under our 2015 capital budget, we plan to invest approximately $420 million for development and exploration activities.
Our ability to deploy capital as planned depends on a number of variables, including: (i) commodity prices and sales point disruptions; (ii) regulatory and third-party approvals; (iii) our ability to timely drill wells due to technical factors and contract terms; (iv) the availability of capital, equipment, services and personnel; and (v) drilling and completion costs and results. Because of these and other potential variables, 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 investments, other than any significant acquisitions, primarily through cash flow from operations and, if necessary, through borrowings under our Revolving Credit Facility or the issuance of debt or equity securities. 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 exercise their discretion to expand our existing credit. In the event additional capital is needed and unavailable, we may curtail drilling, development and other activities or be forced to sell assets on an unfavorable basis.
Our business is highly regulated and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, including hydraulic fracturing and other well stimulation, enhanced production techniques and fluid disposal, that could increase costs, restrict operations and delay our implementation of, or cause us to change, our business strategy.
Our operations are subject to complex and stringent federal, state, local and other laws and regulations relating to the exploration and development of our properties, the production, transportation and sale of our products, and the services we provide. See “Business—Regulation of the Oil and Natural Gas Industry” for a description of the laws and regulations that affect our business. To operate in compliance with these laws and regulations, we must obtain and maintain permits, approvals and certificates from federal, state and local governmental authorities. 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 contamination, including on properties over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
Costs of compliance may increase or operational delays or restrictions may occur as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations. Certain government agencies have adopted or proposed new or more stringent requirements for permitting, well construction, public disclosure or environmental review of, or restrictions on, certain oil and gas operations, including drilling, well stimulation, enhanced production techniques or fluid disposal. Such new requirements or restrictions or resulting litigation could result in potentially significant added costs to comply, delay or curtail 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. For example, in 2013, California adopted SB 4, which mandated further regulation of certain well stimulation techniques, including hydraulic fracturing.

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The implementation of interim well stimulation regulations under SB 4 in 2014 delayed certain operations, and California’s implementation of final SB 4 regulations and associated studies and reports may increase costs and cause additional delays. In addition, certain local governments have proposed or adopted ordinances that purport, within their jurisdictions, to regulate certain drilling activities in general, or well stimulation or completion activities in particular, including hydraulic fracturing, or to ban such activities outright.
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, and we may increase the proportion of our drilling in new or emerging plays over time. We may not find commercial amounts of oil or natural 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.
Tax law changes may adversely affect our operations.
In California, there have been proposals for tax increases for the past several years including a severance tax as high as 12.5% on oil, natural 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 and natural gas production, which may reduce our capital investments and growth plans.
In addition, President Obama’s budget proposal for fiscal year 2016 recommended the elimination of certain federal income tax preferences currently available to oil and gas exploration and production companies, all of which could harm us. These changes include (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of expensing intangible drilling costs, (iii) an increase in the amortization period from two years to seven years for geological and geophysical costs paid or incurred by independent producers in connection with the exploration for, or development of, oil or natural gas and (iv) repeal of the ability to claim the domestic manufacturing deduction against income derived from the sale or exchange of oil, natural gas or primary products produced in the United States.
Drilling for and producing oil and natural 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 investments 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 geologists, geophysicists and engineers, and for field and other personnel to drill wells, conduct field operations and construct and maintain facilities, can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages which may increase costs for such services. Finally, competition for reserves can make it more difficult to find attractive investment opportunities or require delay of reserve replacement efforts.

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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 prospectus represents estimates prepared by internal engineers. 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 natural gas. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variables and assumptions, including:
historical production from the area compared with production from similar areas;
the quality, quantity and interpretation of available relevant data;
commodity prices;
production and operating costs;
ad valorem, excise and income taxes;
development costs;
the effects of government regulations; and
future workover and remedial costs.
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.
Our producing properties are located exclusively in California, making us vulnerable to risks associated with having operations concentrated in this geographic area.
Our operations are geographically concentrated exclusively in California. Because of this geographic concentration, the success and profitability of our operations may be disproportionately exposed to the effect of regional events. These include, among others, fluctuations in the prices of crude oil and natural gas produced from wells in the region, changes in state or regional laws and regulations affecting our operations, and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints, available rigs, equipment, oil field services, supplies, labor and infrastructure capacity. The concentration of our operations in California also increases exposure to unexpected events that may occur in this region such as natural disasters, industrial accidents or labor difficulties. Any one of these events has the potential to cause producing wells to be shut-in, delay operations and growth plans, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our financial condition, results of operations and cash flows.
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 90% of the fluids we produce are brackish waters, unsuitable for agricultural use, that need to be managed, recycled or disposed. We treat and re-use this water for a substantial portion of our needs related to activities such as steamflooding, waterflooding, pressure management, well completion and stimulation, including hydraulic fracturing, and we provide water for agricultural use in certain areas. 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 steam injection. Due to severe drought in California, some local and regional water districts and the state government are implementing policies or regulations that restrict water usage and increase the cost of water.

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Existing regulations restrict our ability and increase our cost to manage and dispose of wastewater. The federal Clean Water Act and Safe Drinking Water Act and similar state laws impose restrictions and strict controls on the discharge of produced waters and waste and the subsurface injection of fluids. We must obtain permits or waivers for certain discharges and for construction activities that may affect regulated water resources. In addition, certain government agencies have investigated and continue to study whether fluid injection 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 or private or public property. The laws, regulations, policies and attendant liabilities relating to water use, wastewater disposal and fluid injection could increase our costs and negatively affect our development and production activities.
Our Area of Mutual Interest (“AMI”) Agreement may limit our ability to operate outside of California.
In connection with the Spin-off, we entered into an AMI Agreement, which provides Occidental with the right to acquire a 51% interest in, and rights with respect to, certain oil and gas properties we acquire in the United States, other than in the State of California, for five years following the completion of the Spin-off. 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 “Certain Relationships and Related Party Transactions—Arrangements Between Occidental and Our Company—AMI Agreement.”
We may not drill our identified sites at the times we scheduled or at all and sites we decide to drill may not yield crude oil or natural gas in economically producible quantities.
We have specifically identified locations for scheduled drilling over the next several years. These drilling locations represent a significant part of our long-term 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 covered by leases expiring in the next three years represents 23% of our total net undeveloped acreage at December 31, 2014. Our actual drilling activities may materially differ from those presently identified.
The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity-price, interest-rate and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank Act"), enacted in 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, like us, that participate in that market. The Dodd-Frank Act requires the Commodities and Futures Trading Commission ("CFTC") and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when this will be accomplished.
The CFTC is authorized to set position limits for certain futures contracts in designated physical commodities and for economically equivalent options and swaps. In November 2013, the CFTC proposed rules that would place limits on positions in certain futures and equivalent swap contracts for, or linked to, certain physical commodities; subject to exceptions for certain bona fide hedging transactions. We do not know when the CFTC will finalize these regulations; therefore, the impact of those provisions on us is currently uncertain.
The CFTC designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. In addition, the Dodd-Frank Act requires that regulators establish margin rules for uncleared swaps. The application of such requirements may indirectly change the cost and availability of the swaps that we may use for hedging.
The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter or reduce our ability to monetize or restructure derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

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Our commodity-price risk-management and trading activities may prevent us from fully benefiting from price increases and may expose us to other risks.
To the extent that we engage in commodity-price risk-management activities to protect our cash flows from commodity-price declines, we may be prevented from realizing the full benefits of price increases above the levels stated in the derivative instruments used to manage price risk. In addition, our commodity-price risk-management and trading activities may expose us to the risk of financial loss in certain circumstances, including instances in which the following occur:
• our production is less than the notional volumes;
• a change in price basis differentials;
• the counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements; and
• an event materially impacts oil and natural-gas prices.
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 AB 32, which established a statewide cap on GHG emissions, including on the oil and natural gas production industry, and a “cap-and-trade” program. Since 2012, California Air Resources Board ("CARB") regulations have required us to obtain GHG emissions allowances corresponding to reported GHG emissions from operations and, starting in 2015, from the sale of certain products to customers for use in the State. In 2014, we incurred approximately $33 million to purchase mandatory GHG emissions allowances in California, and costs of such allowances are expected to increase in the future as CARB reduces the number of available allowances, increases their targeted price and covers more operations and products in the program. In addition, other CARB regulations, state policies and proposed legislation seek to restrict or reduce the use of petroleum products in transportation fuels and electricity generation in California and require the use of renewable energy, which could increase our costs and reduce the demand for our products and services.
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 and associated state laws and regulations. In addition, California air quality laws and regulations, particularly in Southern and Central California where most of our operations are located, are in many instances more stringent than comparable federal laws and regulations. As these requirements become more stringent, we may be unable to implement them in a cost-effective manner. 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 natural gas prices in recent years and oil prices in recent months; (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.

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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 natural 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 could significantly affect us.
Cyber attacks on businesses have escalated in recent years. We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. 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, natural 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, the ability of such facilities to gather, transport or process our products and regional disruptions, such as strikes and mechanical failures. If our access to markets for commodities we produce is restricted, our costs could increase and our expected production may be impaired.
Risks Related to the Spin-off
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:
enhancing our ability to grow by reinvesting substantially all of our cash flow in our business;
enhancing growth and efficiency by enabling our management team to focus its attention on the development and execution of our business in a single state;
enhancing our focus on, and accelerating our technical expertise in, specific reservoirs and fields in California; and
enhancing our market recognition with investors because of our status as an industry leader in California.
We may not achieve the anticipated benefits from our separation for a variety of reasons. We may not generate sufficient cash flow to fund our long-term growth plans and to generate acceptable returns. 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.
Our historical 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 financial information included in this prospectus has been derived partly 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 or as a separate segment 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: (i) 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; (ii) certain employee benefits and incentives; and (iii) 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

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identifiable, with the remainder allocated based on estimated time spent by Occidental personnel, headcount or our relative size compared to Occidental and its subsidiaries. The costs of operating as a stand-alone public company, other than the debt-related costs, may be slightly higher than the costs reported in the 2014 historical financial statements. These estimates may not prove to be accurate. Our capital investment requirements, including acquisitions, historically have been satisfied as part of the companywide cash management practices of Occidental. Following the Spin-off, we no longer have access to Occidental’s working capital, and we may need to obtain additional financing from banks, through public offerings or private placements of debt or equity securities or other arrangements if our cash flow from operations and our existing Credit Facilities are not sufficient to fund our capital investment requirements.
In connection with our separation from Occidental, we agreed to indemnify Occidental for certain liabilities, including those related to the operation of our business while it was still owned by Occidental, and Occidental agreed to indemnify us for certain liabilities, which indemnities may not be adequate.
Pursuant to agreements with Occidental, Occidental has indemnified us for certain liabilities, and we agreed to indemnify Occidental for certain liabilities, in each case for uncapped amounts, as discussed further in “Certain Relationships and Related Party Transactions—Arrangements Between Occidental and Our Company.” Indemnity payments that we may be required to provide Occidental may be significant and could negatively impact our business, particularly indemnity payments relating to our actions that could impact the tax-free nature of the Spin-off. Third parties could also seek to hold us responsible for 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 may 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.
Prior to the Spin-off, our operations were fully integrated within Occidental, and we 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. As part of Occidental, we were able to enjoy certain benefits from Occidental’s scale and purchasing power. As an independent, publicly traded company, we do not have similar negotiating leverage.
In addition, we are now obligated to file with the SEC annual and quarterly information and other reports, and, as a result, must 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 are now subject to other reporting and corporate governance requirements, including certain requirements of the New York Stock Exchange (the "NYSE"), and certain provisions of the Sarbanes-Oxley Act of 2002, and the regulations promulgated thereunder, which impose significant compliance obligations and costs upon 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 have agreed to take certain actions or refrain from taking certain actions to ensure that the Spin-off and certain transactions taken in preparation for, or in connection with, the Spin-off, qualify for tax-free status under the relevant provisions of the Internal Revenue Code of 1986, as amended (the “Code”). We have also made various other covenants in the Tax Sharing Agreement intended to ensure the tax-free status of the Spin-off. 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 securities retained by Occidental after the Spin-off, absent approval by Occidental, we may not enter into any transaction that would be reasonably likely to cause us to undergo either a 30% or greater change in the ownership of our voting stock or a 30% or greater change in the ownership (measured by value) of all classes of our stock. See “Certain Relationships and Related Party Transactions—Arrangements Between Occidental and Our Company—Tax Sharing Agreement.”
We have agreed to indemnify Occidental for (a) taxes incurred as a result of the failure of the Spin-off or certain transactions undertaken in preparation for, or in connection with, the Spin-off, to qualify as tax-free transactions under the relevant provisions of the Code, as amended, to the extent caused by (i) our breach of certain tax-related representations or covenants made in connection with the Spin-off, (ii) actions, failures to act and omissions inconsistent with such representations and covenants and (iii) certain permitted transactions, (b) our separate taxes due to capitalization of intangible drilling and

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development costs, (c) any finally determined increases of our liability for separate tax items included in combined or consolidated Occidental returns, and (d) 50% of certain sales, use, transfer, real property transfer, intangible, recordation, registration, documentary, stamp and similar taxes. We also have agreed to pay 50% of any taxes arising from the Spin-off or related transactions to the extent that the tax is not attributable to the fault of either party. However, if we receive an increase in the tax basis of our depletable, depreciable or amortizable assets as a result of any such tax begin imposed, we will pay to Occidental any amount equal to any reduction in our tax liability attributable to such basis increase at the time such reduction in tax liability arises. In addition, we have agreed to indemnify Occidental and its remaining subsidiaries against claims and liabilities relating to the past operation of our business.
We could have significant tax liabilities for periods during which Occidental operated our business.
For any tax periods (or portion thereof) in which Occidental owned 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 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, we will pay Occidental for any additional taxes payable by Occidental resulting from Occidental’s election to capitalize some or all of certain CRC intangible drilling costs. We will also be responsible for any increase in Occidental’s federal or state tax liability for any period in which we or any of our subsidiaries are combined or consolidated with Occidental if such increase results from audit adjustments attributable to our business. 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). 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. See “Certain Relationships and Related Party Transactions—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.
The amount of tax for which we are liable for taxable periods preceding the Spin-off may be impacted by elections Occidental makes on our behalf.
Under the Tax Sharing Agreement, Occidental will have the right to make all elections, including elections to capitalize intangible drilling costs, relevant to the determination of our tax liability for periods while we, or any of our subsidiaries, are required to file tax returns with Occidental on a consolidated or combined basis or which include pre-Spin-off periods. As a result, the amount of tax for which we are liable for taxable periods preceding the Spin-off may be impacted by elections Occidental makes on our behalf.
We could have significant tax liabilities if the Spin-off, and certain transactions in preparation therefore, are not tax-free.
In certain circumstances, if the Spin-off is determined to be taxable for U.S. federal income tax purposes, we could incur significant liabilities under a tax-sharing agreement between us and Occidental. Occidental has received a private letter ruling from the Internal Revenue Service ("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. Occidental also received opinions from tax counsel 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 generally qualifies as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code. The private letter ruling relies and the opinions 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 may not be able to rely on the private letter ruling or the opinions 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 opinions of Occidental’s tax advisor, the IRS could conclude upon

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audit that the Spin-off is taxable in full or in part. The IRS may determine that the Spin-off is taxable for other reasons, including as a result of certain significant changes in the stock ownership of Occidental or us after the Spin-off. For a description of the sharing of such liabilities between Occidental and us, see “Certain Relationships and Related Party Transactions—Arrangements Between Occidental and Our Company—Tax Sharing Agreement.”
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 and the overlap of one member of our Board with the board of directors of Occidental.
Several members of our board of directors and management will initially own common stock of Occidental or options to purchase common stock of Occidental, 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. In addition, the board of directors of each of CRC and Occidental has one member in common, which could create actual or potential conflicts of interest.
The Spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements.
The Spin-off 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 Spin-off, 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 Spin-off, transferring assets or taking other action as part of the Spin-off 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 unreasonably 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 Spin-off 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 Spin-off.
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 Spin-off, each of Occidental and CRC 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 Spin-off, and each of Occidental and CRC 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 “Certain Relationships and Related Party Transactions—Arrangements Between Occidental and Our Company—Separation and Distribution Agreement.”
The agreements between us and Occidental were not made on an arm’s-length basis.
The agreements we entered into with Occidental in connection with the Spin-off, were 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 were negotiated, we did not have an independent board of directors or a management team independent of Occidental. As a result, the terms of those agreements, including those that are discussed elsewhere, may be unfavorable and 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.

