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As filed with the Securities and Exchange Commission on August 20, 2014

Registration No. 001-36478

 

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

Amendment No. 2
to

Form 10

GENERAL FORM FOR REGISTRATION OF SECURITIES
PURSUANT TO SECTION 12(b) OR 12(g) OF
THE SECURITIES EXCHANGE ACT OF 1934

California Resources Corporation
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
  46-5670947
(I.R.S. Employer
Identification No.)

10889 Wilshire Blvd.    
Los Angeles, California   90024
(Address of Principal Executive Offices)   (Zip Code)

Registrant's telephone number, including area code:
310-208-8800

        Securities to be registered pursuant to Section 12(b) of the Act:

Title of Each Class to be so Registered   Name of Each Exchange on Which
Each Class is to be Registered
Common stock, par value $0.01 per share   The New York Stock Exchange

        Securities to be registered pursuant to Section 12(g) of the Act: None

        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 Securities Exchange Act of 1934, as amended. (Check one):

Large accelerated filer  o   Accelerated filer  o   Non-accelerated filer  ý
(Do not check if a
smaller reporting company)
  Smaller reporting company  o

   



INFORMATION REQUIRED IN REGISTRATION STATEMENT

CROSS-REFERENCE SHEET BETWEEN INFORMATION STATEMENT AND ITEMS OF FORM 10

        The information required by the following Form 10 Registration Statement items is contained in the sections identified below of the information statement attached hereto as Exhibit 99.1, each of which are incorporated in this Form 10 Registration Statement by reference:

Item 1.     Business

        The information required by this item is contained under the sections "Summary," "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business," "Arrangements Between Occidental and Our Company" and "Other Related Party Transactions" of the Information Statement. Those sections are incorporated herein by reference.

Item 1A.     Risk Factors

        The information required by this item is contained under the section "Risk Factors" of the Information Statement. That section is incorporated herein by reference.

Item 2.     Financial Information

        The information required by this item is contained under the sections "Summary," "Selected Historical Combined Financial Data," "Unaudited Pro Forma Combined Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Description of Capital Stock" and "Index to Financial Statements and Supplementary Information" of the Information Statement. Those sections are incorporated herein by reference.

Item 3.     Properties

        The information required by this item is contained under the section "Business" of the Information Statement. That section is incorporated herein by reference.

Item 4.     Security Ownership of Certain Beneficial Owners and Management

        The information required by this item is contained under the section "Security Ownership of Certain Beneficial Owners and Management" of the Information Statement. That section is incorporated herein by reference.

Item 5.     Directors and Executive Officers

        The information required by this item is contained under the section "Management" of the Information Statement. That section is incorporated herein by reference.

Item 6.     Executive Compensation

        The information required by this item is contained under the section "Executive Compensation" of the Information Statement. That section is incorporated herein by reference.

Item 7.     Certain Relationships and Related Transactions, and Director Independence

        The information required by this item is contained under the sections "Management," "Executive Compensation," "Arrangements Between Occidental and Our Company" and "Other Related Party Transactions" of the Information Statement. Those sections are incorporated herein by reference.

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Item 8.     Legal Proceedings

        The information required by this item is contained under the sections "Business—Legal Proceedings" and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Lawsuits, Claims and Contingencies" of the Information Statement. Those sections are incorporated herein by reference.

Item 9.     Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters

        The information required by this item is contained under the sections "Risk Factors," "The Spin-Off," "Dividend Policy," "Executive Compensation" and "Description of Capital Stock" of the Information Statement. Those sections are incorporated herein by reference.

Item 10.     Recent Sales of Unregistered Securities

        The information required by this item is contained under the section "Description of Capital Stock." That section is incorporated herein by reference.

Item 11.     Description of Registrant's Securities to be Registered

        The information required by this item is contained under the section "Description of Capital Stock" of the Information Statement. That section is incorporated herein by reference.

Item 12.     Indemnification of Directors and Officers

        The information required by this item is contained under the section "Description of Capital Stock—Limitation of Liability and Indemnification Matters" of the Information Statement. That section is incorporated herein by reference.

Item 13.     Financial Statements and Supplementary Data

        The information required by this item is contained under the sections "Selected Historical Combined Financial Data," "Unaudited Pro Forma Combined Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Description of Capital Stock" and "Index to Financial Statements and Supplementary Information" of the Information Statement. Those sections are incorporated herein by reference.

Item 14.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None.

Item 15.     Financial Statements and Exhibits

(a)
Financial Statements

        The information required by this item is contained under the section "Index to Financial Statements and Supplementary Information" beginning on page F-1 of the Information Statement. That section is incorporated herein by reference.

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(b)
Exhibits

        The following documents are filed as exhibits hereto:

Exhibit No.   Description
  2.1   Form of Separation and Distribution Agreement between Occidental Petroleum Corporation and California Resources Corporation
  3.1 * Form of Amended and Restated Certificate of Incorporation of California Resources Corporation
  3.2 * Form of Amended and Restated Bylaws of California Resources Corporation
  4.1 * Form of Stockholder's and Registration Rights Agreement
  10.1 * Form of Transition Services Agreement between Occidental Petroleum Corporation and California Resources Corporation
  10.2 * Form of Tax Sharing Agreement between Occidental Petroleum Corporation and California Resources Corporation
  10.3   Form of Employee Matters Agreement between Occidental Petroleum Corporation and California Resources Corporation
  10.4 * Form of Intellectual Property License Agreement between Occidental Petroleum Corporation and California Resources Corporation
  10.5   Form of California Resources Corporation Long-Term Incentive Plan
  10.6 * Form of Grant Agreements
  10.7 * Form of Indemnification Agreements
  10.8 * Form of Area of Mutual Interest Agreement between Occidental Petroleum Corporation and California Resources Corporation
  10.9 * Form of Confidentiality and Trade Secret Protection Agreement between Occidental Petroleum Corporation and California Resources Corporation
  10.10   Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated November 5, 1991, by and among the State of California, by and through the State Lands Commission, the City of Long Beach, Atlantic Richfield Company and ARCO Long Beach, Inc.
  10.11   Amendment to the Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated January 16, 2009, by and among the State of California, by and through the State Lands Commission, the City of Long Beach, and Oxy Long Beach, Inc.
  10.12   Contractors' Agreement, by and between the City of Long Beach, Humble Oil & Refining Company, Shell Oil Company, Socony Mobil Oil Company, Inc., Texaco, Inc., Union Oil Company of California, Pauley Petroleum, Inc., Allied Chemical Corporation, Richfield Oil Corporation and Standard Oil Company of California
  10.13 * Retention Payment and Separation Benefits Attachments
  21.1 * List of Subsidiaries of California Resources Corporation
  99.1   Information Statement, preliminary and subject to completion, dated August 20, 2014
  99.2 ** Report of Independent Petroleum Engineers, Ryder Scott Company, L.P.
  99.3   Information extracted from Occidental's Annual Report on Form 10-K for the year ended December 31, 2013.

*
To be filed by amendment.

**
Previously filed.

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SIGNATURES

        Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized.

    California Resources Corporation

 

 

By:

 

/s/ TODD A. STEVENS

Todd A. Stevens
President and Chief Executive Officer
Date: August 20, 2014

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INFORMATION REQUIRED IN REGISTRATION STATEMENT CROSS-REFERENCE SHEET BETWEEN INFORMATION STATEMENT AND ITEMS OF FORM 10
SIGNATURES

Exhibit 2.1

 

[FORM OF]

 

SEPARATION AND DISTRIBUTION AGREEMENT

 

BY AND BETWEEN

 

OCCIDENTAL PETROLEUM CORPORATION

 

AND

 

CALIFORNIA RESOURCES CORPORATION

 

DATED AS OF [ · ], 2014

 



 

TABLE OF CONTENTS

 

Article I

Definitions

1

 

 

 

Article II

The Separation

12

 

 

 

2.1

Transfer of Assets and Assumption of Liabilities

12

2.2

CRC Assets

14

2.3

CRC Liabilities

15

2.4

Approvals and Notifications

16

2.5

Novation of CRC Liabilities

18

2.6

Novation of OPC Liabilities

18

2.7

Termination of Agreements

19

2.8

Treatment of Shared Contracts

19

2.9

Bank Accounts; Cash Balances

20

2.10

Other Ancillary Agreements

21

2.11

Disclaimer of Representations and Warranties

21

2.12

CRC Financing Arrangements

21

2.13

Financial Information Certifications

22

 

 

 

Article III

The Distribution

22

 

 

 

3.1

The Initial Distribution and the Distribution

22

3.2

Actions Prior to the Initial Distribution

22

3.3

Conditions to Initial Distribution

23

3.4

Certain Stockholder Matters

24

 

 

 

Article IV

Dispute Resolution

25

 

 

 

4.1

General Provisions

25

4.2

Consideration by Senior Executives

25

4.3

Mediation

25

4.4

Arbitration

26

4.5

Confidentiality

26

 

 

 

Article V

MUTUAL RELEASES; INDEMNIFICATION

26

 

 

 

5.1

Release of Pre-Initial Distribution Claims

26

5.2

Indemnification by CRC

28

5.3

Indemnification by OPC

29

5.4

Indemnification Obligations Net of Insurance Proceeds and Other Amounts

30

5.5

Procedures for Indemnification of Third-Party Claims

31

5.6

Additional Matters

32

5.7

Remedies Cumulative

33

5.8

Survival of Indemnities

33

5.9

Guarantees, Letters of Credit and other Obligations

33

5.10

No Impact on Third Parties

34

5.11

No Cross-Claims or Third-Party Claims

34

5.12

Severability

34

5.13

Change of Control

34

 

 

 

Article VI

INSURANCE MATTERS

34

 

 

 

6.1

Insurance Matters

34

 

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Article VII

EXCHANGE OF INFORMATION; CONFIDENTIALITY

36

 

 

 

7.1

Agreement for Exchange of Information

36

7.2

Ownership of Information

36

7.3

Compensation for Providing Information

36

7.4

Record Retention

36

7.5

Other Agreements Providing for Exchange of Information

37

7.6

Production of Witnesses; Records; Cooperation

37

7.7

Confidentiality

37

7.8

Protective Arrangements

38

 

 

 

Article VIII

Further Assurances and Additional Covenants

38

 

 

 

8.1

Further Assurances

38

8.2

Performance

39

8.3

OPC Guarantees

39

8.4

Third-Party Agreements

39

8.5

OPC Names and Marks

39

8.6

Conflicts with and between Ancillary Agreements

40

8.7

Attorney Client Privilege

40

8.8

No Attorney Testimony

41

 

 

 

Article IX

Termination

41

 

 

 

9.1

Termination

41

 

 

 

Article X

Miscellaneous

41

 

 

 

10.1

Counterparts; Entire Agreement; Corporate Power

41

10.2

Governing Law; Waiver of Trial by Jury

42

10.3

Assignability

42

10.4

Third-Party Beneficiaries

42

10.5

Notices

42

10.6

Severability

42

10.7

Force Majeure

43

10.8

Publicity

43

10.9

Expenses

43

10.10

Late Payments

43

10.11

Headings

43

10.12

Survival of Covenants

43

10.13

Waivers of Default

43

10.14

Specific Performance

43

10.15

Amendments

44

10.16

Interpretation

44

10.17

Relationship of the Parties

44

10.18

Limitations of Liability

44

 

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SCHEDULES

 

1.1

Assumed Actions

1.2

OPC Contracts

1.2(a)

Contracts, Agreements and Instruments Evidencing or Creating Oil and Gas Interests

1.2(b)

Other Agreements Relating to Hydrocarbons or Revenues

1.2(c)

Leases, Subleases, or Similar Agreements Granting Surface Use or Occupancy Rights

1.2(d)

Contracts Intending to Reduce or Eliminate Fluctuations in Prices of Commodities

1.2(e)

Customer, Distribution, Supply or Vendor Contracts

1.2(g)

Other Contracts Relating Exclusively to the CRC Business

1.3

CRC Intellectual Property

2.2(a)(i)

Assets Constituting CRC Assets

2.2(a)(ii)(B)

Equity Interests in OPC Affiliates and Subsidiaries Constituting CRC Assets

2.2(a)(ii)(C)

Equity Interests in Other Entities Constituting CRC Assets

2.2(a)(v)

Permits, Waivers, Authorizations and Similar Approvals Constituting CRC Assets

2.2(b)(i)

Assets Constituting OPC Assets

2.3(a)(ii)

Liabilities Constituting CRC Liabilities

2.3(b)(i)

Liabilities Not Constituting CRC Liabilities

2.7(b)(ii)

Contracts Not Terminated by Section 2.7(a)

2.8(a)

Treatment of Shared Contracts

5.1(c)(i)

Pre-Initial Distribution Claims Not Released by Section 5.1

5.3(a)(iv)

OPC Indemnified Actions

5.5(l)

CRC Assumed Third Party Claims

5.9(a)

CRC Contracts with OPC Group Guarantor or Obligor

6.1(c)

Insurance Matters

 

iii



 

SEPARATION AND DISTRIBUTION AGREEMENT

 

This SEPARATION AND DISTRIBUTION AGREEMENT, made and entered into effective as of [ · ], 2014 (this “ Agreement ”), is by and between Occidental Petroleum Corporation, a Delaware corporation (“ OPC ”), and California Resources Corporation, a Delaware corporation and wholly owned subsidiary of OPC (“ CRC ”).  Capitalized terms used herein and not otherwise defined shall have the respective meanings assigned to them in Article I.

 

R E C I T A L S

 

The board of directors of OPC (the “ OPC Board ”) has determined that it is in the best interests of OPC and its stockholders to create a new publicly traded company that shall operate the CRC Business.

 

CRC has been incorporated for this purpose and has not engaged in activities except in preparation for its corporate reorganization (including activities with respect to the CRC Financing Arrangements) and the distribution of its stock.

 

In furtherance of the foregoing, the OPC Board has determined that it is appropriate and desirable for OPC and its applicable Subsidiaries to transfer the CRC Assets to CRC and certain entities designated by CRC that will be Subsidiaries of CRC as of the Distribution Date (any such entities, the “ CRC Designees ”), and for CRC and the CRC Designees to assume or retain, as applicable, the CRC Liabilities, in each case as more fully described in this Agreement and the Ancillary Agreements (the “ Separation ”).

 

OPC currently intends that, on the Distribution Date, OPC shall distribute to holders of shares of OPC Common Stock, through a spin-off, 80.1% of the outstanding shares of CRC Common Stock, as more fully described in this Agreement and the Ancillary Agreements (the “ Initial Distribution ”), and OPC intends to distribute the remaining outstanding shares of CRC Common Stock to its shareholders in one or more subsequent distributions within 18 months following the date of the Initial Distribution, as more fully described in this Agreement and the Ancillary Agreements (together with the Initial Distribution, the “ Distribution ”).

 

In connection with the Separation, OPC intends to cause CRC to declare and distribute the Cash Dividends at such times and in the manner set forth in the Restructuring Steps Memorandum and to use such cash in the manner set forth in the Restructuring Steps Memorandum.

 

For U.S. federal income tax purposes, the Contribution and the Distribution, if effected, taken together, are intended to qualify generally as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code.

 

This Agreement is intended to be, and is hereby adopted as, a “plan of reorganization” within the meaning of Treas. Reg. 1.368-2(g).

 

It is appropriate and desirable to set forth the principal corporate transactions required to effect the Separation and the Distribution and certain other agreements that will govern certain matters relating to the Separation and the Distribution and the relationship of OPC, CRC and their respective Subsidiaries, following the Distribution.

 

NOW, THEREFORE, in consideration of the mutual agreements, provisions and covenants contained in this Agreement, the parties, intending to be legally bound, agree as follows:

 

ARTICLE I
DEFINITIONS

 

For the purpose of this Agreement, the following terms shall have the following meanings:

 

AAA ” shall have the meaning set forth in Section 4.3.

 

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AAA Commercial Arbitration Rules ” shall have the meaning set forth in Section 4.4(a).

 

Action ” means any demand, action, claim, dispute, suit, countersuit, arbitration, inquiry, subpoena, proceeding or investigation of any nature (whether criminal, civil, legislative, administrative, regulatory, prosecutorial or otherwise) by or before any federal, state, local, foreign or international Governmental Authority or any arbitration or mediation tribunal.

 

Affiliate ” means, when used with respect to a specified Person, a Person that, directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with such specified Person.  For the purpose of this definition, “ control ” (including with correlative meanings, “ controlled by ” and “ under common control with ”), when used with respect to any specified Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities or other interests, by contract, agreement, obligation, indenture, instrument, lease, promise, arrangement, release, warranty, commitment, undertaking or otherwise.  For the avoidance of doubt, after the Distribution Date, the members of the OPC Group and the members of the CRC Group shall not be deemed to be under common control for purposes hereof due solely to the fact that OPC and CRC have common shareholders.

 

Agent ” means the distribution agent to be appointed by OPC to distribute to the stockholders of OPC at least 80.1% of the outstanding shares of CRC Common Stock pursuant to the Initial Distribution.

 

Agreement ” shall have the meaning set forth in the Preamble.

 

Ancillary Agreements ” means the Area of Mutual Interest Agreement, the Confidentiality and Trade Secret Protection Agreement, the Employee Matters Agreement, the Intellectual Property License Agreement, the Stockholder’s Agreement, the Transition Services Agreement, the Tax Sharing Agreement and the Transfer Documents.

 

Approvals or Notifications ” means any consents, waivers, approvals, permits or authorizations to be obtained from, notices, registrations or reports to be submitted to, or other filings to be made with, any third Person, including any Governmental Authority.

 

Area of Mutual Interest Agreement ” means the Area of Mutual Interest Agreement, dated as of the date hereof, between OPC and CRC.

 

Assets ” means, with respect to any Person, the assets, properties, claims and rights (including goodwill) of such Person, wherever located (including in the possession of vendors or other third Persons or elsewhere), of every kind, character and description, whether real, personal or mixed, tangible, intangible or contingent, in each case, whether or not recorded or reflected or required to be recorded or reflected on the books and records or financial statements of such Person, including the following:

 

(a)                                  All Hydrocarbons (whether in place, in storage, in pipelines or elsewhere) and all interests in and rights with respect to Hydrocarbons and Hydrocarbon leases, subleases, fee interests, fee mineral interests, wells, mineral servitudes, royalties, overriding royalties, production payments, net profits interests, carried interests, reversionary interests and all other interests of any kind or character in Hydrocarbons in place or produced (collectively, “ oil and gas interests ”), together with any and all other rights, titles and interests in and to any pooled acreage, communitized acreage or units arising on account of oil and gas interests having been pooled, communitized or unitized into such units;

 

(b)                                  all Records;

 

(c)                                   all apparatus, IT Equipment, fixtures, machinery, equipment, furniture, office equipment, automobiles, trucks, vessels, motor vehicles and other transportation equipment, well equipment, casing, tubing, pumps, motors, machinery, platforms, rods, tanks, boilers, fixtures, compression equipment,

 

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flowlines, pipelines, gathering systems associated with wells, manifolds, processing and separation facilities, pads, structures, materials and other tangible personal property;

 

(d)                                  all inventories of materials, parts, raw materials, components, supplies, works-in-process and finished goods and products;

 

(e)                                   all interests in real property of whatever nature, including buildings, fixtures and easements, whether as owner, mortgagee or holder of a Security Interest in real property, lessor, sublessor, lessee, sublessee or otherwise, including interests in and rights with respect to all leases, subleases, licenses, easements, rights-of-way or other similar surface interests, or other occupancy or similar agreements granting surface use or surface occupancy rights and all pipelines, gathering systems, salt water disposal wells and evaporation pits;

 

(f)                                    (i) all interests in any capital stock or other equity interests of any Subsidiary, Affiliate or any other Person, (ii) all bonds, notes, debentures or other securities issued by any Subsidiary, Affiliate or any other Person, (iii) all loans, advances or other extensions of credit or capital contributions to any Subsidiary, Affiliate or any other Person, and (iv) all other investments in securities of any Person;

 

(g)                                   all license agreements, leases of personal property, open purchase orders for raw materials, supplies, parts or services and other contracts, agreements or commitments;

 

(h)                                  all letters of credit;

 

(i)                                      all written (including in electronic form) or oral technical information, data, specifications, research and development information, engineering drawings and specifications, operating and maintenance manuals, and materials and analyses prepared by consultants and other third Persons;

 

(j)                                     all Intellectual Property;

 

(k)                                  all Software;

 

(l)                                      all cost information, sales and pricing data, customer prospect lists, supplier records, customer and supplier lists, customer and vendor data, correspondence and lists, product data and literature, artwork, design, formulations and specifications, quality records and reports and other books, records, studies, surveys, reports, plans and documents;

 

(m)                              all prepaid expenses, trade accounts and other accounts and notes receivable;

 

(n)                                  all rights under contracts or agreements, all claims or rights against any Person arising from the ownership of any Asset described in (a) through (m) and (o) through (q) hereof, including, to the extent transferrable, all rights against third parties with respect to indemnification, and all rights in connection with any bids or offers and all claims, choses in action or similar rights, whether accrued or contingent;

 

(o)                                  all licenses, permits, approvals and authorizations which have been issued by any Governmental Authority;

 

(p)                                  all cash or cash equivalents, bank accounts, lock boxes and other deposit arrangements; and

 

(q)                                  all interest rate, currency, commodity or other swap, collar, cap or other hedging or similar agreements or arrangements.

 

Assumed Actions ” means (a) those Actions which are listed in Schedule 1.1 ; and (b) those Actions that are exclusively related to the CRC Business.

 

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Cash Dividends ” means [ · ].

 

Code ” means the Internal Revenue Code of 1986, as amended.

 

Confidentiality and Trade Secret Protection Agreement ” means the Confidentiality and Trade Secret Protection Agreement, dated as of the date hereof, between OPC and CRC.

 

Contribution ” means [ · ].

 

Corporate Action ” means any Action, whether filed before, on or after the Distribution Date, to the extent it asserts violations of any federal, state, local, foreign or international securities Law, securities class action or shareholder derivative claim.

 

CRC ” shall have the meaning set forth in the Preamble.

 

CRC Accounts ” shall have the meaning set forth in Section 2.9(a).

 

CRC Assets ” shall have the meaning set forth in Section 2.2(a).

 

CRC Balance Sheet ” means the unaudited combined balance sheet of the CRC Group, including the notes thereto, as of June 30, 2014.

 

CRC Business ” means (a) the exploration for and development and production of crude oil and condensate, NGL and natural gas in the State of California and in state waters offshore California, including all California operations of OPC’s Oil and Gas Segment, operated mainly through OXY Long Beach and Occidental of Elk Hills, Vintage Production, and the California operations of OXY USA, and the gathering and processing of such crude oil, condensate, NGL and natural gas, (b) the ownership interest in and operation of three gas-fired combined cycle power plants at Elk Hills Field in California and THUMS in California, (c) the marketing and trading of crude oil and condensate, NGL, natural gas, water, steam and electricity produced in the operations set forth in clause (a) and (b) of this definition, and (d) the abandonment, monitoring and remediation of oil and gas properties and operations utilized therein. For the avoidance of doubt, the “ CRC Business ” shall not include the existing third-party crude oil and gas marketing business of OPC and its subsidiaries’ non-California midstream and marketing segment, which participates in various U.S. markets, including California.

 

CRC Certificate of Incorporation ” shall have the meaning set forth in Section 3.2(d).

 

CRC Common Stock ” means the common stock, par value $0.01 per share, of CRC.

 

CRC Contracts ” means the following contracts, agreements and instruments to which OPC or any of its Affiliates is a party or by which it or any of its Affiliates or any of their respective Assets is bound, whether or not in writing, in each case immediately prior to the Distribution Date, except for any such contract or agreement that is contemplated to be retained by OPC or any member of the OPC Group pursuant to any provision of this Agreement or any Ancillary Agreement, including those listed on Schedule 1.2 (each, an “ OPC Contract ”):

 

(a)                                  The contracts, agreements and instruments evidencing or creating the oil and gas interests comprising a part of the CRC Business including those listed on Schedule 1.2(a) ;

 

(b)                                  Without duplication of the preceding clause (a), any farm-in or farm-out agreement, confidentiality agreement, area of mutual interest agreement, joint venture agreement, development agreement, production sharing agreement, operating agreement, unitization, pooling or communitization agreement, declaration and order, division order, transfer order, oil and gas sales agreement, exchange agreement, gathering and processing contract or agreement, drilling, service or supply contract, geophysical or geological contract, land broker, title attorney or abstractor contract or any other contract relating to Hydrocarbons or revenues therefrom and claims and rights thereto, in each case that relates exclusively to the CRC Business, including those contracts listed on Schedule 1.2(b) ;

 

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(c)                                   Any lease, sublease, license, easement or other occupancy or similar agreement granting surface use or surface occupancy rights, in each case that relates exclusively to the CRC Business, including those contracts listed on Schedule 1.2(c) ;

 

(d)                                  Any contract that relates to futures, swaps, collars, puts, calls, floors, caps, options or otherwise is intended to reduce or eliminate the fluctuations in the prices of commodities, including natural gas, natural gas liquids, crude oil and condensate, in each case that relates exclusively to the CRC Business, including those contracts listed on Schedule 1.2(d) ;

 

(e)                                   Any customer, distribution, supply or vendor contract, or any joint venture or license agreement, in each case, that relates exclusively to the CRC Business, including those contracts listed on Schedule 1.2(e) ;

 

(f)                                    Any employment, change of control, retention, consulting, indemnification, termination, severance or other similar agreement with any CRC Group Employees;

 

(g)                                   Any other contract that relates exclusively to the CRC Business, including those contracts listed on Schedule 1.2(g) .

 

CRC Designees ” shall have the meaning set forth in the Recitals.

 

CRC Financing Arrangements ” means the Rule 144A / Capital Markets Securities, the Term Loan Facility, and the Revolving Credit Facility.

 

CRC Group ” means CRC, (i) each Subsidiary of CRC immediately after the Distribution Date, (ii) each Affiliate of CRC controlled by CRC immediately after the Distribution Date and (iii) each other entity that becomes a Subsidiary of CRC at any time following the Distribution Date for so long as such entity is a Subsidiary of CRC.

 

CRC Group Employee ” shall have the meaning set forth in the Employee Matters Agreement.

 

CRC Indemnitees ” shall have the meaning set forth in Section 5.3.

 

CRC Intellectual Property ” means (a) the patents, registered trademarks, registered service marks, registered Internet domain names, copyright registrations, and applications for the foregoing (collectively, “ Registered IP ”) set forth on Schedule 1.3(a) , (b) all Registered IP that is owned exclusively by or licensed exclusively to any member of the CRC Group at or prior to the Distribution Date, excluding any such Registered IP that has been assigned by any member of the CRC Group to any member of the OPC Group prior to the Distribution Date, (c) all Intellectual Property set forth on Schedule 1.3(c)  and (d) all Intellectual Property, other than Registered IP, that is wholly-owned by the OPC Group or CRC Group and that is used or held for use exclusively in the CRC Business as of the Distribution Date.

 

CRC Liabilities ” shall have the meaning set forth in Section 2.3(a).

 

“CRC Third Party Claim” shall mean any claim or commencement of any Action by any Person (including any Governmental Authority) other than (i) CRC, (ii) each Subsidiary of CRC immediately after the Distribution Date, and (iii) each Affiliate of CRC controlled by CRC immediately after the Distribution Date.

 

CRC Transfer Documents ” shall have the meaning set forth in Section 2.1(c).

 

Credit Rating ” means on any date, the rating that has been most recently announced by any Rating Agency for any class of senior, unsecured, non-convertible long-term debt of a Person.

 

Dispute ” shall have the meaning set forth in Section 4.1(a).

 

Distribution ” shall have the meaning set forth in the Recitals.

 

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Distribution Date ” means the date and time determined in accordance with Section 3.1(a) at which the Initial Distribution occurs.