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Risks Related to the Exchange Offer
If you do not exchange your original notes, you may have difficulty transferring them at a later time.
Original notes that are not exchanged will remain subject to restrictions on transfer and will not have rights to registration. If you do not participate in the exchange offer, your original notes will continue to be subject to the restrictions on transfer described in the offering memorandum distributed in connection with the private placement of the original notes. Accordingly, you would need to comply with the registration and prospectus delivery requirements of the Securities Act for any resale transaction. Each broker-dealer who holds original notes for its own account due to market-making or other trading activities and who receives exchange notes for its own account must acknowledge that it will deliver a prospectus in connection with any resale of the exchange notes. If any original notes are not tendered in the exchange or are tendered but not accepted, the trading market for such original notes could be negatively affected due to the limited amount of original notes expected to remain outstanding following the completion of the exchange offer.
If you wish to tender your original notes for related exchange notes, you must comply with the requirements described in this prospectus.
We will issue the exchange notes for the related original notes only if you properly tender the original notes before the Expiration Date in the manner set forth in this prospectus. Neither we nor the exchange agent has any duty to give you notice of defects or irregularities with respect to tenders of original notes for exchange.
If you are the beneficial owner of original notes that are held through a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender such original notes in the exchange offer, you should promptly contact and instruct that person to tender on your behalf.
Risks Related to the Exchange Notes
We may not be able to repurchase the exchange notes upon a change of control trigger event or an offer to repurchase the exchange notes in connection with an asset sale as required by the indenture.
Under the terms of our indenture, upon the occurrence of specific types of change of control trigger events, we will be required to offer to repurchase all of the exchange notes at a price equal to 101% of the aggregate principal amount of the exchange notes repurchased, plus accrued and unpaid interest, up to but not including the date of repurchase. We may not have sufficient funds available to repurchase all of the exchange notes tendered pursuant to any such offer and any other indebtedness that would become payable upon a change of control.
Our Credit Facilities restrict, and any future credit agreements or other debt agreements to which we become a party may restrict, our ability to repurchase the exchange notes. If we are prohibited from repurchasing the exchange notes, we could seek the consent of our then-existing lenders to repurchase the exchange notes or we could attempt to refinance the borrowings that contain such prohibition. If we are unable to obtain a consent or refinance the debt, we could not repurchase the exchange notes. Our failure to repurchase tendered exchange notes could constitute a default under the indenture and might constitute a default under the terms of other indebtedness that we incur. The term “change of control,” as defined in “Description of Exchange Notes—Certain Definitions,” is limited to certain specified transactions and may not include other events that might adversely affect our financial condition. Our obligation to repurchase the exchange notes upon a change of control triggering event would not necessarily afford holders of exchange notes protection in the event of a highly leveraged transaction, reorganization, merger or similar transaction involving us.
Your ability to transfer the exchange notes may be limited by the absence of a trading market.
The exchange notes will be new securities for which currently there is no trading market. We do not initially intend to apply for listing of the exchange notes on any securities exchange or stock market. Although the initial purchasers have informed us that they currently intend to make a market in the exchange notes, they are not obligated to do so. In addition, they may discontinue any such market making at any time without notice. The liquidity of any market for the exchange notes will depend on the number of holders of those exchange notes, the interest of securities dealers in making a market in those exchange notes and other factors. Accordingly, we cannot assure you as to the development, maintenance or liquidity of any market for the exchange notes. If the exchange notes are traded after their initial issuance, they may trade at a discount to their initial offering price, depending on prevailing interest rates, the market for similar securities, our performance and other factors. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the exchange notes. We cannot assure you that the market, if any, for the exchange notes will be free from similar disruptions. Any such disruption may adversely affect the holders of the exchange notes. To the extent that

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an active trading market for the exchange notes does not develop, the liquidity and trading prices for the exchange notes may be harmed. Thus, you may not be able to liquidate your investment rapidly, and your lenders may not readily accept the exchange notes as collateral for loans.
Future trading prices of the exchange notes will depend on many factors, including but not limited to:
our operating performance and financial condition;
the interest of the securities dealers in making a market in the exchange notes; and
the market for similar securities.
Changes in our credit ratings or the debt markets may adversely affect the market price of the exchange notes and our borrowing costs.
The price for the exchange notes will depend on a number of factors, including but not limited to:
our credit ratings with major credit rating agencies;
prevailing market interest rates and interest rates being paid by other companies similar to us;
our financial condition, operating performance and future prospects;
market analysts’ perception of our company, our prospects and our industry in general; and
the overall condition of the financial markets and global and domestic economies.
The condition of the financial markets and prevailing interest rates have fluctuated in the past and are likely to fluctuate in the future. Such fluctuations could have an adverse effect on the market price of the exchange notes. In addition, if rating agencies reduce the rating on the exchange notes or place the exchange notes on watch for a downgrade in the future, the market price of the notes may be adversely affected. If any rating of our outstanding debt is downgraded, raising capital will become more difficult, our borrowing costs may increase and the market price of the exchange notes may decrease. The credit rating agencies evaluate the industry in which we operate as a whole and may also change their credit rating for us based on their overall view of our industry.
The exchange notes will be effectively junior in right of payment to our secured debt and that of our guarantors.
The exchange notes and the guarantees are unsecured and therefore will be effectively junior in right of payment to any of our future secured debt and that of our subsidiary guarantors to the extent of the value of assets securing such debt. In the event of a bankruptcy or similar proceeding, the assets that serve as collateral for any secured debt will be available to satisfy the obligations under the secured debt before any payments are made on the exchange notes. Initially, the Credit Facilities are unsecured; however, initially we will be required to provide collateral for the Credit Facilities if our corporate family rating is Ba3 or lower from (or is unrated by) Moody’s or our corporate credit rating is BB- or lower from (or is unrated by) S&P during the interim covenant period discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities". Outside the initial period, we will be required to provide collateral if our corporate family rating is B1 or lower from (or is unrated by) Moody’s or our corporate credit rating is B+ or lower from (or is unrated by) S&P (unless our corporate family rating is B1 or our corporate credit rating is B+, and our other rating is BB or Ba2 or higher, as applicable).
The indenture under which the exchange notes were issued permits us to incur significant secured obligations without equally and ratably securing the exchange notes. Holders of any of our secured indebtedness or other obligations would have claims with respect to our assets constituting collateral for such indebtedness and obligations that are prior to your claims under the exchange notes. To the extent the value of the collateral is not sufficient to satisfy such indebtedness and obligations, the holders of that indebtedness and those obligations would be entitled to share with the holders of the exchange notes and the holders of other claims against us with respect to the remainder of our assets, if any. However, since we may be permitted to pledge all of our assets to secure our indebtedness and other obligations, there may be no assets remaining to satisfy the claims of holders of the exchange notes.

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Claims of holders of the exchange notes will be structurally subordinated to claims of creditors of any of our existing and future non-guarantor subsidiaries.
Initially, certain immaterial subsidiaries will not guarantee the exchange notes. The non-guarantor subsidiaries represented less than 1% of our total assets and had no indebtedness as of December 31, 2014, and represented less than 1% of revenues for the twelve months ended December 31, 2014. In addition, in the future, certain subsidiaries may not be required to be, or may be delayed in becoming, a subsidiary guarantor. See “Description of Exchange Notes—Guarantees” and “Description of Exchange Notes—Certain Covenants—Future Guarantees.” In particular, any subsidiary that is a master limited partnership or a royalty trust will not be required to guarantee the exchange notes. Claims of holders of the exchange notes will be structurally subordinated to all of the liabilities of any subsidiaries that do not guarantee the exchange notes.
The guarantee of a subsidiary could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the exchange notes from relying on that subsidiary to satisfy claims.
Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, to the extent the exchange notes would be guaranteed by a subsidiary, such subsidiary guarantees can be voided, or claims under the guarantee of a subsidiary may be further subordinated to all other debts of that subsidiary guarantor if, among other things, the subsidiary guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and at the time of incurrence:
was insolvent or rendered insolvent by reason of such incurrence;
was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.
The guarantee of a subsidiary may also be voided, without regard to the above factors, if a court found that the subsidiary guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors.
A court would likely find that a subsidiary guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the subsidiary guarantor did not substantially benefit directly or indirectly from the issuance of the guarantees. Sufficient funds to repay the exchange notes may not be available from other sources, including the remaining subsidiary guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.
Each subsidiary guarantee will contain a provision intended to limit the subsidiary guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its subsidiary guarantee to be a fraudulent transfer. Such provision may not be effective to protect the subsidiary guarantees from being voided under fraudulent transfer law.

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THE EXCHANGE OFFER
This section of the prospectus describes the exchange offer. While we believe that the description covers the material terms of the exchange offer, this summary may not contain all of the information that is important to you. You should carefully read this entire document for a complete understanding of the exchange offer.
Purpose and Effects of the Exchange Offer
We sold the original notes in transactions that were exempt from or not subject to the registration requirements of the Securities Act. Accordingly, the original notes are subject to transfer restrictions. In general, you may not offer or sell the original notes unless either they are registered under the Securities Act or the offer or sale is exempt from or not subject to registration under the Securities Act and applicable state securities laws.
As a condition to the initial sale of the original notes, we and the initial purchasers entered into a registration rights agreement on October 1, 2014. We are offering the exchange notes under this prospectus in an exchange offer for the original notes to satisfy our obligations under the registration rights agreement. Under the registration rights agreement, we are required, among other things, to:
within 365 days after the closing of the private placement on October 1, 2014, use our commercially reasonable efforts to cause to be effective a registration statement registering the proposed offer and exchange of any and all original notes for registered exchange notes with substantially identical terms, except that the exchange notes will not contain terms with respect to transfer restrictions or additional interest for failure to effect an exchange offer;
keep the exchange offer open for not less than 20 business days after the date notice thereof is mailed to holders of the original notes; and
use our commercially reasonable efforts to consummate the exchange offer within 30 business days after the registration statement has become effective, or such longer period as may be required by United States securities laws.
In addition, under certain circumstances, we may be required to file a shelf registration statement to cover resales of original notes and exchange notes.
If we fail to comply with the requirements of the registration rights agreement, the interest rate on the original notes may increase. Specifically, if (i) the exchange offer is not consummated within 30 business days after the 365th day following the closing of the private placement on October 1, 2014 (or, if the exchange offer is not permitted, the shelf registration statement is not filed on or prior to the date specified for such filing) or (ii) a registration statement with respect to the original notes is filed and declared effective but thereafter ceases to be effective or fails to be usable for its intended purpose (any such event referred to in the clauses above, a “Registration Default”), the annual interest rate borne by the original notes will be increased by 0.25% per annum with respect to the first 90 days after the applicable Registration Default, and, if such default is not cured prior to the end of such 90-day period, by an additional 0.25% per annum (together with the increase described in the preceding clause, as applicable, the “Additional Interest”) with respect to each subsequent 90-day period, up to a maximum amount of additional interest of 0.5% per annum.
The summary in this document of the registration rights agreement is not complete and is subject to, and is qualified in its entirety by, all the provisions of the registration rights agreement. We urge you to read the entire registration rights agreement carefully. A copy of the registration rights agreement has been incorporated by reference in the registration statement of which this prospectus forms a part. The registration statement is intended to satisfy some of our obligations under the registration rights agreement.
The exchange offer will be open for at least 20 business days (or longer, if required by applicable law) after the date notice thereof is mailed to the holders of the original notes. During the exchange offer period, we will deliver exchange notes for all original notes properly tendered and not withdrawn before the Expiration Date. The exchange notes will be registered and the transfer restrictions, registration rights and provisions for additional interest relating to the original notes will not apply to the exchange notes. The exchange notes issued in exchange for the original notes are expected to bear a different CUSIP number and ISIN number from any unexchanged original notes. Holders of the exchange notes and the original notes will vote as one series under the indenture governing the notes.

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We have not requested, and do not intend to request, an interpretation by the staff of the SEC with respect to whether the exchange notes may be offered for sale, resold or otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act. Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, including Exxon Capital Holdings Corp. (available May 13, 1988), Morgan Stanley & Co. Incorporated (available June 5, 1991) and Shearman & Sterling (available July 2, 1993), we believe the exchange notes may be offered for resale, resold and otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act, provided such holder meets the following conditions:    
such holder is not a broker-dealer who purchased original notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act;
such holder is not our “affiliate”; and
such holder acquires exchange notes in the ordinary course of its business and has no arrangement or understanding with any person to participate in the distribution of the exchange notes.
If you do not satisfy all of the above conditions, you cannot participate in the exchange offer. Rather, in the absence of an exemption, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the original notes. Any holder required to comply with such registration and prospectus delivery requirements may incur liabilities under the Securities Act for which the holder will not be entitled to indemnification from us.
A broker-dealer that has bought original notes for its own account as part of its market-making or other trading activities must deliver a prospectus in order to resell the exchange notes it receives pursuant to the exchange offer. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer for such purpose, and we have agreed in the registration rights agreement to make this prospectus available to such broker-dealers upon reasonable request for the period required by the Securities Act. See “Plan of Distribution.” Each broker-dealer that receives exchange notes in the exchange offer must acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of exchange notes. The accompanying letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.
We are not making the exchange offer to, nor will we accept tenders for exchange from, holders of original notes in any jurisdiction in which this exchange offer or its acceptance would not comply with applicable state securities laws or applicable laws of a foreign jurisdiction.
Participation in the exchange offer is voluntary and you should carefully consider whether to participate. We urge you to consult your financial and tax advisors in making your decision on whether to participate in the exchange offer.
Consequences of Failure to Exchange
Original notes that are not exchanged for exchange notes in the exchange offer will remain “restricted securities” within the meaning of Rule 144(a)(3) under the Securities Act, and will therefore continue to be subject to restrictions on transfer. Original notes will remain outstanding and will continue to accrue interest, but holders of such original notes will not be able to require us to register them under the Securities Act. Accordingly, following completion of the exchange offer any original notes that remain outstanding may not be offered, sold, pledged or otherwise transferred except:
(1)
to us, upon redemption thereof or otherwise;
(2)
so long as the original notes are eligible for resale pursuant to Rule 144A, to a person whom the seller reasonably believes is a qualified institutional buyer within the meaning of Rule 144A, purchasing for its own account or for the account of a qualified institutional buyer to whom notice is given that the resale, pledge or other transfer is being made in reliance on Rule 144A;
(3)
in an offshore transaction in accordance with Regulation S under the Securities Act;
(4)
pursuant to an exemption from registration in accordance with Rule 144, if available, under the Securities Act;
(5)
in reliance on another exemption from the registration requirements of the Securities Act; or
(6)
pursuant to an effective registration statement under the Securities Act.