 

Distribution Ratio ” means [ · ] share of CRC Common Stock distributed in the Initial Distribution in respect of one share of OPC Common Stock.

 

Employee Matters Agreement ” means the Employee Matters Agreement, dated as of the date hereof, between OPC and CRC.

 

Environmental Law ” means any Law pertaining to (a) the protection of, or prevention of harm to, the environment or natural resources, (b) the generation, use, handling, transportation, treatment, storage, management, presence, disposal of and arrangement for disposal of, Release, threatened Release of, or exposure to Hazardous Materials, (c) the prevention of pollution, remediation of contamination, or restoration of environmental quality, or (d) employee health or workplace safety.

 

Environmental Liabilities ” means all Liabilities, environmental response costs (including all removal, remediation or cleanup costs, investigatory costs, monitoring costs, and response costs with respect to Hazardous Materials), damages (including natural resources damages, property damages, personal injury damages), costs of compliance (including with any product take back requirements, or with any settlement, judgment or other determination of Liability and indemnity, contribution or similar obligations), court costs, attorneys’ fees, and all other Liabilities, costs, expenses, interest, fines, penalties or monetary sanctions relating to, arising out of or resulting from any order, notice of responsibility, directive, injunction, judgment or similar act (including settlements) by any Governmental Authority to the extent arising out of non-compliance with or any violation of, or obligation under, any Environmental Laws, or pursuant to any demand, action, claim, dispute, suit, countersuit, settlement, arbitration, formal inquiry, subpoena, investigation, proceeding or other legal determination of liability by a Governmental Authority or any other Person with respect to Hazardous Materials (including any exposure to Hazardous Materials), Environmental Law or contract or agreement relating to environmental, health or safety matters.

 

Exchange Act ” means the U.S. Securities Exchange Act of 1934, as amended, together with the rules and regulations promulgated thereunder.

 

Form 10 ” shall have the meaning set forth in Section 3.3(a)(vii).

 

Governmental Approvals ” means any notices, reports or other filings to be made, or any consents, registrations, approvals, permits or authorizations to be obtained from, any Governmental Authority.

 

Governmental Authority ” means any nation or government, any state, municipality or other political subdivision thereof, and any entity, body, agency, commission, department, board, bureau, court, tribunal or other instrumentality, whether federal, state, local, domestic, foreign or multinational, exercising executive, legislative, judicial, regulatory, administrative or other similar functions of, or pertaining to, government and any executive official thereof.

 

Group ” means either the CRC Group or the OPC Group, as the context requires.

 

Hazardous Materials ” means any chemical, material, substance, waste, pollutant, emission, discharge, release, contaminant or words of similar meaning or import that could result in liability under, or that is prohibited, limited or regulated by or pursuant to, any Environmental Law, and any natural or artificial substance (whether solid, liquid or gas, noise, ion, vapor or electromagnetic) that could cause harm to human health or the environment, including petroleum, petroleum products and byproducts, oil and gas exploration and production wastes, natural gas, condensate or any components, fractions or derivatives thereof, asbestos and asbestos-containing materials, urea formaldehyde foam insulation, electronic, medical or infectious wastes, polychlorinated biphenyls, naturally occurring radioactive materials, radon gas, radioactive substances, chlorofluorocarbons and all other ozone-depleting substances.

 

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Hydrocarbons ” means oil and gas and other hydrocarbons produced or processed in association therewith (whether in liquid or gaseous form), or any combination thereof, and any minerals produced in association therewith.

 

Income Taxes ” shall have the meaning set forth in the Tax Sharing Agreement.

 

Indemnifying Party ” shall have the meaning set forth in Section 5.4(a).

 

Indemnitee ” shall have the meaning set forth in Section 5.4(a).

 

Indemnity Payment ” shall have the meaning set forth in Section 5.4(a).

 

Information ” means information, whether or not patentable or copyrightable, in written, oral, electronic or other tangible or intangible forms, stored in any medium, including studies, reports, records, books, contracts, instruments, surveys, discoveries, ideas, concepts, know-how, techniques, designs, specifications, drawings, blueprints, diagrams, models, prototypes, samples, flow charts, data, computer data, disks, diskettes, tapes, computer programs or other software, marketing plans, customer names, memos, and other technical, financial, employee or business information or data.

 

Information Statement ” shall have the meaning set forth in Section 3.3(a)(vii).

 

Initial Distribution ” shall have the meaning set forth in the Recitals.

 

Initial Notice ” shall have the meaning set forth in Section 4.2.

 

Insurance Proceeds ” means those monies:

 

(a)                                  received by an insured from an insurance carrier; or

 

(b)                                  paid by an insurance carrier on behalf of the insured;

 

in any such case net of any applicable premium adjustments (including reserves and retrospectively rated premium adjustments) and net of any costs or expenses incurred in the collection thereof; provided, however , with respect to a captive insurance arrangement, Insurance Proceeds shall only include net amounts received by the captive insurer in respect of any reinsurance arrangement with respect to the insurance issued by such captive insurer.

 

Intellectual Property ” means any and all proprietary and intellectual property rights whether arising under the Laws of the United States or of any other foreign or multinational jurisdiction or provided by international treaties or convention, including: (a) patents, patent applications and statutory invention registrations, including reissues, divisions, continuations, continuations in part, substitutions, renewals, extensions and reexaminations of any of the foregoing, (b) trademarks, service marks, trade names, service names, trade dress, logos, Internet domain names, uniform resource locaters, and other source or business identifiers, including all goodwill associated with any of the foregoing and any and all common law rights in and to any of the foregoing, registrations and applications for registration of any of the foregoing, and all reissues, extensions and renewals of any of the foregoing (collectively, “ Trademarks ”), (c) copyrights, moral rights, mask work rights, database rights, other rights in works of authorship, and all registrations and applications for registration of any of the foregoing, and (d) trade secrets, know how, and rights in confidential and proprietary information, including invention disclosures, formulations, concepts, compilations of information, methods, techniques, procedures, and processes, whether or not patentable.

 

Intellectual Property License Agreement ” means the Intellectual Property License Agreement, dated as of the date hereof, between OPC and CRC.

 

IT Equipment ” means all computers, servers, printers, computer hardware, wired or mobile telephones, on-site process control and automation systems, telecommunication assets, and other information technology-related equipment.

 

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Law ” means any national, supranational, federal, state, provincial, local or similar law (including common law), statute, code, order, ordinance, rule, regulation, treaty (including any income tax treaty), license, permit, authorization, approval, consent, decree, injunction, binding judicial or administrative interpretation or other requirement, in each case, enacted, promulgated, issued or entered by a Governmental Authority.

 

LHO ” shall have the meaning set forth in Section 5.5(i).

 

 “ Liabilities ” means any and all debts, guarantees, assurances, commitments, liabilities (including Environmental Liabilities), responsibilities, Losses, remediation, deficiencies, reimbursement obligations in respect of letters of credit, damages, fines, penalties, settlements, sanctions, costs, expenses, interest and obligations, whether accrued or fixed, absolute or contingent, matured or unmatured, accrued or not accrued, asserted or unasserted, liquidated or unliquidated, foreseen or unforeseen, known or unknown, reserved or unreserved, or determined or determinable, including those arising under any Law, claim (including any Third-Party Claim), demand, Action, or order, writ, judgment, injunction, decree, stipulation, determination or award entered by or with any Governmental Authority or arbitration tribunal, and those arising under any contract, agreement, obligation, indenture, instrument, lease, promise, arrangement, release, warranty, commitment or undertaking, or any fines, damages or equitable relief that is imposed, in each case, including all costs and expenses relating thereto.

 

Losses ” means actual losses (including any diminution in value), costs, damages, penalties and expenses (including legal and accounting fees and expenses and costs of investigation and litigation), whether or not involving a Third-Party Claim.

 

Mediation Procedures ” shall have the meaning set forth in Section 4.3.

 

 “ Minimum Credit Rating ” shall mean a rating of at least (a) BB- by Standard & Poor’s Financial Services LLC, (b) Ba3 by Moody’s Investors Service, Inc., or (c) BB- by Fitch, Inc.

 

NGL ” means natural gas liquids.

 

NYSE ” means the New York Stock Exchange.

 

 “ Occidental of Elk Hills ” means Occidental of Elk Hills, Inc., a Delaware corporation.

 

Oil and Gas Segment ” means the oil and gas segment of OPC described in OPC’s Annual Report on Form 10-K for the period ended December 31, 2013, which business explores for, develops and produces oil and condensate, NGL and natural gas.

 

OPC ” shall have the meaning set forth in the Preamble.

 

OPC Accounts ” shall have the meaning set forth in Section 2.9(a).

 

OPC Assets ” shall have the meaning set forth in Section 2.2(b).

 

OPC Board ” shall have the meaning set forth in the Recitals.

 

OPC Business ” means the business of the OPC and its Subsidiaries as conducted at any point in time prior to the Distribution Date, other than the CRC Business.

 

OPC Common Stock ” means the common stock, par value $0.20 per share, of OPC.

 

OPC Contracts ” shall have the meaning set forth in the definition of CRC Contracts.

 

OPC Group ” means OPC, (i) each Subsidiary of OPC immediately after the Distribution Date, (ii) each Affiliate of OPC controlled by OPC immediately after the Distribution Date and (iii) each other entity that becomes a Subsidiary of OPC at any time following the Distribution Date for so long as such entity is a Subsidiary of OPC;

 

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provided that, from and after the Distribution Date, each member of the CRC Group will be deemed not to be a member of the OPC Group.

 

OPC Guarantees ” shall have the meaning set forth in Section 8.3.

 

OPC Indemnitees ” shall have the meaning set forth in Section 5.2.

 

OPC Intellectual Property ” means (a) the OPC Names and Marks, and (b) all other Intellectual Property that, as of the Distribution Date, is owned or licensed by any member of either Group, other than the CRC Intellectual Property.

 

OPC Liabilities ” shall have the meaning set forth in Section 2.3(b).

 

OPC Names and Marks ” means (a) the Trademarks of OPC or any of its Affiliates using or containing “OPC,” “OXY”, Occidental Chemical Corporation, OxyChem,  or “Occidental Petroleum” (in block letters or otherwise), “OPC,” “OXY” or “Occidental Petroleum” either alone or in combination with other words or elements, together with all variations and acronyms thereof, and all trademarks, service marks, Internet domain names, trade names, trade dress, company names and other identifiers of source or goodwill containing or incorporated with any of the foregoing, including the oxy comet logo (b) the “OXY circle or comet logo” (shown immediately below)

 

 

(c) all Trademarks registered by a member of the OPC Group prior to the Distribution Date and not used or held for use exclusively in the CRC Business as of the Distribution Date, and (d) all Trademarks registered by a member of the CRC Group prior to the Distribution Date and not used or held for use exclusively in the CRC Business as of the Distribution Date, and (e) Trademarks confusingly similar to or embodying any of the foregoing either alone or in combination with other words or elements, together with the goodwill associated with any of the foregoing.

 

OPC Software ” means all Software that, as of the Distribution Date, is owned by any member of either Group.

 

OPC Third Party Claim ” shall mean any claim or commencement of any Action by any Person (including any Governmental Authority) other than (i) OPC, (ii) each Subsidiary of OPC immediately after the Distribution Date, and (iii) each Affiliate of OPC controlled by OPC immediately after the Distribution Date; provided, however, that for the avoidance of doubt, CRC and its Subsidiaries immediately after the Distribution Date shall not be considered an Affiliate or Subsidiary of OPC.

 

OPC Transfer Documents ” shall have the meaning set forth in Section 2.1(b).

 

OPIC ” means Occidental Petroleum Investment Co., a California corporation and a wholly owned subsidiary of OPC.

 

OXY Long Beach ” means OXY Long Beach, Inc., a Delaware corporation.

 

OXY USA ” means OXY USA Inc., a Delaware corporation.

 

Person ” means an individual, a general or limited partnership, a corporation, a trust, a joint venture, an unincorporated organization, a limited liability entity, any other entity and any Governmental Authority.

 

Prime Rate ” means the rate which JPMorgan Chase Bank (or any successor thereto or other major money center commercial bank agreed to by the parties hereto) announces from time to time as its prime lending rate, as in effect from time to time.

 

Privilege ” shall have the meaning set forth in Section 7.1.

 

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Rating Agency ” means Moody’s Investors Service, Inc., Standard & Poor’s, a division of The McGraw-Hill Companies, Inc., Fitch, Inc. or any nationally recognized statistical rating organizations registered with the Securities and Exchange Commission.

 

Record Date ” means the close of business on the date to be determined by the OPC Board as the record date for determining stockholders of OPC entitled to receive shares of CRC Common Stock in the Initial Distribution.

 

Records ” means all corporate, operational, accounting and other books and records, files, data, correspondence, studies, surveys, reports, Hydrocarbon sales contract files, gas processing files, geologic, geophysical and seismic data (including raw data and any interpretative data or information relating to such geologic, geophysical and seismic data) and other data (in each case whether in written or electronic format), including all title records, prospect information, title opinions,  title insurance reports, abstracts, property ownership reports, customer lists, supplier lists, sales materials, well logs, well tests, maps, engineering data and reports, health, environmental and safety information and records, third-party licenses, accounting and financial records, promotional materials, operational records, technical records, reserve estimates and economic estimates; production and processing records, division order, lease, land and right-of-way files, accounting files,  tax records (other than income tax), and contract files (including copies of all contracts, all files regarding the contracts and related files).

 

Registered IP ” shall have the meaning set forth in the definition of CRC Intellectual Property.

 

Release ” means any depositing, spilling, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, migrating, injecting, escaping, leaching, seeping, dumping, or disposing of Hazardous Materials into the environment (including ambient air, surface water, groundwater and surface or subsurface strata).

 

Representatives ” means, with respect to any Person, any of such Person’s directors, officers, employees, agents, managers, consultants, advisors, accountants, attorneys or other representatives.

 

Required Share Number ” means the number of shares of CRC Common Stock necessary to effect the Distribution less the number of shares of CRC Common Stock outstanding immediately prior to the Contribution.

 

Response ” shall have the meaning set forth in Section 4.2.

 

Restructuring Steps Memorandum ” means the memorandum attached as Annex A hereto setting forth the restructuring steps to be taken prior to the Distribution Date and the sequence thereof.

 

Revolving Credit Facility ” means a revolving credit facility pursuant to a revolving credit facility agreement entered into prior to the Initial Distribution by CRC, as borrower, the bank named therein as administrative agent, and the lending banks named therein, on such terms and conditions as agreed to by CRC and the other parties to the revolving credit facility agreement and approved by OPC.

 

Rule 144A / Capital Markets Securities ” means securities sold prior to the Initial Distribution by CRC, and approved by OPC, in reliance on Rule 144A promulgated under the Securities Act.

 

SEC ” means the U.S. Securities and Exchange Commission.

 

Securities Act ” means the U.S. Securities Act of 1933, as amended, together with the rules and regulations promulgated thereunder.

 

Security Interest ” means any mortgage, security interest, pledge, lien, charge, claim, option, right to acquire, voting or other restriction, right-of-way, covenant, condition, easement, encroachment, restriction on transfer, or other encumbrance of any nature whatsoever.

 

Separation ” shall have the meaning set forth in the Recitals.

 

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Shared Contract ” shall have the meaning set forth in Section 2.8(a).

 

Software ” means any and all (a) computer programs, including the tangible media on which it is recorded (in any form), and any and all software implementation of algorithms, models and methodologies, whether in source code, object code, human readable form or other form, together with all translations, adaptations, modifications, derivations, combinations or derivative works thereof, (b) databases and compilations, including any and all data and collections of data, whether machine readable or otherwise, (c) descriptions, flow charts and other work products used to design, plan, organize and develop any of the foregoing, screens, user interfaces, report formats, firmware, development tools, templates, menus, buttons and icons, and (d) documentation, including user manuals and other training documentation, relating to any of the foregoing.

 

Stockholder’s Agreement ” means the Stockholder’s and Registration Rights Agreement, dated as of the date hereof, between OPC, and CRC.

 

 “ Subsidiary ” or “ subsidiary ” means, with respect to any Person, any corporation, limited liability company, joint venture or partnership of which such Person (a) beneficially owns, either directly or indirectly, more than fifty percent (50%) of (i) the total combined voting power of all classes of voting securities of such Person, (ii) the total combined equity interests or (iii) the capital or profit interests, in the case of a partnership, or (b) otherwise has the power to vote, either directly or indirectly, sufficient securities to elect a majority of the board of directors or similar governing body.

 

Supplies ” shall have the meaning set forth in Section 8.5(a).

 

Tax Benefit ” shall have the meaning set forth in the Tax Sharing Agreement.

 

Tax Return ” shall have the meaning set forth in the Tax Sharing Agreement.

 

Tax Sharing Agreement ” means the Tax Sharing Agreement, dated as of the date hereof, between OPC, and CRC.

 

Taxes ” shall have the meaning set forth in the Tax Sharing Agreement.

 

Term Loan Facility ” means the term loan facility pursuant to the term loan agreement entered into prior to the Initial Distribution by CRC, as borrower, the bank named therein as administrative agent, and the lending banks named therein, on such terms and conditions as agreed to by CRC and the other parties to the term loan agreement and approved by OPC.

 

Third-Party ” shall mean any Person (including any Governmental Authority) other than (i) CRC, (ii) each Subsidiary of CRC immediately after the Distribution Date, and (iii) each Affiliate of CRC controlled by CRC immediately after the Distribution Date, (iv) OPC, (v) each Subsidiary of OPC immediately after the Distribution Date, and (vi) each Affiliate of OPC controlled by OPC immediately after the Distribution Date.

 

Third-Party Claim ” shall mean a CRC Third Party Claim or an OPC Third Party Claim.

 

Trademarks ” shall have the meaning set forth in the definition of Intellectual Property.

 

Transfer Documents ” shall have the meaning set forth in Section 2.1(c).

 

Transferred Entities ” shall have the meaning set forth in Section 2.2(a)(ii).

 

Transition Services Agreement ” means the Transition Services Agreement, dated as of the date hereof, between OPC and CRC.

 

Unreleased OPC Liability ” shall have the meaning set forth in Section 2.6(b).

 

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Unreleased CRC Liability ” shall have the meaning set forth in Section 2.5(b).

 

Vintage Production ” means Vintage Production California LLC, a Delaware limited liability company.

 

ARTICLE II
THE SEPARATION

 

2.1                                Transfer of Assets and Assumption of Liabilities .

 

(a)                                  Unless otherwise provided in this Agreement or in any Ancillary Agreement, on or prior to the Distribution Date in accordance with the Restructuring Steps Memorandum and to the extent not previously effected prior to the date hereof pursuant to the steps of the Restructuring Steps Memorandum:

 

(i)                                      OPC shall, and shall cause its applicable Subsidiaries to, assign, transfer and convey to CRC, or the applicable CRC Designees, and CRC or such CRC Designees shall accept from OPC and its applicable Subsidiaries, all of OPC’s and such Subsidiaries’ respective direct or indirect right, title and interest in and to all of the CRC Assets (it being understood that if any CRC Asset shall be held by a Transferred Entity or a wholly owned Subsidiary of a Transferred Entity, such CRC Asset will be indirectly owned by CRC as a result of the transfer of the equity interests in such Transferred Entity);

 

(ii)                                   CRC and the applicable CRC Designees shall accept and assume from OPC and the applicable OPC Subsidiaries and agree faithfully to perform, discharge and fulfill certain of the CRC Liabilities in accordance with their respective terms.  CRC and such CRC Designees shall be responsible for all CRC Liabilities, regardless of when or where such CRC Liabilities arose or arise, or whether the facts on which they are based occurred prior to or subsequent to the Distribution Date, regardless of where or against whom such CRC Liabilities are asserted or determined (including any CRC Liabilities arising out of claims made by the respective directors, officers, employees, agents, stockholders, managers, Subsidiaries or Affiliates of either Group against any member of either Group) or whether asserted or determined prior to the date hereof, and regardless of whether arising from or alleged to arise from negligence, recklessness, violation of Law, fraud, misrepresentation or any other cause by any member of either Group, or any of their respective directors, officers, employees, agents or managers;

 

(iii)                                OPC shall cause its applicable Subsidiaries to assign, transfer and convey to certain of its other Subsidiaries, which shall accept from such applicable OPC Subsidiaries, such applicable Subsidiaries’ respective right, title and interest in and to any OPC Assets specified by OPC to be so assigned, transferred and conveyed; and

 

(iv)                               OPC and certain of its Subsidiaries shall accept and assume from certain of its other Subsidiaries and agree faithfully to perform, discharge and fulfill certain OPC Liabilities of such other Subsidiaries, and OPC and its applicable Subsidiaries shall be responsible for all OPC Liabilities, regardless of when or where such OPC Liabilities arose or arise, or whether the facts on which they are based occurred prior to or subsequent to the Distribution Date, regardless of where or against whom such OPC Liabilities are asserted or determined (including any such OPC Liabilities arising out of claims made by the respective directors, officers, employees, agents, stockholders, managers, Subsidiaries or Affiliates of either Group against any member of either Group) or whether asserted or determined prior to the date hereof, and regardless of whether arising from or alleged to arise from negligence, recklessness, violation of Law, fraud, misrepresentation or any other cause by any member of either Group, or any of their respective directors, officers, employees, agents or managers.

 

Except as otherwise specifically set forth in this Agreement or any Ancillary Agreement, (A) and except for where the assumption by CRC of any CRC Liabilities would be a violation of applicable Law, or require any Approvals or Notifications in connection with the Separation or the Distribution that have not been obtained or made by the Distribution Date, to the extent that any CRC Liabilities have not been accepted and assumed by CRC or an applicable CRC Designee in accordance with Section 2.1(a)(ii) as of immediately prior to the Distribution Date, then from and after the Distribution Date, CRC shall and hereby does, accept, assume and agree faithfully to perform,

 

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discharge and fulfill all such CRC Liabilities in accordance with their respective terms and (B) and except for where the assumption by OPC of any OPC Liabilities would be a violation of applicable Law, or require any Approvals or Notifications in connection with the Separation or the Distribution that have not been obtained or made by the Distribution Date, to the extent that any OPC Liabilities have not been accepted and assumed by OPC or an applicable OPC Group member in accordance with Section 2.1(a)(iv) as of immediately prior to the Distribution Date, then from and after the Distribution Date, OPC shall and hereby does, accept, assume and agree faithfully to perform, discharge and fulfill all such OPC Liabilities in accordance with their respective terms.

 

(b)                                  In furtherance of the assignment, transfer and conveyance of the CRC Assets and the assumption of the CRC Liabilities in accordance with Sections 2.1(a)(i) and 2.1(a)(ii)  and Section 2.1(d), on, before and/or as of the date that such CRC Assets are assigned, transferred or conveyed or such CRC Liabilities are assumed (i) OPC shall execute and deliver, and shall cause its Subsidiaries to execute and deliver, such bills of sale, deeds, stock powers, certificates of title, assignments of contracts and other instruments of transfer, conveyance and assignment as and to the extent necessary to evidence the transfer, conveyance and assignment of all of OPC’s and its Subsidiaries’ (other than CRC and its Subsidiaries) right, title and interest in and to the CRC Assets to CRC and the CRC Designees, and (ii) CRC shall execute and deliver, and shall cause the CRC Designees to execute and deliver, such assumptions of contracts and other instruments of assumption as and to the extent necessary to evidence the valid and effective assumption of the CRC Liabilities.  All of the foregoing documents contemplated by this Section 2.1(b) shall be referred to collectively herein as the “ OPC Transfer Documents .”

 

(c)                                   In furtherance of the assignment, transfer and conveyance of OPC Assets and the assumption of OPC Liabilities set forth in Sections 2.1(a)(iii) and 2.1(a)(iv) and Section 2.1(e), on, before and/or as of the date that such CRC Assets are assigned, transferred or conveyed or such CRC Liabilities are assumed: (i) CRC shall execute and deliver, and shall cause its Subsidiaries to execute and deliver, such bills of sale, quitclaim deeds, stock powers, certificates of title, assignments of contracts and other instruments of transfer, conveyance and assignment as and to the extent necessary to evidence the transfer, conveyance and assignment of all of CRC’s and its Subsidiaries’ right, title and interest in and to the OPC Assets to OPC and its Subsidiaries, and (ii) OPC shall execute and deliver, and shall cause its Subsidiaries to execute and deliver, such assumptions of contracts and other instruments of assumption as and to the extent necessary to evidence the valid and effective assumption of the OPC Liabilities.  All of the foregoing documents contemplated by this Section 2.1(c) shall be referred to collectively herein as the “ CRC Transfer Documents ” and, together with the OPC Transfer Documents, the “ Transfer Documents .”

 

(d)                                  To the extent any CRC Asset is not transferred, assigned or delivered to or retained by, or any CRC Liability is not assumed by or retained by, a member of the CRC Group at the Distribution Date or is owned or held by a member of the OPC Group after the Distribution Date, from and after the Distribution Date, any such CRC Asset or CRC Liability shall be held by such member of the OPC Group for the use and benefit of the member of the CRC Group entitled thereto (at the expense of the member of the CRC Group entitled thereto) in accordance with Section 2.4(e), and, subject to Section 2.4(c):

 

(i)                                      OPC shall, and shall cause its applicable Subsidiaries to, as soon as reasonably practicable, assign, transfer, convey and deliver to CRC or certain of its Subsidiaries designated by CRC, and CRC or such Subsidiaries shall accept from OPC and its applicable Subsidiaries, all of OPC’s and such Subsidiaries’ respective right, title and interest in and to such CRC Assets; and

 

(ii)                                   CRC and certain of its Subsidiaries designated by CRC shall, as soon as reasonably practicable, accept, assume and agree faithfully to perform, discharge and fulfill all such CRC Liabilities in accordance with their respective terms.

 

(e)                                   To the extent any OPC Asset is not transferred, assigned or delivered to or retained by, or any OPC Liability is not assumed by or retained by, a member of the OPC Group at the Distribution Date or is owned or held by a member of the CRC Group after the Distribution Date, from and after the Distribution Date, any such OPC Asset or OPC Liability shall be held by such member of the CRC Group for the use and benefit of the member of the OPC Group entitled thereto (at the expense of the member of the OPC Group entitled thereto) in accordance with Section 2.4(f), and, subject to Section 2.4(d):

 

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(i)                                      CRC shall, and shall cause its applicable Subsidiaries to, as soon as reasonably practicable, assign, transfer, convey and deliver to OPC or certain of its Subsidiaries designated by OPC, and OPC or such Subsidiaries shall accept from CRC and its applicable Subsidiaries, all of CRC’s and such Subsidiaries’ respective right, title and interest in and to such OPC Assets; and

 

(ii)                                   OPC and certain of its Subsidiaries designated by OPC shall, as soon as reasonably practicable, accept, assume and agree faithfully to perform, discharge and fulfill all such OPC Liabilities in accordance with their respective terms.

 

(f)                                    CRC hereby waives compliance by each and every member of the OPC Group with the requirements and provisions of any “bulk-sale” or “bulk-transfer” Laws of any jurisdiction that may otherwise be applicable with respect to the transfer or sale of any or all of the CRC Assets to any member of the CRC Group.

 

(g)                                   OPC hereby waives compliance by each and every member of the CRC Group with the requirements and provisions of any “bulk-sale” or “bulk-transfer” Laws of any jurisdiction that may otherwise be applicable with respect to the transfer or sale of any or all of the OPC Assets to any member of the OPC Group.