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In all of the situations discussed above, the resale must be in compliance with the Securities Act, any applicable securities laws of any state of the United States and any applicable securities laws of any foreign country. Any resale of original notes will also be subject to certain requirements of the registrar or any co-registrar being met, including receipt by the registrar or co-registrar of a certification and, in the case of (3), (4) and (5) above, an opinion of counsel reasonably acceptable to us and the registrar and any co-registrar.
To the extent original notes are tendered and accepted in the exchange offer, the principal amount of outstanding original notes will decrease with a resulting decrease in the liquidity in the market therefor. Accordingly, the liquidity of the market of the original notes could be adversely affected following completion of the exchange offer. See “Risk Factors—Risks Related to the Exchange Offer."
Terms of the Exchange Offer
Upon the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal, we will accept any and all original notes validly tendered (and not withdrawn) prior to 5:00 p.m., New York City time, on the Expiration Date. We will issue the relevant series of exchange notes in principal amount equal to the principal amount of the relevant series of original notes surrendered in the exchange offer. The exchange notes will accrue interest on the same terms as the relevant series of original notes; however, holders of the original notes accepted for exchange will not receive accrued interest thereon at the time of exchange; rather, all accrued interest on the original notes will become obligations under the exchange notes. Holders may tender some or all of their original notes pursuant to the exchange offer. However, original notes may be tendered only in denominations of $2,000 and integral multiples of $1,000 principal amount in excess thereof.
The form and terms of the exchange notes are the same as the form and terms of the relevant series of original notes, except that:
the exchange notes will have been registered under the Securities Act, and the exchange notes will not bear legends restricting their transfer pursuant to the Securities Act; and
except as otherwise described above, holders of the exchange notes will not be entitled to any rights under the registration rights agreement.
As of the date of this prospectus, $5.0 billion in aggregate principal amount of the original notes are outstanding. The exchange notes will evidence the same debt as the relevant series of original notes that they replace, and will be issued under, and be entitled to the benefits of, the indenture which governs the original notes, including the payment of principal and interest.
The term “holder,” as used in this prospectus, means those DTC participants in whose name interests in the global notes are credited on the books of DTC, and those persons who hold interests through such DTC participants. The term “original notes,” as used in this prospectus, means such interests in the global notes.
Holders of the original notes do not have any appraisal or dissenter’s rights under state law or the indenture governing the notes in connection with the exchange offer. We intend to conduct the exchange offer in accordance with the requirements of the registration rights agreement, Securities Act, the Exchange Act, and the SEC’s rules and regulations thereunder.
The exchange agent will act as agent for the tendering holders of the original notes for the purposes of receiving the exchange notes. The exchange notes delivered in the exchange offer will be issued promptly following the Expiration Date. We will return any original notes that we do not accept for exchange for any reason without expense to their tendering holders promptly after the expiration or termination of the exchange offer.
If any tendered original notes are not accepted for exchange because they do not comply with the procedures set forth in this prospectus and the accompanying letter of transmittal, our withdrawal of the exchange offer, the occurrence of certain other events set forth herein or otherwise, such unaccepted original notes will be returned, without expense, to the tendering holder promptly after the Expiration Date or our withdrawal of the exchange offer. Such non-exchanged original notes will be credited to an account maintained by DTC. Any acceptance, waiver of default or a rejection of a tender of original notes shall be at our discretion and shall be conclusive, final and binding.
Holders who tender original notes in the exchange offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of the original notes in the exchange offer. We will pay all charges and expenses, other than certain taxes, in connection with the exchange offer. See “—Fees and Expenses.”

24



Expiration Date; Extensions; Amendments
The term “Expiration Date” with respect to the exchange offer means 5:00 p.m., New York City time, on                 , 2015 unless we, in our sole discretion, extend the exchange offer, in which case the term “Expiration Date” shall mean the latest date and time to which the exchange offer is extended.
If we extend the exchange offer, we will notify the exchange agent and each registered holder of original notes of any extension by oral or written notice and will make a public announcement thereof, each prior to 9:00 a.m., New York City time, no later than on the next business day after the previously scheduled Expiration Date. Any notice relating to the extension of the exchange offer will disclose the number of securities tendered as of the date of the notice, as required by Rule 14e-1(d) under the Exchange Act.
We reserve the right, in our sole discretion,
to extend the exchange offer;
to delay accepting any original notes;
if any of the conditions set forth below under “—Conditions to the Exchange Offer” have not been satisfied, to terminate the exchange offer or waive any conditions that have not been satisfied; or
subject to the terms of the registration rights agreement, to amend the terms of the exchange offer in any manner.
We may effect any such extension, waiver, termination or amendment by giving written notice thereof to the exchange agent and each registered holder of original notes.
Except as specified in the second paragraph under this heading, we will make a public announcement of any such extension, termination, amendment or waiver as promptly as practicable. If we amend or waive any condition of the exchange offer in a manner determined by us to constitute a material change to the exchange offer, we will promptly disclose such amendment or waiver in a prospectus supplement that will be distributed to the holders of the original notes. The exchange offer will then be extended for a period of five to ten business days, as required by law, depending upon the significance of the amendment or waiver and the manner of disclosure to the registered holders.
We will have no obligation to publish, advertise, or otherwise communicate any public announcement of any delay, extension, amendment or termination that we may choose to make, other than by making a timely release to an appropriate news agency.
Interest on the Exchange Notes
The exchange notes will accrue interest on the same terms as the relevant series of original notes: the 2020 exchange notes will bear interest at a rate of 5% per annum, the 2021 exchange notes will bear interest at a rate of 5 1/2% per annum and the 2024 exchange notes will bear interest at a rate of 6% per annum. Interest on the 2020 exchange notes will be paid semi-annually in arrears on January 15 and July 15 of each year, beginning on July 15, 2015. Interest on the 2021 exchange notes will be paid semi-annually in arrears on March 15 and September 15 of each year, beginning on March 15, 2015. Interest on the 2024 exchange notes will be paid semi-annually in arrears on May 15 and November 15 of each year, beginning on May 15, 2015.
Procedures for Tendering Original Notes
To participate in the exchange offer, you must properly tender your original notes to the exchange agent as described below.
Tenders of Original Notes; Book-Entry Delivery Procedure
All of the original notes are held in book-entry form and are currently represented by global notes registered in the name of Cede & Co., the nominee of DTC. We have confirmed with DTC that the original notes may be tendered using the Automated Tender Offer Program (“ATOP”) procedures.
The exchange agent will establish an account with respect to the original notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus, and any financial institution that is a participant in DTC that wishes

25



to participate in the exchange offer may make book-entry delivery of the original notes by causing DTC to transfer such original notes into the exchange agent’s account in accordance with DTC’s procedures for such transfer. The confirmation of a book-entry transfer into the exchange agent’s account at DTC is referred to as a “Book-Entry Confirmation.” In addition, DTC participants on or before the Expiration Date must transmit their acceptance using ATOP procedures, for which the exchange offer is eligible, and DTC will then edit and verify the acceptance and send an Agent’s Message to the exchange agent for its acceptance.
An “Agent’s Message” is a message transmitted by DTC to, and received by, the exchange agent and forming a part of the Book-Entry Confirmation, which states that DTC has received instructions from the participant to tender the original notes and that such participant expressly acknowledged and agreed to be bound by the terms of the letter of transmittal and the representations in the letter of transmittal, and that we may enforce such agreement against such participant.
In order to validly tender the original notes in the exchange offer, the exchange agent must receive, on or prior to the Expiration Date, an Agent’s Message under the ATOP procedures that confirms that:
DTC has received your instructions to tender your original notes; and
You agree to be bound by the terms of the letter of transmittal.
The tender by a holder of original notes pursuant to the procedures set forth above will constitute the tendering holder’s acceptance of all of the terms and conditions of the exchange offer. Our acceptance for exchange of original notes tendered pursuant to the procedures described above will constitute a binding agreement between such tendering holder and us in accordance with the terms and subject to the conditions of the exchange offer. Only holders are authorized to tender their original notes.
The tender by a holder of original notes pursuant to the procedures set forth above will constitute the tendering holder’s acceptance of all of the terms and conditions of the exchange offer. Our acceptance for exchange of original notes tendered pursuant to the procedures described above will constitute a binding agreement between such tendering holder and us in accordance with the terms and subject to the conditions of the exchange offer. Only holders are authorized to tender their original notes.
By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:
any exchange notes that you receive will be acquired in the ordinary course of business;
you are not engaged in and do not intend to engage in the distribution of the exchange notes;
you have no arrangement or understanding with any person or entity to participate in the distribution of the exchange notes;
you are not an “affiliate,” as defined in Rule 405 under the Securities Act, of us or our subsidiary guarantors or, if you are an affiliate, that you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable; and
if you are a broker-dealer that will receive exchange notes for your own account in exchange for the original notes, you acquired those original notes as a result of market-making activities or other trading activities and you will deliver this prospectus, as required by law, in connection with any resale of the exchange notes.
The delivery of original notes through DTC and any Agent’s Message transmitted through ATOP is at the election and risk of the persons tendering original notes. Delivery of documents to DTC does not constitute delivery to the exchange agent. You must allow sufficient time for completion of the ATOP procedures during normal business hours of DTC on or prior to the Expiration Date. Tender and delivery will be deemed made only when actually received by the exchange agent. Holders should be aware that DTC may have deadlines earlier than the Expiration Date for the exchange offer. Accordingly, holders of original notes wishing to participate in the exchange offer are urged to contact DTC as soon as possible.
Except as provided below, unless tender of the original notes is made in accordance with ATOP procedures on or prior to the Expiration Date, we may, at our option, reject the tender of such original notes as invalid and ineffective. The exchange of original notes for exchange notes will be made only against the tendered original notes and for the relevant series of the tendered original notes, which must be deposited with the exchange agent prior to or on the Expiration Date.


26



Tender of Original Notes Held Through a Nominee
If you beneficially own original notes through a bank, depository, broker, trust company or other nominee and wish to tender your original notes, you must instruct such holder to cause your original notes to be tendered on your behalf. Such nominee cannot tender original notes on behalf of a holder of original notes without such holder's instructions. Holders whose original notes are held by a bank, depository, broker, trust company or other nominee should be aware that such nominee may have deadlines earlier than the Expiration Date. Accordingly, such holders are urged to contact any such nominee through which they hold their original notes as soon as possible in order to learn of its applicable deadlines.
Delivery of Original Notes Held in Physical Form
We do not believe any original notes exist in physical form. If you believe you hold original notes in physical form, please contact the exchange agent regarding procedures for participating in the exchange offer. Any original notes in physical form must be tendered using a physical letter of transmittal and such original notes must be delivered to the Exchange Agent at its address set forth below under the heading "—Exchange Agent.”
Determination of Validity
All questions as to the validity, form, eligibility (including time of receipt), acceptance and withdrawal of tendered original notes will be determined by us, which determination will be conclusive, final and binding. Alternative, conditional or contingent tenders of original notes may not be considered valid and may be rejected by us. We reserve the absolute right to reject any and all original notes not properly tendered or any original notes our acceptance of which, in the opinion of our counsel, would be unlawful.
We also reserve the right to waive any defects, irregularities or conditions of tender as to particular original notes. The interpretation of the terms of our exchange offer (including the instructions in the letter of transmittal) by us will be conclusive, final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of original notes must be cured within such time as we shall determine.
Although we intend to notify holders of defects or irregularities with respect to tenders of original notes through the exchange agent, neither we, the exchange agent nor any other person is under any duty to give such notice, nor shall they incur any liability for failure to give such notification. Tenders of original notes will not be deemed to have been made until such defects or irregularities have been cured or waived.
Any original notes tendered into the exchange agent’s account at DTC that are not validly tendered and as to which the defects or irregularities have not been cured or waived within the timeframes established by us in our sole discretion, if any, will be credited back to the account maintained by the applicable DTC participant with such book-entry transfer facility.
Withdrawal of Tenders
Tenders of original notes in the exchange offer may be withdrawn at any time on or prior to the Expiration Date by sending a notice of withdrawal to the exchange agent using the ATOP procedures. To be effective, any notice of withdrawal must specify the name and number of the account at DTC to be credited with such withdrawn original notes and must otherwise comply with the ATOP procedures.
All questions as to the validity, form and eligibility (including time of receipt) of such notices will be determined by us, which determination shall be conclusive, final and binding on all parties. No withdrawal of original notes will be deemed to have been properly made until all defects or irregularities have been cured or expressly waived. Neither we, the exchange agent nor any other person will be under any duty to give notification of any defects or irregularities in any notice of withdrawal or revocation, nor shall we or they incur any liability for failure to give any such notification. Any original notes so withdrawn will be deemed not to have been validly tendered for purposes of the exchange offer and no exchange notes will be issued with respect thereto unless the original notes so withdrawn are retendered on or prior to the Expiration Date. Properly withdrawn original notes may be retendered by following the procedures described above under “—Procedures for Tendering Original Notes” at any time on or prior to the Expiration Date.
Any original notes which have been tendered but which are not accepted for exchange due to the rejection of the tender due to uncured defects or the prior termination of the exchange offer, or which have been validly withdrawn, will be returned to the holder thereof unless otherwise provided in the letter of transmittal, promptly following the Expiration Date or, if so requested in the notice of withdrawal, promptly after receipt by us of notice of withdrawal without cost to such holder.

27



Issuance of Exchange Notes
We will be deemed to have accepted validly tendered original notes when, as and if we have given written notice thereof to the exchange agent, which is Wells Fargo Bank, National Association. In all cases, we will issue the relevant series of exchange notes for the series of original notes that we have accepted for exchange under the exchange offer only after the exchange agent receives (i) a Book-Entry Confirmation of such original notes into the exchange agent’s account at DTC; and (ii) a properly transmitted Agent’s Message. Such exchange notes will be issued promptly following the expiration or termination of the exchange offer.
Return of Original Notes
If any tendered original notes are not accepted for any reason described herein or if original notes are withdrawn or are submitted for a greater principal amount than you desire to exchange, those original notes will be returned, at our cost, to the exchange agent’s account at DTC. Any such original notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.
Conditions to the Exchange Offer
The exchange offer will not be subject to any conditions, other than:
that the exchange offer does not violate applicable law or any applicable interpretations of the staff of the SEC;
that no action or proceeding shall have been instituted or threatened in any court or by any governmental agency with respect to the exchange offer; and
the due tendering of original notes and the delivery to the exchange agent of the letter of transmittal or an Agent’s.
If we determine that any of the conditions to the exchange offer are not satisfied in accordance with their terms, we may:
refuse to accept any original notes and return all tendered original notes to the tendering holders;
terminate the exchange offer;
extend the exchange offer and retain all original notes tendered prior to the Expiration Date, subject, however, to the rights of holders to withdraw such original notes; or
waive such unsatisfied conditions with respect to the exchange offer and accept all validly tendered original notes which have not been withdrawn.
If our waiver of an unsatisfied condition constitutes a material change to the exchange offer, we will promptly disclose such waiver by means of a prospectus supplement that will be distributed to the holders of the original notes, and will extend the exchange offer for a period of five to ten business days, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during such five to ten business day period.
The conditions listed above are for our sole benefit and we may assert these rights regardless of the circumstances giving rise to any of these conditions. We may waive these conditions in our reasonable discretion in whole or in part at any time and from time to time. If we fail at any time to exercise any of the above rights, the failure will not be deemed a waiver of these rights, and these rights will be deemed ongoing rights which may be asserted at any time and from time to time.
In addition, we will not accept for exchange any original notes tendered, and no exchange notes will be issued in exchange for those original notes, if at such time the registration statement of which this prospectus forms a part has not been declared effective by the SEC, or if at such time any stop order shall be threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939, as amended. In any of those events we are required to use commercially reasonable efforts to have the registration statement of which this prospectus forms a part be declared effective by the SEC and obtain the withdrawal of any stop order at the earliest possible moment, as applicable.

28



Termination of Certain Rights
All registration rights under the registration rights agreement benefiting the holders of the original notes will terminate when we consummate the exchange offer. That includes all rights to receive additional interest in the event of a registration default under the registration rights agreement.

Exchange Agent
Wells Fargo Bank, National Association has been appointed as exchange agent for the exchange offer. The exchange agent, among other things, will not be (i) liable for any act or omission unless such act or omission constitutes its own gross negligence or willful misconduct and in no event will the exchange agent be liable to a security holder, us or any third party for special, punitive, indirect or consequential damages, including, but not limited to, lost profits, arising in connection with the exchange offer or its duties and responsibilities related to the exchange offer, (ii) obligated to take any legal action with respect to the exchange offer which might, in its judgment, involve any risk of expense, loss or liability, unless it will be furnished with indemnity satisfactory to it or (iii) liable or responsible for any statement contained in this prospectus. We will indemnify the exchange agent with respect to certain matters relating to the exchange offer.
You should direct questions and requests for assistance, requests for additional copies of this prospectus, the letter of transmittal or requests for other documents to the exchange agent as follows:
Delivery by Registered or Certified Mail:
Wells Fargo Bank, N.A.
Corporate Trust Operations
P.O. Box 1517
Minneapolis, MN 554802-1517

Regular Mail or Overnight Courier:
Wells Fargo Bank, N.A.
Corporate Trust Operations
N9303-121
6th & Marquette Avenue
Minneapolis, MN 554802-1517

In Person by Hand Only:
Wells Fargo Bank, N.A.
Northstar East Building
608 2nd Avenue South, 12th Floor Avenue
Minneapolis, MN 554802-1517


For Information or Confirmation by Telephone:
(800) 344-5128

Wells Fargo Bank, National Association also serves as trustee under the indenture governing the notes.
Fees and Expenses
We will bear the expenses of soliciting tenders with respect to the exchange offer. The principal solicitation is being made by mail by the exchange agent; however, additional solicitation may be made by email, telephone or in person by our or our affiliates’ officers and regular employees.
We have not retained any dealer-manager in connection with the exchange offer and no payments will be made to brokers, dealers or others soliciting acceptance of the exchange offer. However, reasonable and customary fees will be paid to the exchange agent for its services and it will be reimbursed for its reasonable out-of-pocket expenses. We will also pay other cash expenses to be incurred in connection with the exchange offer, including SEC registration fees, our accounting and legal fees, printing costs and related fees and expenses.

29



Our out-of-pocket expenses for the exchange offer will include fees and expenses of the exchange agent and the trustee under the indenture governing the notes, accounting and legal fees and printing costs, among others.
Transfer Taxes
We will pay all transfer taxes, if any, applicable to the exchange of the original notes pursuant to the exchange offer. If, however, exchange notes or original notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be registered or issued in the name of, any person other than the registered holder of the original notes, or if a transfer tax is imposed for any reason other than the exchange of the original notes pursuant to the exchange offer, then the amount of any such transfer taxes (whether imposed on the tendering holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted to the exchange agent, the amount of such transfer taxes will be billed directly to such tendering holder.
Accounting Treatment for the Exchange Offer
The exchange notes will be recorded at the carrying value of the original notes and no gain or loss for accounting purposes will be recognized.
Other
You do not have to participate in the exchange offer. You should carefully consider whether to accept the terms and conditions of this exchange offer. We urge you to consult your financial and tax advisors in deciding what action to take with respect to the exchange offer.

30




USE OF PROCEEDS
The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the exchange notes. In exchange for issuing the exchange notes as contemplated in this exchange offer, we will receive original notes in the same principal amount. The form and terms of the exchange notes are identical in all material respects to the form and terms of the original notes, except as described below under the heading “The Exchange Offer—Terms of the Exchange Offer.” The original notes tendered in exchange for the exchange notes will be retired and canceled and cannot be re-issued. Accordingly, issuance of the exchange notes will not result in any increase in our outstanding debt.
CAPITALIZATION
The following table sets forth our historical capitalization as of December 31, 2014. The table below should be read in conjunction with "Selected Financial Data," —"Management's Discussion and Analysis of Financial Condition and Results of Operations" and our audited consolidated and combined financial statements and the notes to those statements included elsewhere in this prospectus.

 
 
 
December 31, 2014
 
 
(in millions)
Debt Outstanding
 
Long-term debt:
 
Revolving Credit Facility
$
360

Term Loan Facility
1,000

5.00% notes due 2020
1,000

5.50% notes due 2021
1,750

6.00% notes due 2024
2,250

Total debt
6,360

 
 
Equity
 
Common stock (2.0 billion shared authorized at $0.01 par value)
 
Par value
4

Additional paid-in capital
4,748

Accumulated deficit
(2,117
)
Accumulated other comprehensive income (loss)
(24)

 
 
Total Capitalization
$
8,971


31




SELECTED FINANCIAL DATA
Prior to the Spin-off on November 30, 2014, the following selected financial data was derived from the California business of Occidental. All financial information presented after the Spin-off represents CRC's consolidated results of operations, financial position and cash flows. Accordingly:
The selected statement of operations and cash flows data for the year ended December 31, 2014 consists of the stand-alone consolidated results of California Resources Corporation post Spin-off and the consolidated and combined results of the California business prior to the Spin-off. The selected statement of operations data for the years ended December 31, 2013, 2012, 2011, and 2010 consist entirely of the combined results of the California business.
The selected balance sheet data at December 31, 2014 consists of the consolidated balances of California Resources Corporation, while the selected balance sheet data at December 31, 2013, 2012, 2011 and 2010 consists of the combined balances of the California business.
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(in millions)
Statement of Operations Data
 
 

 
 

 
 

 
 

 
 

Revenues
 
$
4,173

 
$
4,284

 
$
4,073

 
$
3,934

 
$
2,912

Income / (loss) before income taxes
 
$
(2,421
)
 
$
1,447

 
$
1,181

 
$
1,641

 
$
1,129

Net income / (loss)
 
$
(1,434
)
 
$
869

 
$
699

 
$
971

 
$
719

Per common share(a)
 
 
 
 
 
 
 
 
 
 
Basic
 
$
(3.75
)
 
$
2.24

 
$
1.80

 
$
2.50

 
$
1.85

Diluted
 
$
(3.75
)
 
$
2.24

 
$
1.80

 
$
2.50

 
$
1.85

 
 
 
 
 
 
 
 
 
 
 
Statement of Cash Flows Data
 
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
 
$
2,371

 
$
2,476

 
$
2,223

 
$
2,456

 
$
1,751

Capital investments
 
$
(2,020
)
 
$
(1,669
)
 
$
(2,331
)
 
$
(2,164
)
 
$
(1,056
)
Acquisitions
 
$
(288
)
 
$
(48
)
 
$
(427
)
 
$
(1,405
)
 
$
(448
)
Borrowings, net of costs
 
$
6,290

 
$

 
$

 
$

 
$

Spin-off related dividends to Occidental
 
$
(6,000
)
 
$

 
$

 
$

 
$

(Distributions to) contributions from Occidental, net
 
$
(335
)
 
$
(763
)
 
$
532

 
$
1,106

 
$
(248
)
 
 
 
 
 
 
 
 
 
 
 
(a) See Note 13 - Earnings Per Share, in the Notes to the Financial Statements

 
 
As of December 31,
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(in millions)
Balance Sheet Data
 
 

 
 

 
 

 
 

 
 

Total current assets
 
$
701

 
$
254

 
$
245

 
$
195

 
$
148

Property, plant and equipment, net
 
$
11,685

 
$
14,008

 
$
13,499

 
$
11,778

 
$
8,823

Total assets
 
$
12,497

 
$
14,297

 
$
13,764

 
$
11,989

 
$
8,987

Total current liabilities
 
$
906

 
$
689

 
$
551

 
$
664

 
$
471

Long-term debt
 
$
6,360

 
$

 
$

 
$

 
$

Equity / Net Investment
 
$
2,611

 
$
9,989

 
$
9,860

 
$
8,624

 
$
6,557


The selected financial data presented above should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated and combined financial statements and accompanying notes included elsewhere in this prospectus.

32




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 Financial Data,” and “Business,” as well as the audited consolidated and combined financial statements and the related notes thereto, all appearing elsewhere in this prospectus.
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 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 assumed in connection with the spin-off from Occidental on November 30, 2014 (the “Spin-off”) and (3) all references to “Occidental” refer to Occidental Petroleum Corporation, our former parent, and its subsidiaries.
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 prospectus. See “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors.”
The Separation and Spin-off
We are an independent oil and natural gas exploration and production company operating properties exclusively within the State of California. We were incorporated in Delaware as a wholly-owned subsidiary of Occidental on April 23, 2014 and remained a wholly-owned subsidiary of Occidental until the Spin-off. On November 30, 2014, Occidental distributed shares of our common stock on a pro rata basis to Occidental stockholders and we became an independent, publicly traded company. Occidental retained approximately 18.5% of our outstanding shares of common stock which it has stated it intends to divest within 18 months of the Spin-off. Occidental has also granted us a proxy to vote the shares of our common stock that Occidental retained immediately after the distribution in proportion to the votes cast by our stockholders.
Basis of Presentation and Certain Factors Affecting Comparability
Up until the Spin-off, the accompanying consolidated and combined financial statements were derived from the consolidated financial statements and accounting records of Occidental. These consolidated and combined financial statements reflect the historical results of operations, financial position and cash flows of the California business. All financial information presented after the Spin-off consists of the stand-alone consolidated results of operations, financial position and cash flows of CRC. 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 consolidated and combined statements of income for periods prior to the Spin-off 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 consolidated and combined financial statements, including the assumptions regarding allocating expenses from Occidental, are reasonable. However, the financial statements may not include all of the actual expenses that would have been incurred or may include duplicative costs and may not reflect our 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 prior to the Spin-off would depend on multiple factors, including organizational structure and strategic and operating decisions. There may be some additional non-recurring costs of operating as a stand-alone company which are not expected to be material.

33



Prior to the Spin-off, we participated in Occidental’s centralized treasury management program and did not incur any debt. Additionally, excess cash generated by our business was distributed to Occidental, and likewise our cash needs were provided by Occidental, in the form of contributions.
Had we been a stand-alone company for the full year 2014, and had the same level of debt throughout the year as we did on December 31, 2014, of approximately $6.4 billion, we would have incurred $314 million, $186 million after-tax, of interest expense, on a pro-forma basis, for the year ended December 31, 2014, compared to the $72 million pre-tax interest expense reported in our statement of operations for the year then ended.
Business Environment and Industry Outlook
Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas index 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 investments to be in line with current economic conditions, including adjusting the size and allocation of our capital program. The changes in the capital program have an impact on our production levels and cash flows.
Given the recent volatile and deteriorating oil price environment, as well as our leverage, we began a hedging program shortly after the Spin-off to protect against our down-side price risk and preserve our ability to execute our capital program. In December 2014, we purchased put options with a $50 per barrel Brent strike price, measured monthly. This initial program covers almost all of our oil production for the first six months of 2015. More recently, we put into place additional hedging instruments to protect the pricing for almost two-thirds of our expected third quarter 2015 oil production. For this program we chose a combination of Brent-based collars (between $55 and $72) for 30,000 barrels per day for July through September as well as put options at $50 per barrel Brent for 40,000 barrels per day in the same period. In addition, we sold a $75 per barrel call for 30,000 barrels per day of oil production in March through June of 2015. Going forward as an independent company, we will continue to be strategic and opportunistic in implementing any hedging program. Our objective is to protect against the cyclical nature of commodity prices to provide a level of certainty around our margins and cash flows necessary to implement our investment program.
We sell all of our crude oil into California markets, which typically reflect international waterborne-based prices because the structural energy deficit in the state results in most of its oil being imported. Over the last several years, these prices have exceeded and continue to exceed West Texas Intermediate (“WTI”) based prices for comparable grades. Due to much lower levels of natural gas production compared to our oil production, the changes in natural gas prices have a significantly lower impact on our operating results. Lower natural gas prices generally have a positive effect on our steamflood projects that use natural gas to generate the steam being injected. Average oil prices were lower in 2014 than 2013, caused by a steep decline in prices in the last half of 2014. Average Brent prices were $108.76 per barrel in 2013 and $99.51 per barrel in 2014 ending 2014 at $57.33. Our realized price for crude oil as a percentage of Brent prices was approximately 93% and 96% for 2014 and 2013, respectively. Oil prices continued to decline in the early part of 2015.
The following table presents the average daily WTI oil, Brent oil and NYMEX gas prices for each of the years ended December 31, 2014, 2013 and 2012:
 
2014
 
2013
 
2012
WTI oil ($/Bbl)
$
93.00

 
$
97.97

 
$
94.21

Brent oil ($/Bbl)
$
99.51

 
$
108.76

 
$
111.70

NYMEX gas ($/Mcf)
$
4.34

 
$
3.66

 
$
2.81

Oil prices and differentials will continue to be affected by (i) global supply and demand, which are generally a function of global economic conditions, the actions of OPEC, other significant producers and governments, inventory levels, threatened or actual production or refining disruptions, the effects of conservation, technological advances and regional market conditions; (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 and differentials for natural gas liquids (“NGLs”) are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural 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.

34



Natural 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 natural gas byproducts, and deliver dry gas to pipelines and separately sell the 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
Seasonality is not a primary driver of changes in our quarterly earnings during the year.
Taxes
Deferred tax liabilities, net of deferred tax assets of $444 million, were approximately $2.0 billion at December 31, 2014. The current portion of total deferred tax assets was $61 million as of December 31, 2014, which was reported in other current assets. The realization of deferred tax assets is assessed periodically based on several factors, including our expectation to generate sufficient future taxable income and reversal of taxable temporary differences.