 

2.2                                CRC Assets .

 

(a)                                  For purposes of this Agreement, “ CRC Assets ” means (without duplication):

 

(i)                                      all Assets that are specifically provided pursuant to the express terms of this Agreement or any Ancillary Agreement as Assets to be transferred to CRC or any other member of the CRC Group, including the Assets listed on Schedule 2.2(a)(i) ;

 

(ii)                                   (A) all CRC Contracts, (B) all issued and outstanding equity interests held by OPC or its Subsidiaries in the wholly owned Subsidiaries and Affiliates of OPC that have been or shall be contributed to, or otherwise transferred, conveyed, or assigned to, the CRC Group or entities that shall be members of the CRC Group as of the Distribution Date, as listed on Schedule 2.2(a)(ii)(B) (such Subsidiaries and entities, the “ Transferred Entities ”), and (C) the shares of capital stock or other equity interests held by OPC or its Subsidiaries in certain entities (other than the Transferred Entities) that have been or shall be contributed to, or otherwise transferred, conveyed, or assigned to, the CRC Group as listed on Schedule 2.2(a)(ii)(C) ;

 

(iii)                                all Assets reflected as assets of CRC or its Subsidiaries on the CRC Balance Sheet, subject to any dispositions of such Assets subsequent to the date of the CRC Balance Sheet;

 

(iv)                               all CRC Intellectual Property;

 

(v)                                  all permits, waivers, authorizations and similar approvals issued under or pursuant to any Environmental Laws used or held for use by OPC or any of its Subsidiaries exclusively in the CRC Business or listed on Schedule 2.2(a)(v) ;

 

(vi)                               any Shared Contracts (but only to the extent assigned to CRC pursuant to Section 2.8(a));

 

(vii)                            any and all Assets (including oil and gas interests) owned and used or held for use immediately prior to the Distribution Date by OPC or any of its Subsidiaries exclusively in the CRC Business, including any account or trade receivables, inventory, property, plant and equipment, prepaid expenses and other assets associated with oil, gas and NGL production by the CRC Business, whether or not reflected as assets of CRC or its Subsidiaries on the CRC Balance Sheet.

 

Notwithstanding the foregoing, the CRC Assets shall not, in any event, include the OPC Assets referred to in Section 2.2(b) (other than 2.2(b)(v)).  All rights of the CRC Group in respect of OPC insurance policies are set forth in Article VI and shall not be included in the CRC Assets.

 

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(b)                                  For the purposes of this Agreement, “ OPC Assets ” means (without duplication):

 

(i)                                      the Assets listed on Schedule 2.2(b)(i) and any and all other Assets that are specifically provided pursuant to the express terms of this Agreement or any Ancillary Agreement as Assets to be retained by OPC or any other member of the OPC Group;

 

(ii)                                   any cash or cash equivalents withdrawn from CRC Accounts in accordance with Sections 2.9(c), (d) or (e);

 

(iii)                                the OPC Intellectual Property and OPC Software;

 

(iv)                               any Shared Contracts (other than CRC Assets arising under any Shared Contracts due to the operation of Section 2.8(a)); and

 

(v)                                  any and all Assets of any members of the OPC Group that are not CRC Assets pursuant to Section 2.2(a).

 

2.3                                CRC Liabilities .

 

(a)                                  For the purposes of this Agreement, “ CRC Liabilities ” means (without duplication):

 

(i)                                      all Liabilities, including any Environmental Liabilities to the extent relating to:

 

(A)                                the operation or ownership of the CRC Business, as conducted at any time prior to, on or after the Distribution Date (including any Liability related to oil and gas properties and operations in California formerly owned or operated by OPC or any of its Subsidiaries and the marketing and trading of commodities related to such properties at the time they were owned or operated by OPC or any of its Subsidiaries ), including any Liability relating to, arising out of or resulting from (i) any strict liability under or violation of Environmental Law at any CRC Assets; (ii) a Release of Hazardous Materials to, on or under any CRC Assets (including Releases that migrate from CRC Assets to, on or under contiguous properties); or (iii) any Liabilities related to Hazardous Materials generated, transported from or disposed of by any CRC Business, including any act or failure to act by any Person, whether or not such act or failure to act is or was within such Person’s authority; or

 

(B)                                any CRC Assets, including any CRC Contracts, Shared Contracts (to the extent related to the CRC Business) and any real property and leasehold interests;

 

in any such case, whether arising before, on or after the Distribution Date;

 

(ii)                                   the Liabilities listed on Schedule 2.3(a)(ii) (subject to any discharge of any such Liabilities prior to the Distribution Date) and any and all other Liabilities that are expressly contemplated by this Agreement or any Ancillary Agreement as Liabilities to be assumed by CRC or any member of the CRC Group, and all agreements, obligations and Liabilities of any member of the CRC Group under this Agreement or any of the Ancillary Agreements;

 

(iii)                                all Liabilities relating to, arising out of or resulting from the CRC Financing Arrangements;

 

(iv)                               all Liabilities reflected as liabilities or obligations of CRC or its Subsidiaries on the CRC Balance Sheet, subject to any discharge of such Liabilities subsequent to the date of the CRC Balance Sheet; and

 

(v)                                  all Liabilities arising out of claims made by the respective directors, officers, stockholders, employees, agents, managers, Subsidiaries or Affiliates of either Group against any member

 

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of either Group relating to, arising out of or resulting from the CRC Business or the other businesses, operations, activities or Liabilities referred to in clauses (i) through (iv) above, inclusive.

 

Notwithstanding the foregoing, the CRC Liabilities shall not include (i) the Liabilities listed on Schedule 2.3(b)(i) , (ii) any and all other Liabilities that are expressly stated in this Agreement or any Ancillary Agreement as Liabilities to be retained or assumed by OPC or any other member of the OPC Group, and (iii) all agreements and obligations of any member of the OPC Group under this Agreement or any of the Ancillary Agreements.

 

(b)                                  For the purposes of this Agreement, “ OPC Liabilities ” means (without duplication): all Liabilities of OPC and its Subsidiaries as of the Distribution Date other than CRC Liabilities.

 

2.4                                Approvals and Notifications .

 

(a)                                  To the extent that the transfer or assignment of any CRC Asset, the assumption of any CRC Liability, the Separation or the Distribution requires any Approvals or Notifications, the parties will endeavor to obtain or make such Approvals or Notifications as soon as reasonably practicable; provided , however , that, except to the extent expressly provided in this Agreement (including in Section 2.4(j)) or any of the Ancillary Agreements or as otherwise agreed between OPC and CRC, neither OPC nor CRC shall be obligated to contribute capital or pay any consideration in any form (including providing any letter of credit, guaranty or other financial accommodation) to any Person in order to obtain or make such Approvals or Notifications.

 

(b)                                  To the extent that the transfer or assignment of any OPC Asset, the assumption of any OPC Liability, the Separation or the Distribution requires any Approvals or Notifications, the parties will endeavor to obtain or make such Approvals or Notifications as soon as reasonably practicable; provided , however , that, except to the extent expressly provided in this Agreement (including in Section 2.4(j)) or any of the Ancillary Agreements or as otherwise agreed between OPC and CRC, neither OPC nor CRC shall be obligated to contribute capital or pay any consideration in any form (including providing any letter of credit, guaranty or other financial accommodation) to any Person in order to obtain or make such Approvals or Notifications.

 

(c)                                   If and to the extent that the valid, complete and perfected transfer or assignment to the CRC Group of any CRC Assets or assumption by the CRC Group of any CRC Liabilities would be a violation of applicable Law, or require any Approvals or Notifications in connection with the Separation or the Distribution that have not been obtained or made by the Distribution Date, then, unless the parties hereto shall otherwise mutually determine, the transfer or assignment to the CRC Group of such CRC Assets or the assumption by the CRC Group of such CRC Liabilities, as the case may be, shall be automatically deemed deferred and any such purported transfer, assignment or assumption shall be null and void until such time as all legal impediments are removed or such Approvals or Notifications have been obtained or made.  Notwithstanding the foregoing, any such CRC Assets or CRC Liabilities shall continue to constitute CRC Assets and CRC Liabilities for all other purposes of this Agreement.

 

(d)                                  If and to the extent that the valid, complete and perfected transfer or assignment to the OPC Group of any OPC Assets or assumption by the OPC Group of any OPC Liabilities would be a violation of applicable Law, or require any Approvals or Notifications in connection with the Separation or the Distribution that have not been obtained or made by the Distribution Date, then, unless the parties hereto shall otherwise mutually determine, the transfer or assignment to the OPC Group of such OPC Assets or the assumption by the OPC Group of such OPC Liabilities, as the case may be, shall be automatically deemed deferred and any such purported transfer, assignment or assumption shall be null and void until such time as all legal impediments are removed or such Approvals or Notifications have been obtained or made.  Notwithstanding the foregoing, any such OPC Assets or OPC Liabilities shall continue to constitute OPC Assets and OPC Liabilities for all other purposes of this Agreement.

 

(e)                                   If any transfer or assignment of any CRC Asset or any assumption of any CRC Liability intended to be transferred, assigned or assumed hereunder, as the case may be, is not consummated on or prior to the Distribution Date, whether as a result of the provisions of Section 2.4(c) or for any other reason, then, insofar as reasonably possible, the member of the OPC Group retaining such CRC Asset or such CRC Liability, as the case may be, shall thereafter hold such CRC Asset or CRC Liability, as the case may be, for the use, benefit and/or

 

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burden of the member of the CRC Group entitled thereto (at the expense and for the account of the member of the CRC Group entitled thereto).  In addition, the member of the OPC Group retaining such CRC Asset or such CRC Liability shall, insofar as reasonably possible and to the extent permitted by applicable Law, treat such CRC Asset or CRC Liability in the ordinary course of business in accordance with past practice and take such other actions as may be reasonably requested by the member of the CRC Group to whom such CRC Asset is to be transferred or assigned, or which will assume such CRC Liability, as the case may be, in order to place such member of the CRC Group in a substantially similar position as if such CRC Asset or CRC Liability had been transferred, assigned or assumed as contemplated hereby and so that all the benefits and burdens relating to such CRC Asset or CRC Liability, as the case may be, including use, risk of loss, potential for gain, and dominion, control and command over such CRC Asset or CRC Liability, as the case may be, and all costs and expenses related thereto, shall inure from and after the Distribution Date to the CRC Group.

 

(f)                                    If any transfer or assignment of any OPC Asset or any assumption of any OPC Liability intended to be transferred, assigned or assumed hereunder, as the case may be, is not consummated on or prior to the Distribution Date, whether as a result of the provisions of Section 2.4(d) or for any other reason, then, insofar as reasonably possible, the member of the CRC Group retaining such OPC Asset or such OPC Liability, as the case may be, shall thereafter hold such OPC Asset or OPC Liability, as the case may be, for the use, benefit and/or burden of the member of the OPC Group entitled thereto (at the expense and for the account of the member of the OPC Group entitled thereto).  In addition, the member of the CRC Group retaining such OPC Asset or such OPC Liability shall, insofar as reasonably possible and to the extent permitted by applicable Law, treat such OPC Asset or OPC Liability in the ordinary course of business in accordance with past practice and take such other actions as may be reasonably requested by the member of the OPC Group to whom such OPC Asset is to be transferred or assigned, or which will assume such OPC Liability, as the case may be, in order to place such member of the OPC Group in a substantially similar position as if such OPC Asset or OPC Liability had been transferred, assigned or assumed as contemplated hereby and so that all the benefits and burdens relating to such OPC Asset or OPC Liability, as the case may be, including use, risk of loss, potential for gain, and dominion, control and command over such OPC Asset or OPC Liability, as the case may be, and all costs and expenses related thereto, shall inure from and after the Distribution Date to the OPC Group.

 

(g)                                   If the transfer or assignment of any OPC Asset or the assumption of any OPC Liability not intended to be transferred, assigned or assumed hereunder, as the case may be, is consummated on or prior to the Distribution Date, then, insofar as reasonably possible, the member of the CRC Group holding or owning such OPC Asset or such OPC Liability, as the case may be, shall thereafter hold such OPC Asset or OPC Liability, as the case may be, for the use, benefit and/or burden of the member of the OPC Group entitled thereto (at the expense of the member of the OPC Group entitled thereto).  In addition, the member of the CRC Group retaining such OPC Asset or such OPC Liability shall, insofar as reasonably possible and to the extent permitted by applicable Law, treat such OPC Asset or OPC Liability in the ordinary course of business in accordance with past practice and take such other actions as may be reasonably requested by the member of the OPC Group to whom such OPC Asset is to be transferred or assigned, or which will assume such OPC Liability, as the case may be, in order to place such member of the OPC Group in a substantially similar position as if such OPC Asset or OPC Liability had not been so transferred, assigned or assumed and so that all the benefits and burdens relating to such OPC Asset or OPC Liability, as the case may be, including use, risk of loss, potential for gain, and dominion, control and command over such OPC Asset or OPC Liability, as the case may be, and all costs and expenses related thereto, shall inure from and after the Distribution Date to the OPC Group.

 

(h)                                  If the transfer or assignment of any CRC Asset or the assumption of any CRC Liability not intended to be transferred, assigned or assumed hereunder, as the case may be, is consummated on or prior to the Distribution Date, then, insofar as reasonably possible, the member of the OPC Group holding or owning such CRC Asset or such CRC Liability, as the case may be, shall thereafter hold such CRC Asset or CRC Liability, as the case may be, for the use, benefit and/or burden of the member of the CRC Group entitled thereto (at the expense of the member of the CRC Group entitled thereto).  In addition, the member of the OPC Group retaining such CRC Asset or such CRC Liability shall, insofar as reasonably possible and to the extent permitted by applicable Law, treat such CRC Asset or CRC Liability in the ordinary course of business in accordance with past practice and take such other actions as may be reasonably requested by the member of the CRC Group to whom such CRC Asset is to be transferred or assigned, or which will assume such CRC Liability, as the case may be, in order to place such member of the CRC Group in a substantially similar position as if such CRC Asset or CRC Liability had not been so

 

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transferred, assigned or assumed and so that all the benefits and burdens relating to such CRC Asset or CRC Liability, as the case may be, including use, risk of loss, potential for gain, and dominion, control and command over such CRC Asset or CRC Liability, as the case may be, and all costs and expenses related thereto, shall inure from and after the Distribution Date to the CRC Group.