The following table sets forth the calculation of our effective income tax rate for each of the years ended December 31 (in millions):

 
 
2014
 
2013
 
2012
Pre-tax income/(loss)
 
$
(2,421
)
 
$
1,447

 
$
1,181

Income tax (expense)/benefit
 
987

 
(578
)
 
(482
)
Net income/(loss)
 
$
(1,434
)
 
$
869

 
$
699

Effective tax rate
 
41
%
 
40
%
 
41
%

Operations
We conduct our operations through fee interests, 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 2.4 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 and integral infrastructure assets, including 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 are obligated to fund all capital and production costs. We record a share of production and reserves to recover such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (1) to recover our partners’ share of capital and production costs that we incur on their behalf and costs associated with contractually defined base production, (2) for our defined share of base production and (3) for our defined share of production in excess of base production for each period. We recover our share of capital and production costs, and generate returns, through our defined share of production from base and incremental production in (2) and (3) above. 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, however, our net economic benefit is greater when product prices are higher. These contracts represented approximately 16% of our production for the year ended December 31, 2014.
Results
Results for the year ended December 31, 2014 were a net loss of $1.4 billion, compared with net income of $869 million for the year ended December 31, 2013. The net loss in 2014 largely reflected a $2.0 billion non-cash after-tax impairment charge for proved and unproved properties in the fourth quarter of 2014 and approximately $64 million in after-tax charges for

35



rig terminations, other price-related charges and Spin-off and transition related costs. There were no similar charges or costs in 2013. Net income for 2014, excluding these charges was $650 million as reflected in the table below.
The table below reconciles net income / (loss) to core income and lists unusual and infrequent items affecting earnings for each year (in millions):
 
 
2014
 
2013
 
2012
Net income / (loss)
 
$
(1,434
)
 
$
869

 
$
699

Unusual and infrequent items:
 
 
 
 
 
 
Asset impairments
 
3,402

 

 
29

Rig terminations and other price-related costs
 
52

 

 
12

Spin-off and transition related costs
 
55

 

 

 
 
3,509

 

 
41

Tax effect of pre-tax adjustments
 
(1,425
)
 

 
17

Core income
 
$
650

 
$
869

 
$
675

Our results of operations can include the effects of significant unusual and infrequent transactions and events affecting earnings that vary widely and unpredictably in nature, timing and amount. Therefore, management uses a measure called "core income," which excludes those items. This non-GAAP measure is not meant to disassociate those items from management's performance, but rather is meant to provide useful information to investors interested in comparing our earnings performance between periods. Reported earnings are considered representative of management's performance over the long term. Core income is not considered to be an alternative to income reported in accordance with generally accepted accounting principles.
Core income for 2014, compared to 2013, benefited from higher oil production and higher realized natural gas prices, which were more than offset by lower realized oil prices and lower realized NGL prices and volumes, and higher production costs, depreciation rates, property taxes, selling, general and administrative costs and interest expenses. In addition, unit production costs increased mainly due to higher natural gas and other energy costs, and expenses for surface operations and maintenance.
Core income for the year ended December 31, 2013 was $869 million, compared to $675 million for the year ended December 31, 2012. The higher income in 2013 reflected higher oil and gas prices and volumes and higher NGL volumes, partially offset by higher depreciation rates, taxes other than on income and other expenses. Production costs decreased in 2013, compared to 2012, due to a wide range of operational efficiency initiatives implemented in 2012.

36



The following table sets forth our average production volumes of oil, NGLs and natural gas per day for each of the three years in the period ended December 31, 2014:
 
2014
 
2013
 
2012
Oil (MBbl/d)
 
 
 
 
 
      San Joaquin Basin
64

 
58

 
58

      Los Angeles Basin
29

 
26

 
24

      Ventura Basin
6

 
6

 
6

      Sacramento Basin

 

 

          Total
99

 
90

 
88

 
 
 
 
 
 
NGLs (MBbl/d)
 
 
 
 
 
      San Joaquin Basin
18

 
19

 
16

      Los Angeles Basin

 

 

      Ventura Basin
1

 
1

 
1

      Sacramento Basin

 

 

          Total
19

 
20

 
17

 
 
 
 
 
 
Natural gas (MMcf/d)
 
 
 
 
 
      San Joaquin Basin
180

 
182

 
204

      Los Angeles Basin
1

 
2

 
3

      Ventura Basin
11

 
11

 
12

      Sacramento Basin
54

 
65

 
37

          Total
246

 
260

 
256

 
 
 
 
 
 
Total Production (MBoe/d) (a)
159

 
154

 
148

Note:     MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent per day.
(a)     Natural gas volumes have been converted to Boe based on the equivalence of energy content between six Mcf of natural gas and one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, for the year ended December 31, 2014, the average prices of Brent oil and NYMEX natural gas were $99.51 per barrel and $4.34 per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 23 to 1.
Daily oil and gas production volumes averaged 159,000 Boe for the year ended December 31, 2014, compared with 154,000 Boe for the year ended December 31, 2013. Average daily oil production increased by 9,000 Boe, or by ten percent, while daily NGLs production decreased by 1,000 Boe and natural gas decreased by 14 MMcf. The increase in oil production and decline in NGL and natural gas production reflected our emphasis on high margin oil drilling and reduction of drilling capital for natural gas. Our oil production, as well as total production, increased sequentially each quarter during 2014, reaching 105,000 barrels per day and 165,000 Boe/d, respectively, in the fourth quarter, both of which were record levels for us.
For the year ended December 31, 2013, daily oil and gas production volumes averaged 154,000 Boe, compared with 148,000 Boe for the year ended December 31, 2012. Our daily liquids production increased by 5,000 Boe while our daily natural gas production increased by 4 MMcf, or less than 700 Boe. The slight increase in our natural gas production reflected increased production from acquisitions made in 2012 and associated natural gas produced from oil drilling, partially offset by lower gas production due to reduced investment in natural gas drilling in 2013.

37




The following table sets forth the average realized prices for our products:
 
2014
 
2013
 
2012
Oil Prices ($ per Bbl)
$
92.30

 
$
104.16

 
$
104.02

NGLs Prices ($ per Bbl)
$
47.84

 
$
50.43

 
$
52.76

Gas Prices ($ per Mcf)
$
4.39

 
$
3.73

 
$
2.94

The following table presents our average realized prices as a percentage of WTI, Brent and NYMEX for each of the three years in the period ended December 31, 2014:
 
2014
 
2013
 
2012
WTI oil
99
%
 
106
%
 
110
%
Brent oil
93
%
 
96
%
 
93
%
NYMEX gas
101
%
 
102
%
 
105
%
Balance Sheet Analysis
The changes in our balance sheet as of December 31, 2014 and 2013, are discussed below:
 
 
2014
 
2013
 
 
(in millions)
 
 
 
 
 
Cash and cash equivalents
 
$
14

 
$

Trade receivables, net
 
$
308

 
$
30

Inventories
 
$
71

 
$
75

Other current assets
 
$
308

 
$
149

Property, plant and equipment, net
 
$
11,685

 
$
14,008

Other assets
 
$
111

 
$
35

Accounts payable
 
$
588

 
$
448

Accrued liabilities
 
$
318

 
$
241

Long-term debt
 
$
6,360

 
$

Deferred income taxes
 
$
2,055

 
$
3,122

Other long-term liabilities
 
$
565

 
$
497

Equity / Net investment
 
$
2,611

 
$
9,989

See "Liquidity and Capital Resources" for discussion of changes in our cash and cash equivalents and long-term debt.
The increase in trade receivables was largely the result of marketing our own products directly to third parties, rather than through Occidental, beginning in mid-2014. The increase in other current assets included additional California greenhouse gas emissions allowances, an increase in the current portion of our deferred tax assets, increases in joint interest receivables and the fair value of the put option purchased in December 2014. The decrease in property, plant and equipment, net, reflected the $3.4 billion pre-tax impairment charge for proved and unproved properties and additional depreciation, depletion and amortization (“DD&A”) in 2014, partially offset by capital investments of approximately $2.1 billion. The increase in other assets reflected deferred debt costs incurred in 2014.
The increase in accounts payable reflected higher capital levels in the last quarter of 2014, compared to 2013. The increase in accrued liabilities included unpaid interest attributable to our 2014 borrowings. The decrease in deferred income taxes reflected the impact of the impairment charges, partially offset by accelerated tax depreciation of the capital investments in 2014. The increase in other long-term liabilities was mostly due to employee related liabilities. The decrease in equity / net investment reflected dividends and distributions to Occidental prior to the Spin-off and our net loss for the year.

38



Statement of Operations Analysis
The following table presents the results of our operations, including the unusual and infrequent items discussed in the "Results" section above: :
    
 
2014
 
2013
 
2012
 
(in millions)
Oil and natural gas sales (including related parties)
$
4,023

 
$
4,139

 
$
3,967

Other revenue
150

 
145

 
106

Production costs
(1,023
)
 
(960
)
 
(1,219
)
Selling, general and administrative expenses
(336
)
 
(292
)
 
(273
)
Depreciation, depletion and amortization
(1,198
)
 
(1,144
)
 
(926
)
Asset impairments
(3,402
)
 

 
(29
)
Taxes other than on income
(217
)
 
(185
)
 
(167
)
Exploration expense
(139
)
 
(116
)
 
(148
)
Interest and debt expense, net
(72
)
 

 

Other expenses
(207
)
 
(140
)
 
(130
)
Income tax (expense) / benefit
987

 
(578
)
 
(482
)
Net income / (loss)
$
(1,434
)
 
$
869

 
$
699

 
 
 
 
 
 
EBITDAX(1)
$
2,548

 
$
2,733

 
$
2,296

 
 
 
 
 
 
Effective tax rate
41
%
 
40
%
 
41
%
________________________
(1)
We define EBITDAX consistent with our Credit Facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and certain other non-cash items and unusual, infrequent charges. Our management believes EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and investment community. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. This measure is a material component of one of our financial covenants under our Credit Facilities and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.
The following table presents a reconciliation of the non‑GAAP financial measure of EBITDAX to the GAAP financial measure of net income (in millions):
 
2014
 
2013
 
2012
Net income / (loss)
$
(1,434
)
 
$
869

 
$
699

Interest expense
72

 

 

Income tax expense / (benefit)
(987
)
 
578

 
482

Asset impairments
3,402

 

 
29

Depreciation, depletion and amortization
1,198

 
1,144

 
926

Exploration expense
139

 
116

 
148

Other non-cash items
51

 
26

 

Unusual and infrequent charges(a)
107

 

 
12

EBITDAX
$
2,548

 
$
2,733

 
$
2,296

(a)
Includes rig terminations and other price-related costs, and Spin-off and transition related costs.







39




The following represents key metrics of our oil and gas operations, excluding certain corporate items, on a per BOE basis for the years ended December 31, 2014, 2013 and 2012:
 
2014
 
2013
 
2012
Production costs
$
17.64

 
$
17.10

 
$
22.58

General and administrative expenses(a)
$
2.31

 
$
2.35

 
$
2.48

Other operating expenses(b)
$
0.55

 
$
0.60

 
$
0.33

Depreciation, depletion and amortization
$
20.40

 
$
20.11

 
$
16.82

Taxes other than on income
$
3.50

 
$
3.05

 
$
3.09

(a)    For 2014, the amount excludes unusual and infrequent costs of $0.10 per Boe related to Spin-off and transition related costs.
(b)
For 2014, the amount excludes unusual and infrequent costs related to rig termination charges and Spin-off and transition related costs of $0.97 per Boe. For 2012, the amount excludes rig termination charges of $0.22 per Boe.
   
Year Ended December 31, 2014 vs. 2013
Oil and natural gas sales decreased 3%, or $116 million, in 2014, compared to 2013. Lower oil prices, which declined significantly in the second half of 2014, contributed $377 million to this decrease, lower natural gas volumes contributed $71 million and lower NGL prices and volumes contributed $54 million. Partially offsetting these decreases were $318 million related to higher oil volumes and $61 million related to higher natural gas prices. Crude oil production increased by 9,000 Boe/d while our NGL and natural gas production decreased by 1,000 Boe/d and 14 MMcf/d, or approximately 2,000 Boe/d, respectively. The lower NGL and natural gas production reflects our planned shift in our capital toward higher margin oil projects.

Other revenue in 2014, attributable to sales from our Elk Hills power plant, was consistent with 2013.

Production costs increased by 6%, or $63 million to $17.64 per Boe in 2014, compared to $17.10 per Boe in 2013. Of this increase, $32 million was due to higher volumes and $31 million due to higher costs for natural gas used in our steamflood operations and higher energy costs and expenses for surface operations and maintenance. In the fourth quarter we started an aggressive cost containment program and have seen costs start to decline in December.

Selling, general and administrative expenses increased 15%, or $44 million, in 2014 compared to 2013, mostly due to higher employee related costs and costs related to the Spin-off. They were, however, consistent with 2013 on a per barrel basis.

DD&A expense increased 5%, or $54 million, in 2014, compared to 2013. Of this increase, $22 million was attributable to higher volumes and $32 million resulted from a higher DD&A rate, due to additional capital investments.

At year end 2014, we performed impairment tests with respect to our proved and unproved properties as a result of significant declines in oil prices largely during the last half of 2014. As a result, in the fourth quarter of 2014, we recorded pre-tax asset impairment charges of $3.4 billion on proved and unproved properties throughout our asset base. The impairment charge was related to certain properties in the San Joaquin and Los Angeles basins and a portion of our assets in the Ventura basin, as well as our gas properties in the Sacramento basin. Approximately $650 million of the charge was related to unproved acreage. The properties were impaired as a result of accounting rules that require us to evaluate our properties based on the year-end forward price curve, as well as projects we determined we would not pursue in the foreseeable future given the current environment. We expect a substantial portion of these assets would ultimately become economical as prices recover to higher levels we view as more sustainable.
 
Taxes other than on income increased 17%, or $32 million, in 2014 compared to 2013 reflecting higher property taxes largely due to a refund received in 2013, which reduced that year's property taxes.

Exploration expense increased 20%, or $23 million, in 2014 compared to 2013 mostly due to higher dry hole expenses in the San Joaquin basin, including $12 million of non-core charges.

Interest expense in 2014 was $72 million, due to our debt incurred in connection with the Spin-off of approximately $6.4 billion in the fourth quarter of 2014.


40



Other expenses increased 48%, or $67 million in 2014, compared to 2013, and included non-core rig termination costs of $33 million and $35 million for Spin-off, transition and other related items.

Provision for income taxes showed a benefit of $987 million in 2014, reflecting the pre-tax loss of approximately $2.4 billion and a slight increase in the effective tax rate compared to 2013.

Year Ended December 31, 2013 vs. 2012
Oil and natural gas sales increased 4%, or $172 million, in 2013, compared to 2012. Of this increase, $47 million was attributable to higher oil and natural gas volumes, $77 million was attributable to higher oil and gas prices and $63 million was attributable to higher volumes for NGLs. The increase was partially offset by $15 million attributable to 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 700 Boe. The increase in liquids production primarily reflected our strategy to increase our overall capital investment 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 natural gas produced from oil drilling, partially offset by lower natural gas production due to reduced investment in natural gas drilling in 2013.
Other revenue increased 37%, or $39 million in 2013, compared to 2012, due to higher realized prices on third party power sales from our Elk Hills power plant.
Production costs decreased by $259 million to $17.10 per Boe in 2013, compared to $22.58 per Boe for 2012, almost entirely due to a wide range of operational efficiency initiatives implemented in late 2012, including activities such as 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 7%, or $19 million, 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.
DD&A expense increased by $218 million. Of this increase, $44 million was attributable to higher volumes and $174 million was attributable to a $3.29 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.
Asset impairments of $29 million in 2012 reflected the write-down of uneconomic properties in various areas, in particular natural gas properties.
Taxes other than on income increased 11%, or $18 million, in 2013, compared to 2012, primarily due to a $32 million increase in California greenhouse gas costs, which we began incurring at the beginning of 2013, partially offset by lower property taxes of $14 million.
Exploration expense decreased 22%, or $32 million, in 2013, compared to 2012, due to higher success rates resulting in lower dry hole expense of $78 million in the San Joaquin and Los Angeles basins, partially offset by higher dry hole expense of $14 million in the Ventura basin and higher expense of $30 million for seismic, geological and geophysical and lease rentals.
Other expenses increased 8%, or $10 million in 2013, compared to 2012, primarily due to higher natural gas prices for purchased natural gas used at our Elk Hills power plant and higher rig termination costs.
Provision for income taxes increased by $96 million due to the effect of higher pre-tax income of $266 million, partially offset by a 1% lower effective tax rate.
Liquidity and Capital Resources
The primary source of liquidity and capital resources to fund our capital programs is cash flow from operations. Through November 2014, any excess cash generated by our business was distributed to Occidental, and our cash needs were provided by Occidental, in the form of a contribution. We expect our needs for capital investments and any potential acquisitions for at least the next twelve months will be met by cash generated from operations, and borrowings when necessary. We may, however, consider other options, such as joint ventures and similar arrangements as we work to deleverage. At December 31, 2014, we

41



had more than $1.6 billion available on our revolving credit facilities, which has effectively been reduced by $750 million under the first amendment to our credit facilities. Operating cash flows are largely dependent on oil and gas prices and differentials, sales volumes and costs. If the current conditions persist we expect our production levels will be affected as we will not look to accelerate production in this price environment.
Given the recent volatile and deteriorating oil price environment, as well as our leverage, we began a hedging program shortly after the Spin-off to protect our down-side price risk and preserve our ability to execute our capital program. In December 2014, we purchased put options with a $50 per barrel Brent strike price, measured as a monthly average. This initial program covers almost all of our oil production for the first six months of 2015. More recently, we put into place additional hedging instruments to protect the pricing for almost two-thirds of our expected third quarter 2015 oil production. For this program we chose a combination of Brent-based collars (between $55 and $72) for 30,000 barrels per day for July through September as well as put options at $50 per barrel Brent for 40,000 barrels per day in the same period. In addition, we sold a $75 per barrel call for 30,000 barrels per day of oil production in March through June of 2015. Going forward as an independent company, we will continue to be strategic and opportunistic in implementing any hedging program. Our objective is to protect against the cyclical nature of commodity prices to provide a level of certainty around our margins and cash flows necessary to implement our investment program.
Credit Facilities
On September 24, 2014, we entered into a credit agreement with a syndicate of lenders, providing for (i) a five-year senior term loan facility (the "Term Loan Facility") and (ii) a five-year senior revolving loan facility (the "Revolving Credit Facility" and, together with the Term Loan Facility, the "Credit Facilities"). All borrowings under these facilities are subject to certain customary conditions. We amended the Credit Facilities effective as of February 25, 2015, and changed certain of our covenants through December 31, 2016 or such earlier time as we elect and demonstrate compliance with our original covenants for two successive quarters (the "Interim Covenant Period").
The aggregate initial commitments of the lenders under the Revolving Credit Facility are $2.0 billion and under the Term Loan Facility are $1.0 billion. The Revolving Credit Facility includes a sub-limit of $400 million for the issuance of letters of credit. We will be required to repay the Term Loan Facility in equal quarterly installments equal to 2.5% (10.00% per annum) of the principal amount of the Term Loan Facility beginning on March 31, 2016. As of December 31, 2014, we had $360 million outstanding under our Revolving Credit Facility with the ability to incur total net borrowings of up to $1.25 billion during the Interim Covenant Period under this facility.
Borrowings under the Credit Facilities bear interest, at our election, at either a LIBOR rate or an alternate base rate ("ABR") (equal to the greatest of (i) the administrative agent’s prime rate, (ii) the one-month LIBOR rate plus 1.00% and (iii) the federal funds effective rate plus 0.50%), in each case plus an applicable margin. This applicable margin is based on our most recent leverage ratio and will vary from (a) in the case of LIBOR loans, 1.50% to 2.25% and (b) in the case of ABR loans, from 0.50% to 1.25%. The unused portion of the Revolving Credit Facility is subject to commitment fees ranging from 0.30% to 0.50% per annum, based on our most recent leverage ratio. We also pay customary fees and expenses under the Revolving Credit Facility.
Interest payments under the Credit Facilities vary based on the borrowing options chosen. Interest on ABR loans is payable quarterly in arrears.  Interest on LIBOR loans is payable at the end of each LIBOR period.   
All obligations under the Credit Facilities are guaranteed jointly and severally by all of our wholly-owned material subsidiaries, and will be unsecured while we maintain our credit ratings at the minimum levels defined in the Credit Facilities. During the Interim Covenant Period, we would be required to grant security to our lenders if our corporate family ratings experienced a two-notch decline from either of our rating agencies. Outside the Interim Covenant Period we would be required to grant security in the event of a three-notch decline subject to certain exceptions described in our Credit Facilities. The assets and liabilities of subsidiaries not guaranteeing the debt are de minimis.
The Credit Facilities also require us to maintain the following financial covenants for the trailing twelve months ended as of the last day of each fiscal quarter: (a) a leverage ratio of no more than 4.50 to 1.00 except during the Interim Covenant Period when the ratio increases by varying amounts to a maximum of 8.25 to 1.00 by December 31, 2015 and (b) an interest expense ratio of no less than 2.50 to 1.00 except as of December 31, 2015 when the ratio must be no less than 2.25 to 1.00. In addition, during the Interim Covenant Period, we must maintain an asset coverage ratio of no less than 1.05 to 1.00 measured as of the last day of each fiscal quarter. Finally, during the Interim Covenant Period, we must apply cash on hand in excess of $250 million to repay certain amounts outstanding under the Revolving Credit Facility. If we were to breach either of these covenants the banks would be permitted to accelerate the principal amount due under the facilities. If payment were accelerated it would result in a default under the notes.

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Senior Notes
On October 1, 2014, we issued $5.00 billion in aggregate principal amount of our senior notes, including $1.00 billion of 5% senior notes due January 15, 2020 (the "2020 notes"), $1.75 billion of 51/2% senior notes due September 15, 2021 (the "2021 notes") and $2.25 billion of 6% senior notes due November 15, 2024 (the "2024 notes" and together with the 2020 notes and the 2021 notes, the ‘‘notes’’), in a private placement.
We will pay interest on the 2020 notes semi-annually in cash in arrears on January 15 and July 15 of each year, beginning on July 15, 2015. We will pay interest on the 2021 notes semi-annually in cash in arrears on March 15 and September 15 of each year, beginning on March 15, 2015. We will pay interest on the 2024 notes semi-annually in cash in arrears on May 15 and November 15 of each year, beginning on May 15, 2015.
In connection with the private placement of the notes, we granted the initial purchasers certain registration rights under a registration rights agreement. We expect to file a registration statement to register the exchange of the notes in the near future.
The indenture governing the notes includes covenants that, among other things, limit our and our restricted subsidiaries’ ability to incur debt secured by liens. These covenants also restrict our ability to merge or consolidate with, or transfer all or substantially all of our assets to, another entity. These covenants are subject to a number of important qualifications and limitations that are set forth in the indenture. The covenants are not, however, directly linked to measures of our financial performance. In addition, if we experience a “change of control triggering event” (as defined in the indenture) with respect to a series of notes, we will be required, unless we have exercised our right to redeem the notes of such series, to offer to purchase the notes of such series at a purchase price equal to 101 percent of their principal amount, plus accrued and unpaid interest.
Spin-off Related Distributions to Occidental
We used the net proceeds from the private placement of our notes to make a $4.95 billion cash distribution to Occidental in October 2014. See “—Senior Notes” for more details regarding the terms of our senior notes. On November 25, 2014, we borrowed $1.0 billion under our Term Loan Facility and $50 million under a Revolving Credit Facility to make a $1.05 billion cash distribution to Occidental on November 26, 2014.
Cash Flow Analysis
 
 
2014
 
2013
 
2012
 
 
(in millions)
Net cash flows provided by operating activities
 
$
2,371

 
$
2,476

 
$
2,223

Net cash flows used in investing activities
 
$
(2,312
)
 
$
(1,713
)
 
$
(2,755
)
Net cash flows (used in) provided by financing activities
 
$
(45
)
 
$
(763
)
 
$
532

EBITDAX (1)
 
$
2,548

 
$
2,733

 
$
2,296

____________________________
(1)    We define EBITDAX consistent with our Credit Facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and certain other non-cash items and unusual, infrequent charges. Our management believes EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and investment community. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. This measure is a material component of one of our financial covenants under our Credit Facilities and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

43



The following table sets forth a reconciliation of the non-GAAP financial measure of EBITDAX to the GAAP measure of net cash provided by operating activities:
 
 
2014
 
2013
 
2012
 
 
(in millions)
Net cash provided by operating activities
 
$
2,371

 
$
2,476

 
$
2,223

Interest expense
 
72

 

 

Current income taxes
 
165

 
318

 
(121
)
Cash exploration expenses
 
38

 
44

 
20

Changes in operating assets and liabilities
 
(143
)
 
(103
)
 
202

Other, net
 
45

 
(2
)
 
(28
)
EBITDAX
 
$
2,548

 
$
2,733

 
$
2,296

Year Ended December 31, 2014 vs. 2013
Our operating cash flows in 2014 decreased by $105 million from $2.5 billion in 2013 to $2.4 billion in 2014. The decrease reflected approximately $110 million in lower sales due to lower oil and NGL prices partially offset by higher oil volumes and gas prices, higher interest expense of $70 million, higher production costs of approximately $65 million, higher taxes other than on income of $30 million, higher selling, general and administrative costs of $20 million, partially offset by lower income taxes of $150 million and working capital changes of $40 million in 2014 compared to 2013.
Our cash flows used in investing activities increased by approximately $600 million in 2014, to $2.3 billion in 2014, compared to $1.7 billion in 2013. The increase mainly consisted of approximately $350 million of higher capital investments and higher acquisition costs of $240 million. The 2014 capital investments reported in the statement of cash flows exclude the effect of accruals. Total capital investments in 2014 were $2.1 billion, of which $2.0 billion was paid in cash during the year as reported in the statement of cash flows and $69 million reflected an increase in capital accruals. For the years 2013 and 2012, the capital accrual amount was not material.
Our net cash flows used in financing activities decreased by approximately $720 million in 2014, compared to 2013, and reflected the dividend distribution of $6.0 billion to Occidental prior to the Spin-off, proceeds of approximately $6.3 billion of debt, net of $70 million of debt issuance costs, and lower excess cash distributions to Occidental prior to the Spin-off.
Year Ended December 31, 2013 vs. 2012
Our operating cash flows in 2013 increased by approximately $250 million compared to 2012. The increase reflected lower operating expenses of $250 million resulting from cost efficiencies and $210 million in higher revenues due to higher oil and gas prices and volumes. Other significant items affecting operating cash flows consisted of higher tax payments of $440 million and other costs of $70 million in 2013, as well as $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 investments 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.
Acquisitions
During the year ended December 31, 2014, we paid approximately $290 million to acquire certain producing and nonproducing oil and gas properties, including oil and gas properties in the Ventura Basin purchased for approximately $200 million in the fourth quarter of 2014.
During the year ended December 31, 2013, we paid approximately $50 million to acquire certain oil and gas properties. An acquisition in the San Joaquin basin also included an obligation to invest at least $250 million on exploration and development activities over a period of five years from the date of acquisition. We currently plan to invest significantly more than this amount in capital during that period. Any deficiency in meeting this capital investment obligation would need to be

44



paid in cash at the end of the five-year period. Through December 31, 2014, we have already fulfilled about 20% of this obligation.
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.
Portfolio Management, 2014 Capital Program and 2015 Capital Budget
We develop our capital investment programs by prioritizing life of project returns to grow our net asset value over the long term, while balancing the short- and long-term growth potential of each of our assets. We use a Value Creation Index (“VCI”) metric for project selection and capital allocation across our portfolio of opportunities. The VCI for each project is calculated by dividing the present value of the project's pre-tax cash flow before capital over its life by the present value of the investment, using a 10% discount rate. Projects are expected to meet a VCI of 1.3, meaning that 30% of expected value is created above every dollar invested.
In 2014 we invested $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 investments were directed toward oil-weighted production consistent with 2013. Of the total 2014 capital program, approximately $1.3 billion was allocated to well drilling and completions, $181 million to workovers, $346 million to surface support equipment to handle higher production, $36 million to additional steam generation capacity expansion, $100 million to exploration and the rest to maintenance capital, health, safety and environmental projects and other items.
The table below sets forth our 2014 capital investments for the year ended December 31, 2014 (in millions):
 
Conventional
 
Unconventional
 
Other
 
Total Capital Investments
 
Primary
 
Waterflood
 
Steamflood
 
Total
 
Primary
 
 
Basin:
 
 
 
 
 
 
 
 
 
 
 
 
 
San Joaquin
$
280

 
$
129

 
$
381

 
$
790

 
$
604

 
$

 
$
1,394

Los Angeles
3

 
466

 

 
469

 

 

 
469

Ventura
82

 
13

 
8

 
103

 
1

 

 
104

Sacramento
14

 

 

 
14

 
1

 

 
15

Basin Total
379

 
608

 
389

 
1,376

 
606

 

 
1,982

Exploration and Other

 

 

 

 

 
107

 
107

Total
$
379

 
$
608

 
$
389

 
$
1,376

 
$
606

 
$
107

 
$
2,089

In light of current commodity prices, our focus on creating value and our commitment to internally fund our capital budget with operating cash flows, we have significantly reduced our capital investment budget for 2015 to $440 million, as compared to $2.1 billion in 2014. We have focused a substantial majority of our 2015 budget on our mature steamfloods, waterfloods and capital workovers, which have much lower decline rates than many unconventional projects. We will also continue to pursue and fund our most attractive conventional and unconventional projects.

45



Our 2015 capital investment budget targets investments in the San Joaquin, Los Angeles and Ventura basins, and is expected to be directed towards oil-weighted production consistent with 2014. Of the total 2015 capital budget, approximately $150 million is allocated to drilling wells, $50 million to workovers, $130 million to additional steam-generation capacity and compression expansion, $15 million to exploration and the rest to 3D seismic, maintenance capital, occupational health, safety and environmental projects and other items. The table below sets forth the expected allocation of our 2015 capital budget by recovery mechanism.
 
 
Total 2015 Capital
Investments Budget
 
 
(in millions)
Conventional:
 
 
 
Primary recovery
 
$
40
 
Waterfloods
 
175
 
Steamfloods
 
155
 
Total conventional
 
370
 
Unconventional
 
35
 
Exploration
 
15
 
Corporate and other
 
20
 
Total
 
$
440
 

In addition, during this period of lower activity levels, we will deploy our resources to refine modern techniques that will enhance the value and growth potential of other parts of our portfolio that will not be funded in 2015 and will continue to build our inventory of available projects. This will position us to rapidly take advantage of improved market conditions when prices reach more favorable levels.

Off‑Balance-Sheet Arrangements
We have no material off‑balance-sheet arrangements other than those noted below.
Leases
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."

46



Contractual Obligations
The table below summarizes and cross‑references our contractual obligations as of December 31, 2014. This summary indicates on and off‑balance-sheet obligations as of December 31, 2014.
 