 

(i)                                      If and when the Approvals or Notifications, the absence of which caused the deferral of transfer or assignment of any CRC Asset or the deferral of assumption of any CRC Liability pursuant to Section 2.4(c) or the deferral of transfer or assignment of any OPC Asset or the deferral of assumption of any OPC Liability pursuant to Section 2.4(d), are obtained or made, and, if and when any other legal impediments for the transfer or assignment of any CRC Asset or the assumption of any CRC Liability or for the transfer or assignment of any OPC Asset or the assumption of any OPC Liability, have been removed, the transfer or assignment of the applicable CRC Asset or the assumption of the applicable CRC Liability or the transfer or assignment of the applicable OPC Asset or the assumption of the applicable OPC Liability, as the case may be, shall be effected in accordance with the terms of this Agreement and/or the applicable Ancillary Agreement.

 

(j)                                     Except as otherwise agreed between OPC and CRC, (i) any member of the OPC Group holding, owning or retaining a CRC Asset or CRC Liability (whether as a result of the provisions of Section 2.4(c) or for any other reason), and (ii) any member of the CRC Group holding, owning or retaining an OPC Asset or OPC Liability due to a transfer or assignment to, or assumption by, such member of the CRC Group (whether as a result of the provisions of Section 2.4(d) or for any other reason), shall not be obligated, in order to effect the transfer of such Asset or Liability to the Group member entitled thereto, to expend any money unless the necessary funds are advanced (or otherwise made available) by the Group member entitled thereto, other than reasonable out-of-pocket expenses, attorneys’ fees and recording or similar fees, all of which shall be promptly reimbursed by the Group member entitled to such Asset or Liability.

 

2.5                                Novation of CRC Liabilities .

 

(a)                                  Each of OPC and CRC, at the request of the other, shall endeavor, if reasonably practicable, to obtain, or to cause to be obtained, if reasonably practicable, any consent, substitution, approval or amendment required to novate or assign all obligations under agreements, leases, licenses and other obligations or Liabilities of any nature whatsoever that constitute CRC Liabilities, or to obtain in writing the unconditional release of all parties to such arrangements other than any member of the CRC Group, so that, in any such case, the members of the CRC Group will be solely responsible for the CRC Liabilities; provided , however , that neither OPC nor CRC shall be obligated to contribute any capital or pay any consideration in any form (including providing any letter of credit, guaranty or other financial accommodation) to any third Person from whom any such consent, substitution, approval, amendment or release is requested.

 

(b)                                  If OPC or CRC is unable to obtain, or to cause to be obtained, any such required consent, substitution, approval, amendment or release and the applicable member of the OPC Group continues to be bound by such agreement, lease, license or other obligation or Liability (each, an “ Unreleased CRC Liability ”), CRC shall, to the extent not prohibited by Law, as indemnitor, guarantor, agent or subcontractor for such member of the OPC Group, as the case may be, (i) pay, perform and discharge fully all the obligations or other Liabilities of such member of the OPC Group that constitute Unreleased CRC Liabilities from and after the Distribution Date and (ii) use its commercially reasonable efforts to effect such payment, performance, or discharge prior to any demand for such payment, performance, or discharge is permitted to be made by the obligee thereunder on any member of the OPC Group.  If and when any such consent, substitution, approval, amendment or release shall be obtained or the Unreleased CRC Liabilities shall otherwise become assignable or able to be novated, OPC shall promptly assign, or cause to be assigned, and CRC or the applicable CRC Group member shall assume, such Unreleased CRC Liabilities without exchange of further consideration.

 

2.6                                Novation of OPC Liabilities .

 

(a)                                  Each of OPC and CRC, at the request of the other, shall endeavor, if reasonably practicable, to obtain, or to cause to be obtained, if reasonably practicable, any consent, substitution, approval or amendment required to novate or assign all obligations under agreements, leases, licenses and other obligations or Liabilities of any nature whatsoever that constitute OPC Liabilities, or to obtain in writing the unconditional release

 

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of all parties to such arrangements other than any member of the OPC Group, so that, in any such case, the members of the OPC Group will be solely responsible for such OPC Liabilities; provided , however , that neither OPC nor CRC shall be obligated to contribute any capital or pay any consideration in any form (including providing any letter of credit, guaranty or other financial accommodation) to any third Person from whom any such consent, substitution, approval, amendment or release is requested.

 

(b)                                  If OPC or CRC is unable to obtain, or to cause to be obtained, any such required consent, substitution, approval, amendment or release and the applicable member of the CRC Group continues to be bound by such agreement, lease, license or other obligation or Liability (each, an “ Unreleased OPC Liability ”), OPC shall, to the extent not prohibited by Law, as indemnitor, guarantor, agent or subcontractor for such member of the CRC Group, as the case may be, (i) pay, perform and discharge fully all the obligations or other Liabilities of such member of the CRC Group that constitute Unreleased OPC Liabilities from and after the Distribution Date and (ii) use its commercially reasonable efforts to effect such payment, performance, or discharge prior to any demand for such payment, performance, or discharge is permitted to be made by the obligee thereunder on any member of the CRC Group.  If and when any such consent, substitution, approval, amendment or release shall be obtained or the Unreleased OPC Liabilities shall otherwise become assignable or able to be novated, CRC shall promptly assign, or cause to be assigned, and OPC or the applicable OPC Group member shall assume, such Unreleased OPC Liabilities without exchange of further consideration.

 

2.7                                Termination of Agreements .

 

(a)                                  Except as set forth in Section 2.7(b), in furtherance of the releases and other provisions of this Agreement, CRC and each member of the CRC Group, on the one hand, and OPC and each member of the OPC Group, on the other hand, hereby terminate any and all agreements, arrangements, commitments or understandings, whether or not in writing, between or among CRC and/or any member of the CRC Group and/or any entity that shall be a member of the CRC Group as of the Distribution Date, on the one hand, and OPC and/or any member of the OPC Group (other than entities that shall be members of the CRC Group as of the Distribution Date), on the other hand, effective as of the Distribution Date.  No such terminated agreement, arrangement, commitment or understanding (including any provision thereof which purports to survive termination) shall be of any further force or effect after the Distribution Date.  Each party shall, at the reasonable request of the other party, take, or cause to be taken, such other actions as may be necessary to effect the foregoing.

 

(b)                                  The provisions of Section 2.7(a) shall not apply to any of the following agreements, arrangements, commitments or understandings (or to any of the provisions thereof): (i) this Agreement and the Ancillary Agreements (and each other agreement or instrument expressly contemplated by this Agreement or any Ancillary Agreement to be entered into by any of the parties hereto or any of the members of their respective Groups); (ii) any agreements, arrangements, commitments or understandings listed or described on Schedule 2.7(b)(ii) ; (iii) any agreements, arrangements, commitments or understandings to which any Person other than the parties hereto and the members of their respective Groups is a party (it being understood that to the extent that the rights and obligations of the parties and the members of their respective Groups under any such agreements, arrangements, commitments or understandings constitute CRC Assets or CRC Liabilities, they shall be assigned pursuant to Section 2.1); (iv) any agreements, arrangements, commitments or understandings to which any member of the OPC Group or CRC Group, other than OPC, CRC or a wholly owned Subsidiary of OPC or CRC, as the case may be, is a party (it being understood that directors’ qualifying shares or similar interests will be disregarded for purposes of determining whether a Subsidiary is wholly owned); (v) any Shared Contracts; and (vi) any other agreements, arrangements, commitments or understandings that this Agreement or any Ancillary Agreement expressly states will survive the Distribution Date.

 

2.8                                Treatment of Shared Contracts .

 

(a)                                  Without limiting the generality of the obligations set forth in Section 2.1, unless the parties otherwise agree or the benefits of any contract, agreement, arrangement, commitment or understanding described in this Section 2.8 are expressly conveyed to the applicable party pursuant to an Ancillary Agreement, any contract, agreement, arrangement, commitment or understanding that is listed on Schedule 2.8(a) shall be assigned in part to the applicable member(s) of the applicable Group, if so assignable, or appropriately amended prior to, on or after the Distribution Date, so that each party or the members of its respective Group shall, as of the Distribution

 

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Date, be entitled to the rights and benefits, and shall assume the related portion of any Liabilities, inuring to its respective businesses, in each case, in accordance with the allocation of benefits and burdens set forth on Schedule 2.8(a) (each, a “ Shared Contract ”); provided , however , that, (i) in no event shall any member of any Group be required to assign (or amend) any Shared Contract in its entirety or to assign a portion of any Shared Contract which is not assignable (or cannot be amended) by its terms (including any terms imposing consents or conditions on an assignment where such consents or conditions have not been obtained or fulfilled) and (ii) if any Shared Contract cannot be so partially assigned by its terms or otherwise, or cannot be amended or if such assignment or amendment would impair the benefit the parties thereto derive from such Shared Contract, then the parties shall, and shall cause each of their respective Subsidiaries to, take such other reasonable and permissible actions (including by providing prompt notice to the other party with respect to any relevant claim of Liability or other relevant matters arising in connection with a Shared Contract so as to allow such other party the ability to exercise any applicable rights under such Shared Contract) to cause a member of the CRC Group or the OPC Group, as the case may be, to receive the rights and benefits of that portion of each Shared Contract that relates to the CRC Business or the businesses retained by OPC, as the case may be (in each case, to the extent so related), as if such Shared Contract had been assigned to (or amended to allow) a member of the applicable Group pursuant to this Section 2.8, and to bear the burden of the corresponding Liabilities (including any Liabilities that may arise by reason of such arrangement), as if such Liabilities had been assumed by a member of the applicable Group pursuant to this Section 2.8.

 

(b)                                  Each of OPC and CRC shall, and shall cause the members of its Group to, (i) treat for all Tax purposes the portion of each Shared Contract inuring to its respective businesses as Assets owned by, and/or Liabilities of, as applicable, such party, or its subsidiaries, as applicable, not later than the Distribution Date, and (ii) neither report nor take any Tax position (on a Tax Return or otherwise) inconsistent with such treatment (unless required by applicable Law).

 

(c)                                   Nothing in this Section 2.8 shall require any member of any Group to make any material payment (except to the extent advanced, assumed or agreed in advance to be reimbursed by any member of the other Group), incur any material obligation or grant any material concession for the benefit of any member of any other Group in order to effect any transaction contemplated by this Section 2.8.

 

2.9                                Bank Accounts; Cash Balances .

 

(a)                                  OPC and CRC each agrees to take, or cause the respective members of their respective Groups to take, at the Distribution Date (or such earlier time as OPC and CRC may agree), all actions necessary to amend all contracts or agreements governing each bank and brokerage account owned by CRC or any other member of the CRC Group (collectively, the “ CRC Accounts ”) so that such CRC Accounts, if currently linked (whether by automatic withdrawal, automatic deposit or any other authorization to transfer funds from or to, hereinafter “linked”) to any bank or brokerage account owned by OPC or any other member of the OPC Group (collectively, the “ OPC Accounts ”), are de-linked from the OPC Accounts.

 

(b)                                  OPC and CRC each agrees to take, or cause the respective members of their respective Groups to take, at the Distribution Date (or such earlier time as OPC and CRC may agree), all actions necessary to amend all agreements governing the OPC Accounts so that such OPC Accounts, if currently linked to a CRC Account, are de-linked from the CRC Accounts.

 

(c)                                   It is intended that, following consummation of the actions contemplated by Sections 2.9(a) and 2.9(b), there will be in place a centralized cash management process pursuant to which the CRC Accounts will be managed centrally and funds collected will be transferred into one or more centralized accounts maintained by CRC or its designee; provided that, prior to and through the Distribution Date, the funds in such centralized CRC Accounts will be transferred on a daily basis to one or more centralized accounts managed by OPC, at the discretion of OPC.

 

(d)                                  It is intended that, following consummation of the actions contemplated by Sections 2.9(a) and 2.9(b), there will continue to be in place a centralized cash management process pursuant to which the OPC Accounts will be managed centrally and funds collected will be transferred into one or more centralized accounts maintained by OPC or its designee.

 

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(e)                                   With respect to any outstanding payments initiated by OPC, CRC, or any of their respective Subsidiaries prior to the Separation, such outstanding payments shall be honored following the Separation by the Person or Group owning the account from which the payment was initiated.

 

(f)                                    As between OPC and CRC (and the members of their respective Groups) all payments made and reimbursements received after the Separation by either party (or member of its Group) that relate to a business, Asset or Liability of the other party (or member of its Group), shall be held by such party for the use and benefit of the party entitled thereto (at the expense of the party entitled thereto).  Each party shall maintain an accounting of any such payments and reimbursements, and the parties shall have a monthly reconciliation, whereby all such payments made and reimbursements received by each party are calculated and the net amount owed to OPC or CRC shall be paid over with right of set-off.  If at any time the net amount owed to either party exceeds $10,000,000, an interim payment of such net amount owed shall be made to the party entitled thereto within three (3) business days of such amount exceeding $10,000,000.  Notwithstanding the foregoing, neither OPC nor CRC shall act as collection agent for the other party, nor shall either party act as surety or endorser with respect to non-sufficient funds checks, or funds to be returned in a bankruptcy or fraudulent conveyance action.

 

2.10                         Other Ancillary Agreements .  Effective as of the date hereof, each of OPC and CRC will execute and deliver all Ancillary Agreements to which it is a party (other than the Transfer Documents, which will be executed on or prior to the Distribution Date).