 
Payments Due by Year
 
 
Total
 
2015
 
2016 and 2017
 
2018 and 2019
 
2020 and thereafter
 
 
(in millions)
On-Balance Sheet
 
 
 
 
 
 
 
 
 
 
Long-term debt (Note 5)(a)
 
$
6,360

 
$

 
$
200

 
$
1,160

 
$
5,000

Other long-term liabilities(b)
 
147

 
6

 
19

 
16

 
106

 
 
 
 
 
 
 
 
 
 
 
Off-Balance Sheet
 
 
 
 
 
 
 
 
 
 
Operating leases
 
125

 
13

 
28

 
26

 
58

Purchase obligations(c)
 
364

 
70

 
79

 
204

 
11

 
 
 
 
 
 
 
 
 
 
 
Total
 
$
6,996

 
$
89

 
$
326

 
$
1,406

 
$
5,175

(a)     Excludes interest on the debt. As of December 31, 2014, interest on long-term debt totaling $2.4 billion is payable in the following years (in millions): 2015 - $312, 2016 and 2017 - $620, 2018 and 2019 - $608, 2020 and thereafter - $825. The calculation of interest payable on the variable interest debt assumes the interest rate at December 31, 2014 to be the applicable interest rate for the entire term. In performing the calculation, the Revolving Credit Facility borrowings outstanding at December 31, 2014 of $360 million were assumed to be outstanding for the entire term of the agreement.
(b) Includes obligations under postretirement benefit and deferred compensation plans, as well as certain accrued liabilities.
(c)     Amounts include payments, which will become due under long‑term agreements to purchase goods and services used in the normal course of business to secure pipeline capacity, drilling rigs and services. These amounts were significantly reduced as a result of rig contract terminations in 2014. Long-term purchase contracts are discounted using a discount rate of approximately 5%.
Lawsuits, Claims, Contingencies and Commitments
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, 2014 and 2013 were not material to our balance sheets as of such dates. 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 our balance sheet would not be material to our consolidated financial position or results of operations.
We, our subsidiaries, or both, have indemnified various parties against specific liabilities those parties might incur in the future in connection with the Spin-off, purchases and other transactions that they have entered into with us. These indemnities include indemnities made to Occidental against certain tax-related liabilities that may be incurred by Occidental relating to the Spin-off and liabilities related to operation of our business while it was still owned by Occidental. As of December 31, 2014, we are not aware of circumstances that we believe would reasonably be expected to lead to indemnity claims that would result in payments materially in excess of reserves.
Critical Accounting Policies and Estimates
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.

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Oil and Gas Properties
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 volumes 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 investments.
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 the carrying value 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 $1.00 per Bbl, which would increase or decrease pre‑tax income by approximately $60 million annually based on production rates for the year ended December 31, 2014.
A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At December 31, 2014, the net capitalized costs attributable to unproved properties were approximately $300 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 write-downs 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.
At year end 2014, we performed impairment tests with respect to our proved and unproved properties as a result of significant declines in oil prices largely during the last half of 2014. As a result, in the fourth quarter of 2014, we recorded pre-

48



tax asset impairment charges of $3.4 billion on proved and unproved properties throughout our asset base. The impairment charge was related to certain properties in the San Joaquin and Los Angeles basins and a portion of our assets in the Ventura basin, as well as our natural gas properties in the Sacramento basin. Approximately $650 million of the charge was related to unproved acreage. The properties were impaired as a result of accounting rules, that require us to evaluate our properties based on the year-end forward price curve, as well as projects we determined we would not pursue in the foreseeable future given the current environment. We expect a substantial portion of these assets would ultimately become economical as prices recover to higher levels we view as more sustainable.
Fair Value Measurements
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 a risk-adjusted discount rate.
The most significant items on our balance sheet that would be affected by recurring fair value measurements are derivatives. Based on year end 2014 amounts on the balance sheet for derivatives, a 10% increase or decrease in their fair value would affect income by $2.4 million.
Other Loss Contingencies
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, Contingencies and Commitments” for additional information.
Significant Accounting and Disclosure Changes
In August 2014, the Financial Accounting Standards Board (“FASB”) issued rules relating to management’s responsibility to evaluate and make disclosures, if applicable, regarding the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. These rules are effective for annual periods ending after December 15, 2016. They are not expected to have a material impact on our financial statements upon adoption and will require assessment on an ongoing basis.
In June 2014, the FASB issued rules for employee share-based payment awards in which the terms of the awards provide that a performance target can be achieved after the requisite service period. A performance target that affects vesting and that could be achieved after the requisite service period will be treated as a performance condition. These rules are effective for annual periods beginning on or after December 15, 2015 and are not expected to have a material impact on our financial statements upon adoption but will require assessment on an ongoing basis.
In May 2014, the FASB issued rules related to revenue recognition. Under the new rules, an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects what it expects to receive in exchange for the goods or services. The rules will also require more detailed disclosures of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The rules are effective for interim and annual periods beginning after December 15, 2016 and early application is not permitted. While we are evaluating any potential impact of these new rules, we currently believe the effect of the new rules will not have a material impact on our financial statements.
In April 2014, the FASB issued rules changing the requirements for reporting discontinued operations such 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

49



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.
Qualitative and Quantitative Disclosures about Market Risk
Commodity Price Risk
General
Our results are sensitive to fluctuations in oil, NGL and gas prices. Price changes at current levels of production affect our pre‑tax annual income by approximately $32 million for a $1 per Bbl change in Brent oil prices and $4 million for a $1 per Bbl change in NGL prices. If natural gas prices varied by $0.50 per Mcf, it would have an estimated annual effect on our pre-tax income of approximately $20 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.
Derivatives
In February 2015, we put into place hedging instruments to protect the pricing for almost two-thirds of our expected third quarter 2015 oil production. For this program we chose a combination of Brent-based collars (between $55 and $72) for 30,000 barrels per day for July through September as well as put options at $50 per barrel Brent for 40,000 barrels per day in the same period. In addition, we sold a $75 per barrel call for 30,000 barrels per day of oil production in March through June of 2015. Going forward as an independent company, we will continue to be strategic and opportunistic in implementing any hedging program. Our objective is to protect against the cyclical nature of commodity prices to provide a level of certainty around our margins and cash flows necessary to implement our investment program.
In December 2014, we purchased put options, to hedge the risk associated with declining oil prices, for 100,000 barrels of crude oil production per day, effective on a monthly basis from January 1, 2015 through June 30, 2015. The strike price of the put option is $50 per barrel and is tied to the Brent oil index. Changes in the intrinsic value of the put option are deferred in other comprehensive income/(loss) as a cash flow hedge until the hedged transactions are recognized in the statement of operations. Changes in the time value of the put option are marked to market through the statement of operations. The time value of the put option was valued using Level 2 inputs in the fair value hierarchy and was valued at approximately $24 million in other current assets, as of December 31, 2014, which approximated the value of the instrument and the amount we paid the counterparty at the time the option was acquired.
In November 2012, we entered into financial swap agreements for the sale of 50 MMcf/d of our natural 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.
Credit Risk
Our credit risk relates primarily to trade receivables and derivative financial instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. For the derivative options entered into in December 2014, we are subject to counterparty credit risk to the extent the counterparty to this derivative is unable to meet its settlement commitments. We actively manage this credit risk by selecting counterparties that we believe to be financially strong and continuing to monitor their financial health.
As of December 31, 2014, 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, 2014 was not material and losses associated with credit risk have been insignificant for all years presented.
Concentration of Credit Risk
Through July 2014, substantially all of our products were sold through Occidental’s marketing subsidiaries at market prices and were settled at the time of sale to those entities. Beginning August 2014, we began marketing our own products directly to third parties. For the years ended December 31, 2014, 2013 and 2012, sales through Occidental subsidiaries accounted for approximately 65%, 97% and 97% of our net sales, respectively. For the years ended December 31, 2014, 2013 and 2012, ConocoPhillips/Phillips 66 Company and Tesoro Refining & Marketing Company LLC each accounted for more than 10% of our net sales. Collectively, they accounted for 45%, 42% and 46% in each of those years, respectively. No other customer accounted for more than 10% of our net sales during these periods.

50



Interest Rate Risk
Historically, we had no interest rate risk exposure as we did not have debt balances. In November 2014, we made initial borrowings on our variable-rate Credit Facilities. As of December 31, 2014, we had borrowings of $1.0 billion outstanding under our Term Loan Facility and approximately $360 million outstanding under our Revolving Credit Facility. A one-eighth percent change in the variable interest rates on these outstanding borrowings under our Term Loan Facility and Revolving Credit Facility would result in an approximately $1.7 million change in annual interest expense.
The following table shows our fixed- and variable-rate debt as of December 31, 2014:
Year of Maturity
 
U.S. Dollar Fixed-Rate Debt
 
U.S. Dollar Variable-Rate Debt
 
Total
 
 
(amounts in millions)
2015
 
$

 
$

 
$

2016
 

 
100

 
100

2017
 

 
100

 
100

2018
 

 
100

 
100

2019
 

 
1,060

 
1,060

Thereafter
 
5,000

 

 
5,000

Total
 
$
5,000

 
$
1,360

 
$
6,360

Weighted-average interest rate
 
5.63
%
 
2.24
%
 
4.9
%
Fair Value
 
$
4,285

 
$
1,360

 
$
5,645



51



BUSINESS
Our Company
We are an independent oil and natural gas exploration and production company operating properties exclusively within the State of California. Our business is focused on conventional and unconventional assets, exclusively in California, which can generate positive cash flow throughout the oil and natural gas price cycle and have the capacity to provide significant production and cash flow growth in a higher price environment. We are the largest oil and gas 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 2.4 million net acres spanning the state’s four major oil and gas basins. We produced on average approximately 159 MBoe/d net for the year ended December 31, 2014. As of December 31, 2014, we had net proved reserves of 768 MMBoe, with approximately 72% proved developed. Oil represented 72% of our proved reserves. Our aggregate PV-10 value was $16.1 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 “Reserves and Production Information" below. Our current drilling inventory comprises a diversified portfolio of oil and natural gas locations, which allows us to target drilling projects that are economically viable even in a low commodity price environment.
Approximately 56% of our 2014 production was generated by our world-class Elk Hills and Wilmington fields. The remaining 44% was generated through a combination of conventional primary, steamflood and waterflood projects as well as unconventional projects. We develop our capital investment programs by prioritizing life of project returns to grow our net asset value over the long term, while balancing the short- and long-term growth potential of each of our assets. We use the VCI metric for project selection and capital allocation across our portfolio of opportunities. The VCI for each project is calculated by dividing the net present value of the project's pre-tax cash flow over its life by the present value of the investment, using a 10% discount rate. Projects are expected to meet a VCI of 1.3, meaning that 30% of value is created for every dollar invested.
The following table summarizes certain information concerning our acreage, wells and drilling activities (as of December 31, 2014, acres and dollars in millions, unless otherwise stated):
 
 
Acreage
 
Gross Acreage Held in Fee (%)
 
Producing Wells, gross
 
Average Working Interest (%)
 
Identified Drilling Locations(1)
 
2015 Projected Gross Development Wells (2)
 
2015
Projected
Development
Drilling
Capital(3)
 
 
Gross
 
Net
 
 
 
 
Gross
 
Net
 
 
San Joaquin Basin
 
1.9

 
1.6

 
58
%
 
6,379

 
91
%
 
14,450

 
12,600

 
265

 
96

Los Angeles Basin(4)
 
<0.1

 
<0.1

 
49
%
 
1,476

 
93
%
 
2,000

 
1,900

 
25

 
54

Ventura Basin
 
0.3

 
0.3

 
67
%
 
757

 
89
%
 
2,350

 
1,800

 

 

Sacramento Basin
 
0.7

 
0.5

 
34
%
 
719

 
80
%
 
1,000

 
900

 

 

Total
 
2.9

 
2.4

 
53
%
 
9,331

 
89
%
 
19,800

 
17,200

 
290

 
150

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(1)
Our total identified drilling locations include approximately 2,400 gross (2,300 net) locations associated with proved undeveloped reserves as of December 31, 2014 and 2,500 gross (2,400 net) injection well locations associated with our waterflood and steamflood projects. Our total identified drilling locations exclude 6,400 gross (5,300 net) prospective resource drilling locations. Please see "—Our Reserves and Production Information" for more information regarding the processes and criteria through which we identified our drilling locations. Of our total identified drilling locations, we believe approximately 75% are attributable to acreage owned or held by production.
(2)
Includes 55 injection wells expected to be drilled in connection with our steamflood and waterflood projects.
(3)
Includes drilling and completion expenditures of $16 million associated with injection wells. Our total 2015 capital budget of $440 million also includes investments in support equipment, seismic, workovers and exploration.
(4)
We currently hold approximately 40,400 gross (34,400 net) acres in the Los Angeles basin. Our Los Angeles basin operations are concentrated with pad drilling.

During 2014, we operated an average of 26 drilling rigs across the state with the majority located in the San Joaquin and Los Angeles basins. We drilled 1,048 development wells with 847 wells in the San Joaquin basin, 177

52



in the Los Angeles basin, 21 in the Ventura basin, and 3 in the Sacramento basin. We also drilled 9 exploration wells in the San Joaquin basin, 4 in the Ventura basin and 1 in the Sacramento basin.
As market conditions changed in the fourth quarter of 2014, we reduced our investment and drilling pace and exited the year with an active count of six drilling rigs. We currently have three active rigs with two drilling in the San Joaquin basin (targeting steamflood activities), one in the Los Angeles basin (targeting waterflood activities), and none in the Ventura and Sacramento basins. We have also reduced our workover rig count to focus on projects that meet our investment criteria in the current environment. With significant operating control of our properties, we have the ability to adjust our drilling and workover rig count in 2015 based on commodity prices and are monitoring market conditions to increase or decrease our program accordingly.
Our large acreage position contains numerous development and growth opportunities due to its varied geologic characteristics and multiple stacked pay reservoirs which, in many cases, are thousands of feet thick. We have a large portfolio of lower-risk, high-growth-potential conventional opportunities in each of our major oil and gas basins with approximately 72% of our proved reserves associated with conventional opportunities. Conventional reservoirs are capable of natural flow using primary, steamflood and waterflood recovery methods. In 2014, we targeted our capital investments primarily toward conventional development projects, including an increasing number of lower-risk steamflood recovery projects, that we expect will contribute significantly to near-term production and cash flow. We also have a significant portfolio of unconventional growth opportunities in lower permeability reservoirs which typically utilize established well stimulation techniques. We have approximately 4,800 identified drilling locations targeting unconventional reservoirs primarily in the San Joaquin basin. Over the last few years, we have continued to focus on higher-value unconventional production by exploiting seven discrete stacked pay horizons within the Monterey formation, primarily within the upper Monterey. We are seeking to duplicate our results there in the Kreyenhagen and Moreno formations which have similar geological attributes. Over the longer-term, as project economics increase, we intend to pursue development opportunities in the lower Monterey shale, which contains a variety of reservoir lithologies, but has an extremely limited production history compared to the upper Monterey.
Over the past decade, we have also built a 3D seismic library that covers over 4,250 square miles, representing approximately 90% of the 3D seismic data available in California. We have developed unique, proprietary stratigraphic and structural models of the subsurface geology and hydrocarbon potential in each of the four basins in which we operate. In recent years we have tested and successfully implemented various exploration, drilling, completion and enhanced recovery technologies to increase recoveries, growth and returns from our portfolio.
Our Operations
Our Areas of Operation
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. According to the California Division of Oil, Gas and Geothermal Resources (“DOGGR”), cumulative California production from all four basins in which we operate is 35 billion barrels of oil equivalent (“BBoe”), including approximately 19 BBoe in the San Joaquin basin, 10 BBoe in Los Angeles basin, 4 BBoe in Ventura basin and 10 trillion cubic feet (“Tcf”) of natural gas in Sacramento basin. Additionally, Kern County has been the largest oil producing county in the lower 48 states for a number of years. California imports more than 60% 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 has typically allowed California producers to receive Brent-based prices, which are international waterborne prices. Brent prices were at a premium to WTI-based prices for comparable grades in recent years. Our operations include 137 fields with 9,331 gross active wellbores as of December 31, 2014. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.4 million net acres. Approximately 60% of our total net 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.

53



Across all of our California operations, we drilled 1,048 development wells in 2014, of which 83% were producers and the rest were injectors. Our 2014 drilling capital was approximately $1.3 billion. Our 2014 total capital of $2.1 billion also included investments in support equipment, facilities, workovers and exploration. Our capital program added 118 MMBoe of proved reserves in 2014 representing a 203% reserve replacement ratio, calculated by using the proved reserves additions from our capital program for 2014 divided by our 2014 production of 58 MMBoe.
San Joaquin Basin
We actively operate and are developing 45 fields in this inland basin in the southern part of California's central valley which consists of conventional primary, IOR, EOR and unconventional project types with approximately 1.6 million net acres, approximately 62% of which we hold in fee. Approximately 68% of our estimated proved reserves as of December 31, 2014 and 70% of our average daily net production for the year ended December 31, 2014 were located in the San Joaquin basin.


54



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. 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 as of 2012, the San Joaquin basin contained three of the 10 largest oil fields in the United States based on cumulative production and proved reserves. 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. 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 2,972 square miles in the San Joaquin basin, including approximately 50% of our San Joaquin acreage, will give us a competitive advantage in further exploring this basin.
We have established a large ownership interest in several of the largest existing oil fields in the San Joaquin basin, including Elk Hills, our largest producing field, as well as the Buena Vista and Kettleman North Dome fields.
Elk Hills
Elk Hills is one of the largest fields in the continental United States based on proved reserves and has produced over 1.6 BBoe. During the year ended December 31, 2014, we produced 64 MBoe/d on average from our Elk Hills properties, or approximately 40% of our total average daily production. Of our total Elk Hills production more than 60% is liquids. At Elk Hills, we operate efficient natural gas processing facilities with a combined capacity of over 540 MMcf/d. Additionally, we generate sufficient electricity to operate the field and sell excess power to the grid. Our operations at Elk Hills possess a state-of-the-art central control facility and remote automation control on over 95% of our wells.
Los Angeles Basin
We actively operate and are developing 10 fields in this urban, coastal basin which consists of conventional primary, IOR, EOR and unconventional project types, approximately half of which we hold in fee. Approximately 22% of our estimated proved reserves as of December 31, 2014 and 18% of our average daily net production for the year ended December 31, 2014 were located in the Los Angeles basin.
The basin is a northwest-trending plain about 50 miles long and 20 miles wide containing prolific Miocene through Pleistocene sediments. Most of the significant discoveries in the Los Angeles basin date back to the 1920s. The Los Angeles basin has one of the highest concentrations per acre of crude oil in the world with 68 fields named in an area of about 450 square miles. The basin contains multiple stacked formations throughout its depths, and we believe that the Los Angeles basin provides a considerable inventory of existing field re-development opportunities as well as new play discovery potential. Large active oil fields include the Huntington and the Wilmington fields, where we have significant operations as described further below.

Wilmington Oil Field
The Wilmington field located in Long Beach is the third largest field in the United States and has produced over 2.9 BBoe. During the year ended December 31, 2014, we produced approximately 36,000 Boe/d gross on average, or 91% of the Wilmington field daily production from all producers for the year, where we operate on behalf of the State of California and the City of Long Beach. Our net production in this field equates to approximately 16% of our total average daily production. Most of our Wilmington production is covered under a set of contracts similar to production-sharing contracts under which we recover capital and operating costs and our share of profits from production. The field is developed by applying waterflood methods of oil recovery. Our waterflood operations have

55



attractive margins and returns in the current price environment and extend the productive life of our reservoirs beyond the economic life expected for primary development.
Ventura Basin
We actively operate and are developing 29 fields in this central California coastal basin which consists of primary conventional, IOR, EOR and unconventional project types. We currently hold approximately 0.3 million net acres in the Ventura basin, approximately 72% of which we hold in fee. Approximately 8% of our estimated proved reserves as of December 31, 2014 and approximately 6% of our average daily net production for the year ended December 31, 2014 were located in the Ventura basin.
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. 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 exploration potential.
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.

Sacramento Basin
We actively operate and are developing 53 fields in this inland basin in the northern part of California's central valley, primarily consisting of dry gas production. We currently hold approximately 0.5 million net acres in the Sacramento basin, approximately 35% 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 natural gas price environment. Approximately 2% of our estimated proved reserves as of December 31, 2014 and approximately 6% of our average daily net production for the year ended December 31, 2014 were located in the Sacramento basin.
The Sacramento basin is a deep, elongated northwest-trending basin covering about 12,000 square miles. It contains a thick sequence of sedimentary deposits that range in age from the lower Cretaceous to Neogene. Exploration in the basin started in 1918.

Conventional Reservoir Recovery Methods
We determine which 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, EOR methods like steamflooding and IOR methods such as waterflooding, using both vertical and horizontal drilling. All of these techniques are proven technologies we have used extensively in California.
Primary Recovery
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 energy of the reservoir. Our successful exploration program continues to provide us with primary recovery opportunities in new reservoirs or through extensions of existing fields. Our conventional development programs create future opportunities to convert these reservoirs to steamfloods or waterfloods after their primary production phase.

56



Steamfloods
Some of our fields contain heavy, thick oil. Steamfloods work by injecting steam into the reservoir to heat the oil, decreasing its viscosity, or thinning the oil, allowing it to flow more easily to the producing wellbores. Steamflooding is a well understood process that has been used in California since the early 1960s. This process has been known to increase recovery factors from approximately 10% under primary recovery methods, to up to approximately 75%. Thermal operations are most effective in shallow reservoirs containing heavy, viscous oil. The steamflood process is generally characterized by low capital investment with attractive margins and returns even in the current price environment. The economics of steamflooding are largely a function of the ratio between oil and natural gas prices. After drilling, these operations typically ramp up production over one to two years as the steam continues to influence the oil production, and then exhibit a plateau for several months, with a subsequent low, predictable oil production decline rate of 5 to 10% per year. This gradual decline allows us to extend the productive life of a reservoir and significantly increase our incremental recovery after primary depletion. We use steamfloods extensively in the San Joaquin basin, where they have allowed us to grow our production from mature fields such as Kern Front and Lost Hills, among others.
Waterfloods
Some of our fields have been partially produced and no longer have sufficient energy to drive oil to our producing wellbores. Waterflooding is a well understood process that has been used in California for over 50 years to re-introduce energy to the reservoir through water injection and to sweep oil to producing wellbores. This process has been known to increase recovery factors by approximately double those experienced under primary recovery methods. Our waterflood operations have 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.
Unconventional Reservoir Potential
We believe our undeveloped unconventional acreage has the potential to provide significant long-term production growth. In total we hold mineral interests in approximately 1.3 million net acres with unconventional potential and have identified over 4,900 gross (4,400 net) unconventional drilling locations on this acreage. As a result of focusing more on these reservoirs over the past few years, approximately 36% of our 2014 production was from unconventional reservoirs, an increase of approximately 150% since the acquisition of our Elk Hills field properties in 1998. As of December 31, 2014, we had proved reserves of 216 MMBoe associated with our unconventional properties, with approximately 24% proved undeveloped.
We hold significant interests in the Monterey formation, which is divided into upper and lower intervals. We have successfully produced from seven discrete stacked pay horizons within the Upper Monterey. The Lower Monterey is believed to be the principal source rock within the Monterey.
We plan to apply 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 and general reservoir characteristics. The lower Monterey has an extremely limited production history compared to the upper Monterey, and therefore very limited knowledge exists regarding its potential. For example, only about 25 wells have been drilled into the lower Monterey to date. However, we believe we will be able to apply knowledge we gain from the upper Monterey in the lower Monterey as well.
Exploration Program
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

57



acreage position and extensive 3D seismic library give us 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. As of December 31, 2014, our drilling inventory included 7,200 gross (5,100 net) exploration drilling locations 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.
In 2014, we continued our successful near-field and impact exploration programs in conventional and unconventional reservoirs. Our exploration program delivered a geologic success rate of approximately 80% with approximately half of those successful wells determined to be commercial in the current price environment. Notable successes include our conventional reservoir drilling results in proven play trends offsetting the Pleito Ranch field in the San Joaquin basin and the Bardsdale field in the Ventura basin.
In the San Emigdio trend, two exploration wells successfully extended the Pleito Ranch field. Both wells encountered the primary producing reservoir of the Pleito Ranch field at similar reservoir depths and pressures. Additional step-out exploration prospects have been identified that can further extend this trend.
In the Ventura basin, one exploration well encountered two hydrocarbon bearing reservoir intervals and successfully extended the depth of the known producing reservoirs. We have multiple, analogous prospects in this play trend that extends for approximately 30 miles onshore in the southern Ventura basin.
We continue to develop our understanding and knowledge of the significant prospective resources in the exploration shale reservoirs. In 2014, we completed significant log, core and seismic data acquisition projects targeting the Kreyenhagen exploration shale reservoir around the Kettleman North Dome and Middle Dome fields. We completed seven workovers in existing wellbores and drilled six new wells. In many cases, zonal completions were implemented to assess the expected performance of individual zones of interest and identify landing zones for future horizontal development.
In 2015, we expect to invest approximately three percent of our capital budget, or approximately $15 million, on exploration projects with a continued focus on prospects that can generate near-term returns. We expect exploration capital in the future to be focused in the San Joaquin, Ventura and Sacramento basins, and weighted toward projects where we have a proven track record of success.
Our Infrastructure
We own infrastructure that is integral to and significantly complements our operations. Our Elk Hills cryogenic gas plant has a capacity of 200 MMcf/d of wellhead gas bringing our total Elk Hills processing capacity to over 540 MMcf/d. We also own and operate a system of natural gas processing facilities in the Ventura basin that are capable of processing equity wellhead gas from the surrounding areas. Our natural gas processing facilities are interconnected via pipelines to nearby third-party rail and trucking facilities, with access to certain North American NGL markets. In addition, we have truck rack facilities coupled with a battery of pressurized storage tanks at our Elk Hills natural gas processing facility for NGL sales to third parties.
We generate all of our electricity needs at our Elk Hills operations, which run at about 130 megawatts, through our wholly-owned 550 megawatt combined-cycle power plant located adjacent to our Elk Hills processing facilities, and sell the excess. 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 over 40% of the Long Beach operation’s electricity requirements, reducing operating costs. These power facilities are integrated with our operations to improve their reliability and performance.
We own an extensive network of over 20,000 miles of oil and gas gathering lines. These gathering lines are dedicated almost entirely to collect our oil and gas production and are in close proximity to field specific facilities such as tank settings or central processing sites. These lines provide a variety of services, including connecting our producing wells to gathering networks, natural gas collection and compression systems, lines for water treating and

58



injection services, steam supply for our thermal properties, and water lines that deliver treated water for agriculture. Nearly all of our oil is then transported through third party pipelines with flexibility to ship to various parties. In addition, virtually all of our natural gas production interconnects with major third-party natural gas pipeline systems. As a result of these connections, we typically have the ability to access multiple delivery points to improve the prices we obtain for our oil and natural gas production.
Marketing Arrangements
We market our crude oil, natural gas, NGLs and electricity in accordance with standard energy industry practices.
Crude Oil. Substantially all of our crude oil production is connected to California markets via our crude oil gathering pipelines which are used almost entirely for our production. 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 over 60% of oil consumed during 2014 imported from outside the state, mostly from foreign locations. We sell 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 that have exceeded WTI-based prices for comparable grades in recent years. Currently, we do not have any crude oil sales contracts with a term extending past 2015.
Given the recent volatile and deteriorating oil price environment, as well as our leverage, we began a hedging program shortly after the Spin-off to protect against our down-side price risk and preserve our ability to execute our capital program. In December 2014, we purchased put options with a $50 per barrel Brent strike price, measured monthly. This initial program covers almost all of our oil production for the first six months of 2015. More recently, we put into place additional hedging instruments to protect the pricing for almost two-thirds of our expected third quarter 2015 oil production. For this program we chose a combination of Brent-based collars (between $55 and $72) for 30,000 barrels per day for July through September as well as put options at $50 per barrel Brent for 40,000 barrels per day in the same period. In addition, we sold a $75 per barrel call for 30,000 barrels per day of oil production in March through June of 2015. Going forward as an independent company, we will continue to be strategic and opportunistic in implementing any hedging program. Our objective is to protect against the cyclical nature of commodity prices to provide a level of certainty around our margins and cash flows necessary to implement our investment program.
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 contracts 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 facilitates access to third party delivery points near the Elk Hills field. We currently have pipeline capacity contracts to transport 10,000 barrels per day of NGLs to market and will add another 10,000 barrels per day of capacity beginning in the second quarter of 2015. We sell virtually all of our NGLs to third parties using index-based pricing. Our NGLs are generally sold pursuant to one-year contracts that are renewed annually.
Electricity. While part of the electricity output of our generation facilities is provided to our Elk Hills production facilities to reduce field operating costs and increase operational reliability, we sell a significant portion into the California market. We offer excess electricity daily into the California electricity market that is sold based on market pricing and other requirements.



59



Our Principal Customers
We sell our crude oil, natural gas and NGLs production to marketers, California refineries 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, 2014, 2013 and 2012, ConocoPhillips/Phillips 66 Company and Tesoro Refining & Marketing Company LLC each accounted for more than 10% of our revenue. Collectively, they accounted for 45%, 42% and 46% in each of those years, respectively.
Our Reserves and Production Information
Reserve Data
The information with respect to our estimated reserves presented below has been prepared in accordance with the rules and regulations of the SEC.
Reserves Presentation
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 2014 disclosures, the calculated average Brent oil price was $101.30 per Bbl. The calculated average NYMEX gas price for 2014 disclosures was $4.42 per Mcf. The realized prices used for the 2014 disclosures were $95.20 per Bbl for oil $49.94 per Bbl for NGLs and $4.73 per Mcf for natural gas.
During the second half of 2014 oil prices experienced a steep decline, which has continued into 2015. If prices remain at or near current levels for the rest of 2015, or if they decline further, the prices used to determine our year-end 2015 reserves will be significantly lower than those used for year-end 2014, as mandated by SEC regulations. Under such circumstances, we may experience significant negative price-related revisions to our proved reserves at year-end 2015. For example, under a much lower price scenario used for reserves reporting purposes, a significant portion of our proved undeveloped reserves may no longer meet the economic producibility criteria under the rules. Similarly, while we have significant control over variable costs, certain costs in our long-lived fields, such as Elk Hills, are fixed, having the effect of increasing costs on a per barrel basis in later years as production declines, rendering them uneconomic in a lower price environment. We would expect that our production-sharing type contracts would partially offset these negative revisions. Further, we believe that a prolonged period of low oil prices would result in lower operating costs, which would tend to mitigate price related negative revisions to some extent by improving the economics of proved undeveloped reserves as well as extending the economic lives of long-lived fields.

60



The following tables summarize our estimated proved reserves and related PV-10 and Standardized Measure at December 31, 2014. 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.
 
 
As of December 31, 2014
 
 
San Joaquin
Basin
 
Los Angeles
Basin
 
Ventura
Basin
 
Sacramento
Basin
 
Total
Proved developed reserves:
 
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
 
229

 
124

 
34

 

 
387

NGLs (MMBbl)
 
62

 

 
2

 

 
64

Natural Gas (Bcf)
 
458

 
11

 
28

 
110

 
607

Total (MMBoe)(1)(2)
 
367

 
126

 
41

 
18

 
552

 
 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves:
 
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
 
111

 
39

 
14

 

 
164

NGLs (MMBbl)
 
20

 

 
1

 

 
21

Natural Gas (Bcf)
 
163

 
5

 
9

 
6

 
183

Total (MMBoe)(2)
 
158

 
40

 
17

 
1

 
216

 
 
 
 
 
 
 
 
 
 
 
Total proved reserves:
 
 

 
 

 
 

 
 

 
 

Oil (MMBbl)
 
340

 
163

 
48

 

 
551

NGLs (MMBbl)
 
82

 

 
3

 

 
85

Natural Gas (Bcf)
 
621