 

2.11                         Disclaimer of Representations and Warranties .  EACH OF OPC (ON BEHALF OF ITSELF AND EACH MEMBER OF THE OPC GROUP) AND CRC (ON BEHALF OF ITSELF AND EACH MEMBER OF THE CRC GROUP) UNDERSTANDS AND AGREES THAT, EXCEPT AS EXPRESSLY SET FORTH HEREIN OR IN ANY ANCILLARY AGREEMENT, NO PARTY TO THIS AGREEMENT, ANY ANCILLARY AGREEMENT OR ANY OTHER AGREEMENT OR DOCUMENT CONTEMPLATED BY THIS AGREEMENT, ANY ANCILLARY AGREEMENT OR OTHERWISE, IS REPRESENTING OR WARRANTING IN ANY WAY AS TO THE ASSETS, BUSINESSES OR LIABILITIES TRANSFERRED OR ASSUMED AS CONTEMPLATED HEREBY OR THEREBY, AS TO ANY CONSENTS OR APPROVALS REQUIRED IN CONNECTION THEREWITH, AS TO THE VALUE OR FREEDOM FROM ANY SECURITY INTERESTS OF, OR ANY OTHER MATTER CONCERNING, ANY ASSETS OF SUCH PARTY, OR AS TO THE ABSENCE OF ANY DEFENSES OR RIGHT OF SET-OFF OR FREEDOM FROM COUNTERCLAIM WITH RESPECT TO ANY CLAIM OR OTHER ASSET, INCLUDING ANY ACCOUNTS RECEIVABLE, OF ANY PARTY, OR AS TO THE LEGAL SUFFICIENCY OF ANY ASSIGNMENT, DOCUMENT OR INSTRUMENT DELIVERED HEREUNDER TO CONVEY TITLE TO ANY ASSET OR THING OF VALUE UPON THE EXECUTION, DELIVERY AND FILING HEREOF OR THEREOF, AND IN ENTERING INTO THIS AGREEMENT, EACH OF OPC (ON BEHALF OF ITSELF AND EACH MEMBER OF THE OPC GROUP) AND CRC (ON BEHALF OF ITSELF AND EACH MEMBER OF THE CRC GROUP) ACKNOWLEDGES THAT IT IS NOT RELYING ON ANY SUCH REPRESENTATION OR WARRANTY.  EXCEPT AS MAY EXPRESSLY BE SET FORTH HEREIN OR IN ANY ANCILLARY AGREEMENT, ALL SUCH ASSETS ARE BEING TRANSFERRED ON AN “AS IS,” “WHERE IS” BASIS (AND, IN THE CASE OF ANY REAL PROPERTY, EXCEPT AS OTHERWISE AGREED BY OPC, BY MEANS OF A QUITCLAIM OR SIMILAR FORM DEED OR CONVEYANCE) AND THE RESPECTIVE TRANSFEREES SHALL BEAR THE ECONOMIC AND LEGAL RISKS THAT (I) ANY CONVEYANCE WILL PROVE TO BE INSUFFICIENT TO VEST IN THE TRANSFEREE GOOD AND MARKETABLE TITLE, FREE AND CLEAR OF ANY SECURITY INTEREST, AND (II) ANY NECESSARY APPROVALS OR NOTIFICATIONS ARE NOT OBTAINED OR THAT ANY REQUIREMENTS OF LAWS, INCLUDING ENVIRONMENTAL LAWS, OR JUDGMENTS ARE NOT COMPLIED WITH. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, OPC MAKES NO REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF HAZARDOUS MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE CRC ASSETS.

 

2.12                         CRC Financing Arrangements .  Prior to the Distribution Date, CRC shall enter into the CRC Financing Arrangements, on such terms and conditions as agreed by OPC (including the amount that shall be borrowed pursuant to the Financing Arrangements and the interest rates for such borrowings).  OPC and CRC shall participate in the preparation of all materials and presentations as may be reasonably necessary to secure funding

 

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pursuant to the CRC Financing Arrangements, including rating agency presentations necessary to obtain the requisite ratings needed to secure the financing under any of the CRC Financing Arrangements.  The parties agree that CRC, and not OPC, shall be ultimately responsible for all costs and expenses incurred by, and for reimbursement of such costs and expenses to, any member of the OPC Group or CRC Group associated with the CRC Financing Arrangements.

 

2.13                         Financial Information Certifications .  OPC’s disclosure controls and procedures and internal control over financial reporting (as each is contemplated by the Exchange Act) are currently applicable to CRC as its Subsidiary.  In order to enable the principal executive officer and principal financial officer of CRC to make the certifications required of them under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002, OPC, within twenty-five (25) days of the end of any fiscal quarter during which CRC remains its Subsidiary, shall provide CRC with one or more certifications with respect to such disclosure controls and procedures, its internal control over financial reporting and the effectiveness thereof.  Such certification(s) shall be provided by OPC (and not by any officer or employee in their individual capacity).

 

ARTICLE III
THE DISTRIBUTION

 

3.1                                The Initial Distribution and the Distribution .

 

(a)                                  OPC intends to consummate the Initial Distribution in the fourth quarter of 2014.  OPC will, in its sole and absolute discretion, determine the Distribution Date and all terms of the Distribution, including, without limitation, the form, structure and terms of any transaction(s) and/or offering(s) to effect the Distribution and the timing and conditions to the consummation of the Distribution.  In addition, OPC may, at any time and from time to time until the consummation of the Initial Distribution, modify or change the terms of the Initial Distribution, including, without limitation, by accelerating or delaying the timing of the consummation of all or part of the Initial Distribution.  For the avoidance of doubt, nothing in the foregoing shall in any way limit OPC’s right to terminate this Agreement or the Initial Distribution as set forth in Article IX or alter the consequences of any such termination from those specified in such Article.

 

(b)                                  CRC shall cooperate with OPC to accomplish the Distribution and shall, at OPC’s direction, promptly take any and all actions necessary or desirable to effect the Distribution, including, without limitation, the registration under the Securities Act and the Exchange Act of CRC Common Stock on an appropriate registration form or forms to be designated by OPC.  OPC shall select any investment bank or manager in connection with the Distribution, as well as any financial printer, solicitation and/or exchange agent and financial, legal, accounting and other advisors for OPC.  CRC and OPC, as the case may be, will provide to the Agent all share certificates and any information required in order to complete the Distribution.

 

3.2                                Actions Prior to the Initial Distribution .

 

(a)                                  OPC and CRC shall prepare and mail, prior to the Distribution Date, to the holders of OPC Common Stock, such information concerning CRC, its business, operations and management, the Initial Distribution and such other matters as OPC shall reasonably determine and as may be required by Law.  OPC and CRC will prepare, and CRC will, to the extent required under applicable Law, file with the SEC any such documentation and any requisite no-action letters which OPC determines are necessary or desirable to effectuate the Distribution, and OPC and CRC shall each use its commercially reasonable efforts to obtain all necessary approvals from the SEC with respect thereto as soon as practicable.

 

(b)                                  OPC and CRC shall take all such action as may be necessary or appropriate under the securities or blue sky laws of the United States (and any comparable Laws under any foreign jurisdiction) in connection with the Distribution.

 

(c)                                   CRC shall prepare and file, and shall use its commercially reasonable efforts to have approved, an application for the listing of the CRC Common Stock to be distributed in the Distribution on the NYSE, subject to official notice of distribution.

 

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(d)                                  OPC and CRC shall take all necessary action that may be required to provide for the adoption by CRC of the Amended and Restated Certificate of Incorporation of CRC (the “ CRC Certificate of Incorporation ”) and the Amended and Restated Bylaws of CRC, each in such form as may be reasonably determined by OPC and CRC, and CRC will file the CRC Certificate of Incorporation with the Secretary of State of the State of Delaware.

 

(e)                                   OPC and CRC shall take all actions as may be necessary to approve the stock-based employee benefit plans of CRC (and the grants of adjusted awards over OPC stock by OPC and of awards over CRC stock by CRC) in order to satisfy the requirement of Rule 16b-3 under the Exchange Act and the applicable rules and regulations of the NYSE.

 

3.3                                Conditions to Initial Distribution .

 

(a)                                  The consummation of the Initial Distribution will be subject to the satisfaction, or waiver by OPC in its sole and absolute discretion, of the conditions set forth in this Section 3.3(a).  Any determination by OPC regarding the satisfaction or waiver of any of such conditions will be conclusive.

 

(i)                                      The Separation shall have been completed in accordance with the Restructuring Steps Memorandum.

 

(ii)                                   OPC will have received a private letter ruling from the U.S. Internal Revenue Service substantially to the effect that, among other things, certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the Contribution and the Distribution will not cause the Distribution to be taxable to OPC or its Affiliates.

 

(iii)                                OPC shall have received an opinion of its tax counsel, in form and substance acceptable to OPC and which shall remain in full force and effect, that (i) certain transactions that will be undertaken in preparation for, or in connection with, the Contribution and Distribution will not be taxable to OPC or its Affiliates for federal income tax purposes and (ii) the Distribution and related transactions generally qualify as tax-free transactions under Sections 355, 361 and/or 368(a)(1)(D) of the Code

 

(iv)                               All Governmental Approvals necessary to consummate the Initial Distribution shall have been obtained and be in full force and effect.

 

(v)                                  The actions and filings necessary or appropriate under applicable securities laws in connection with the Initial Distribution will have been taken or made, and, where applicable, have become effective or been accepted by the applicable Governmental Authority.

 

(vi)                               No order, injunction or decree issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing the consummation of the Initial Distribution or any of the related transactions shall be in effect, and no other event outside the control of OPC shall have occurred or failed to occur that prevents the consummation of the Initial Distribution or any of the related transactions.

 

(vii)                            A Registration Statement on Form 10 registering the CRC Common Stock (the “ Form 10 ”) shall be effective under the Exchange Act, with no stop order in effect with respect thereto, and the Information Statement included therein (the “ Information Statement ”) shall have been mailed to OPC’s stockholders as of the Record Date.

 

(viii)                         The CRC Common Stock to be distributed to the OPC stockholders in the Distribution shall have been accepted for listing on the NYSE, subject to official notice of distribution.

 

(ix)                               Each of the Ancillary Agreements shall have been duly executed and delivered by the parties thereto.

 

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(x)                                  No events or developments shall have occurred or exist that, in the judgment of the OPC Board, in its sole and absolute discretion, make it inadvisable to effect the Initial Distribution or the other transactions contemplated hereby, or would result in the Initial Distribution or the other transactions contemplated hereby not being in the best interest of OPC or its stockholders.

 

(xi)                               OPC shall have received the Cash Dividends.

 

(xii)                            One or more independent nationally recognized investment banking firms or other firms acceptable to OPC, in its sole and absolute discretion, shall have delivered one or more solvency opinions to the OPC Board and the board of directors of CRC, in form and substance acceptable to OPC in its sole discretion, regarding the effect of the Distribution and related transactions.

 

(b)                                  The foregoing conditions are for the sole benefit of OPC and shall not give rise to or create any duty on the part of OPC or the OPC Board to waive or not waive such conditions or in any way limit OPC’s right to terminate this Agreement as set forth in Article IX or alter the consequences of any such termination from those specified in such Article.  Any determination made by the OPC Board prior to the Initial Distribution concerning the satisfaction or waiver of any or all of the conditions set forth in this Section 3.3 shall be conclusive.

 

3.4                                Certain Stockholder Matters .

 

(a)                                  Subject to Section 3.3, on or prior to the Distribution Date, OPC will deliver to the Agent for the benefit of holders of record of OPC Common Stock on the Record Date not less than 80.1% of the outstanding shares of CRC Common Stock (including, if such shares are represented by one or more stock certificates, such stock certificates, endorsed by OPC in blank) to be distributed to holders of record of OPC Common Stock in the Initial Distribution, and shall cause the transfer agent for the shares of OPC Common Stock to instruct the Agent to distribute on the Distribution Date the appropriate number of such shares of CRC Common Stock to each such holder or designated transferee or transferees of such holder by way of direct registration in book-entry form.  CRC will not issue paper stock certificates.  The Initial Distribution shall be effective at 11:59 p.m. Eastern Time on the Distribution Date or at such other time as OPC may determine.

 

(b)                                  Subject to Sections 3.3 and 3.4(c), and except as otherwise provided in the Employee Matters Agreement, each holder of OPC Common Stock on the Record Date will be entitled to receive in the Initial Distribution a number of whole shares of CRC Common Stock equal to the number of shares of OPC Common Stock held by such holder on the Record Date multiplied by the Distribution Ratio.

 

(c)                                   No fractional shares will be distributed or credited to book-entry accounts in connection with the Initial Distribution.  As soon as practicable after the Distribution Date, OPC shall direct the Agent to determine the number of whole shares and fractional shares of CRC Common Stock allocable to each holder of record or beneficial owner of OPC Common Stock as of the Record Date, to aggregate all such fractional shares and to sell the whole shares obtained thereby in open market transactions (with the Agent, in its sole and absolute discretion, determining when, how and through which broker-dealer and at what price to make such sales), and to cause to be distributed to each such holder or for the benefit of each such beneficial owner, in lieu of any fractional share, such holder’s or owner’s ratable share of the proceeds of such sale, after deducting any taxes required to be withheld and after deducting an amount equal to all brokerage charges, commissions and transfer taxes attributed to such sale.  Neither OPC nor CRC will be required to guarantee any minimum sale price for the fractional shares of CRC Common Stock.  Neither OPC nor CRC will be required to pay any interest on the proceeds from the sale of fractional shares.

 

(d)                                  Until the CRC Common Stock is duly transferred in accordance with this Section 3.4 and applicable Law, from and after the effective time of the Initial Distribution, CRC will regard the Persons entitled to receive such CRC Common Stock as record holders of CRC Common Stock in accordance with the terms of the Initial Distribution without requiring any action on the part of such Persons.  CRC agrees that, subject to any transfers of such stock, from and after the effective time of the Initial Distribution (i) each such holder will be entitled to receive all dividends payable on, and exercise voting rights and all other rights and privileges with respect to, the shares of CRC Common Stock then held by such holder, and (ii) each such holder will be entitled, without

 

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any action on the part of such holder, to receive evidence of ownership of the shares of CRC Common Stock then held by such holder.

 

ARTICLE IV
DISPUTE RESOLUTION

 

4.1                                General Provisions .

 

(a)                                  Any dispute, controversy or claim arising out of or relating to this Agreement or the Ancillary Agreements (except as otherwise set forth in any such Ancillary Agreements), including the validity, interpretation, breach or termination thereof (a “ Dispute ”), shall be resolved in accordance with the procedures set forth in this Article IV, which shall be the sole and exclusive procedures for the resolution of any such Dispute unless otherwise specified in the applicable Ancillary Agreement or in this Article IV.

 

(b)                                  Commencing with a request contemplated by Section 4.2, all communications between the parties or their representatives to attempt to resolve any Dispute shall be deemed to have been delivered in furtherance of a Dispute settlement and shall be exempt from disclosure and production, and shall not be introduced into evidence for any reason (whether as an admission or otherwise) before any arbitral tribunal.

 

(c)                                   The specific procedures set forth in this Article IV, including the time limits referenced herein, may be modified by agreement of both of the parties in writing.

 

(d)                                  All applicable statutes of limitations and defenses based upon the passage of time shall be tolled while the procedures specified in this Article IV are pending.  The parties will take any necessary or appropriate action required to effectuate such tolling.

 

4.2                                Consideration by Senior Executives .  If a Dispute is not resolved in the normal course of business at the operational level, the parties shall attempt in good faith to resolve the Dispute by negotiation between executives.  Either party may initiate the executive negotiation process by providing a written notice to the other (the “ Initial Notice ”).  Within fifteen (15) days after delivery of the Initial Notice, the receiving party shall submit to the other a written response (the “ Response ”).  The Initial Notice and the Response shall include (a) a statement of the Dispute and of each party’s respective position and (b) the name and title of the executive who will represent that party and of any other person who will accompany the executive.  The parties agree that such executives shall have full and complete authority to resolve any Disputes submitted pursuant to this Section 4.2.  Such executives will meet in person or by teleconference or video conference within thirty (30) days of the date of the Initial Notice to seek a resolution of the Dispute.  If the executives are unable to agree to a format for such meeting, the meeting shall be convened by teleconference.

 

4.3                                Mediation .  If a Dispute is not resolved by negotiation or if a meeting between executives is not held as provided in Section 4.2 within thirty (30) days from the delivery of the Initial Notice, resolution of such Dispute shall be attempted by mediation administered by the American Arbitration Association (the “ AAA ”) under its Commercial Mediation Procedures (the “ Mediation Procedures ”) as then in effect.  Unless otherwise agreed by OPC and CRC, the parties shall (a) conduct the mediation in Houston, Texas, and (b) select a mutually agreeable mediator.  If the parties are unable to agree upon a mediator within 10 days of the request for mediation, a mediator shall be appointed as set out in the Mediation Procedures.  The parties shall agree to a mutually convenient date and time to conduct the mediation; provided that the mediation must occur within thirty (30) days of the appointment of the mediator unless a later date is agreed to by the parties in writing.  Each party shall bear its own fees, costs and expenses and an equal share of the expenses of the mediation.  Each party shall designate an executive to have full and complete authority to resolve the Dispute and to represent its interests in the mediation, and each party may, in its sole and absolute discretion, include any number of other Representatives in the mediation process.  At the commencement of the mediation, either party may request to submit a written mediation statement to the mediator.

 

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4.4                                Arbitration .

 

(a)                                  Any Dispute that is not resolved within the latter of sixty (60) days from the delivery of the Initial Notice under Section 4.3 or the date of termination of mediation under the Mediation Procedures shall be settled by arbitration administered by the AAA in accordance with its Commercial Arbitration Rules (the “ AAA Commercial Arbitration Rules ”).

 

(b)                                  Without waiving its rights to any remedy under this Agreement and without first complying with the provisions of Sections 4.2 and 4.3, either party may seek any emergency measures of protection or interim relief (i) before any Texas federal or state court, (ii) before an emergency arbitrator, as provided for under the AAA Commercial Arbitration Rules, or (iii) before the arbitral tribunal established hereunder.

 

(c)                                   Unless otherwise agreed by OPC and CRC, any Dispute to be decided in arbitration hereunder shall be decided by a tribunal of three (3) arbitrators appointed pursuant to the AAA Commercial Arbitration Rules.

 

(d)                                  The place of arbitration shall be Houston, Texas.  The final hearing(s) in such arbitration shall take place within fourteen (14) months of the date of appointment of the arbitral tribunal, unless the parties agree otherwise in writing.

 

(e)                                   The arbitral tribunal will have the right to award, on an interim basis, or include in the final award, any relief which it deems proper in the circumstances, including money damages (with interest on unpaid amounts from the due date), injunctive relief (including specific performance) and attorneys’ fees and costs; provided that the arbitral tribunal will not award any relief not specifically requested by the parties and, in any event, will not award special damages.  Upon constitution of the arbitral tribunal following any grant of interim relief by a special arbitrator or court pursuant to Section 4.4(b), the tribunal may affirm or disaffirm that relief, and the parties will take such measures that are necessary to execute the tribunal’s decision.

 

(f)                                    So long as either party has a timely claim to assert, the agreement to arbitrate Disputes set forth in this Section 4.4 will continue in full force and effect subsequent to, and notwithstanding the completion, expiration or termination of, this Agreement.

 

(g)                                   Any award of the arbitrators shall state reasons and shall be conclusive and binding upon the parties. Judgment on any award rendered by the arbitrators may be entered in any court having jurisdiction thereof.

 

(h)                                  Each party shall bear its own fees, costs and expenses and shall bear an equal share of the costs and expenses of the arbitration, including the fees, costs and expenses of the arbitral tribunal, provided , that the arbitral tribunal may award the prevailing party its reasonable fees and expenses (including attorneys’ fees), including such reasonable fees and expenses for any Disputes relating to the parties’ rights and obligations for indemnification under this Agreement.

 

4.5                                Confidentiality .  Except as may be required by law or to enforce an award, neither a Party nor an arbitrator may disclose the existence, content or results of any arbitration hereunder without the prior written consent of the parties.

 

ARTICLE V
MUTUAL RELEASES; INDEMNIFICATION

 

5.1                                Release of Pre-Initial Distribution Claims .

 

(a)                                  Except as provided in Section 5.1(c), effective as of the Distribution Date, CRC does hereby, for itself and each other member of the CRC Group, their respective Affiliates (other than any member of the OPC Group), successors and assigns, and all Persons who at any time prior to the Distribution Date have been directors, officers, agents, managers, or employees of any member of the CRC Group (in each case, in their

 

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respective capacities as such), remise, release and forever discharge OPC and the members of the OPC Group, their respective Affiliates (other than any member of the CRC Group), successors and assigns, and all Persons who at any time prior to the Distribution Date have been stockholders, directors, officers, agents, managers or employees of any member of the OPC Group (in each case, in their respective capacities as such), and their respective heirs, executors, administrators, successors and assigns, from any and all Liabilities whatsoever, whether at law or in equity (including any right of contribution), whether arising under any contract or agreement, by operation of law or otherwise, including from fraud, existing or arising from any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the Distribution Date, including in connection with the transactions and all other activities to implement the Separation and the Distribution.

 

(b)                                  Except as provided in Section 5.1(c), effective as of the Distribution Date, OPC does hereby, for itself and each other member of the OPC Group, their respective Affiliates (other than any member of the CRC Group), successors and assigns, and all Persons who at any time prior to the Distribution Date have been directors, officers, agents, managers,  or employees of any member of the OPC Group (in each case, in their respective capacities as such), remise, release and forever discharge CRC, the respective members of the CRC Group, their respective Affiliates (other than any member of the OPC Group), successors and assigns, and all Persons who at any time prior to the Distribution Date have been stockholders, directors, officers, agents, managers,  or employees of any member of the CRC Group (in each case, in their respective capacities as such), and their respective heirs, executors, administrators, successors and assigns, from any and all Liabilities whatsoever, whether at law or in equity (including any right of contribution), whether arising under any contract or agreement, by operation of law or otherwise, including from fraud, existing or arising from any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the Distribution Date, including in connection with the transactions and all other activities to implement the Separation and the Distribution.

 

(c)                                   Nothing contained in Section 5.1(a) or (b) shall impair any right of any Person to enforce this Agreement, any Ancillary Agreement or any agreements, arrangements, commitments or understandings that are specified in Schedule 5.1(c)(i)  or Section 5.9(a) or the applicable Schedules thereto as not to terminate as of the Distribution Date, in each case in accordance with its terms.  Nothing contained in Section 5.1(a) or (b) shall release any Person from:

 

(i)                                      any Liability provided in or resulting from any agreement among any members of the OPC Group or the CRC Group that is specified in Schedule 5.1(c)(i)  or Section 2.7(b) of this Agreement or the applicable Schedules thereto as not to terminate as of the Distribution Date, or any other Liability specified in such Section 2.7(b) as not to terminate as of the Distribution Date;

 

(ii)                                   any Liability, contingent or otherwise, assumed, transferred, assigned or allocated to the Group of which such Person is a member in accordance with, or any other Liability of any member of any Group under, this Agreement or any Ancillary Agreement;

 

(iii)                                any Liability for the agreed upon purchase price or fee due arising out of the sale, lease, construction or receipt of goods, property or services purchased, obtained or used in the ordinary course of business by a member of one Group from a member of the other Group prior to the Distribution Date;

 

(iv)                               any Liability that the parties may have with respect to indemnification or contribution pursuant to this Agreement for claims brought against the parties by third Persons, which Liability shall be governed by the provisions of this Article V and Article VI and, if applicable, the other appropriate provisions of this Agreement and the other Ancillary Agreements; or

 

(v)                                  any Liability the release of which would result in the release of any third Person other than a Person released pursuant to this Section 5.1; provided , however , that the parties agree not to bring or allow their respective Subsidiaries to bring suit against the other party or any of their respective past, present or future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing, with respect to any such Liability.

 

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In addition, nothing contained in Section 5.1(a) shall release OPC from honoring its obligations in effect immediately prior to the Distribution Date to indemnify any director, officer or employee of a member of the CRC Group who was a director, officer or employee of a member of the OPC Group on or prior to the Distribution Date, to the extent such director, officer or employee becomes a named defendant in any Action covered by such indemnity obligations; it being understood that, if the underlying obligation giving rise to such Action is a CRC Liability, subject to Schedule 6.1(c) , CRC shall indemnify OPC for such Liability (including OPC’s costs to indemnify the director, officer or employee) in accordance with the provisions set forth in this Article V.

 

(d)                                  CRC covenants that it will not make, and will not permit any member of the CRC Group to make, any claim or demand, or commence any Action asserting any claim or demand, including any claim of contribution or any indemnification, against OPC or any member of the OPC Group, or any other Person released pursuant to Section 5.1(a), with respect to any Liabilities released pursuant to Section 5.1(a).  OPC covenants that it will not make, and will not permit any member of the OPC Group to make, any claim or demand, or commence any Action asserting any claim or demand, including any claim of contribution or any indemnification, against CRC or any member of the CRC Group, or any other Person released pursuant to Section 5.1(b), with respect to any Liabilities released pursuant to Section 5.1(b).

 

(e)                                   It is the intent of each of OPC and CRC, by virtue of the provisions of this Section 5.1, to provide for a full and complete release and discharge of all Liabilities existing or arising from all acts and events occurring or failing to occur or alleged to have occurred or to have failed to occur and all conditions existing or alleged to have existed on or before the Distribution Date, between or among CRC or any member of the CRC Group, on the one hand, and OPC or any member of the OPC Group, on the other hand (including any contractual agreements or arrangements existing or alleged to exist between or among any such members on or before the Distribution Date, including any representations or warranties made or alleged to have been made on or before the Distribution Date, by any member of the CRC Group or the OPC Group), except as expressly set forth in Section 5.1(c).  At any time, at the request of any other party to this Agreement, each party shall cause each member of its respective Group to execute and deliver releases reflecting the provisions hereof.

 

(f)                                    Any breach of the provisions of this Section 5.1 by either OPC or CRC shall entitle the other party to recover reasonable fees and expenses of counsel in connection with such breach or any action resulting from such breach.

 

5.2                                Indemnification by CRC .  Subject to Section 5.4 and Schedule 6.1(c) , CRC shall indemnify, defend and hold harmless OPC, each member of the OPC Group and each of their respective past, present and future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing (collectively, the “ OPC Indemnitees ”), from and against any and all Liabilities of the OPC Indemnitees arising out of or resulting from (without duplication):

 

(a)                                  any OPC Third Party Claim to the extent arising out of or resulting from any of the following items (without duplication):

 

(i)                                      the failure of CRC or any other member of the CRC Group or any other Person to pay, perform or otherwise promptly discharge any CRC Liabilities or CRC Contracts in accordance with its respective terms, whether prior to or after the Distribution Date;

 

(ii)                                   the CRC Business, any CRC Liabilities or any CRC Contracts;

 

(iii)                                any representation or other warranty (including any warranty of title) from or made by the OPC Group contained in any deed, agreement or other document constituting or relating to the CRC Assets or the CRC Business, including any conveyancing instrument whereby any of the CRC assets were conveyed, assigned or transferred to a member of the CRC Group (whether in connection with the Separation or a transaction not related to the Separation);

 

(iv)                               the Assumed Actions;

 

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(v)                                  any Corporate Action or Action relating to the CRC Business from which CRC is unable to cause an OPC Group party to be removed pursuant to Section 5.6(d), but only to the extent relating to the CRC Business;

 

(vi)                               any use by any member of the CRC Group or Person that becomes an Affiliate of a member of the CRC Group after the Distribution Date of the OPC Names and Marks;

 

(vii)                            any guarantee, indemnification obligation, letter of credit reimbursement obligations, surety, bond or other credit support agreement, arrangement, commitment or understanding for the benefit of CRC or its Subsidiaries by OPC or any of its Subsidiaries (other than CRC or its Subsidiaries) that survives following the Distribution Date; and

 

(viii)                         any untrue statement or alleged untrue statement of a material fact or omission or alleged omission to state a material fact required to be stated therein or necessary to make the statements therein not misleading, with respect to all information contained in any of the Form 10 (including in any amendments or supplements thereto), the Information Statement (as amended or supplemented if CRC will have furnished any amendments or supplements thereto) or any offering memorandum or other marketing materials prepared in connection with the CRC Financing Arrangements or otherwise, other than any such statement or omission in the Form 10, Information Statement or offering memorandum or other marketing materials based on information furnished by OPC solely in respect of the OPC Group (it being understood that, with respect to the Form 10 and the Information Statement, the only such information furnished by OPC is the information set forth in the section of the Form 10 titled “The Spin-Off—Reasons for the Spin-Off”); and

 

(b)                                  any breach by CRC or any member of the CRC Group of this Agreement or any of the other Ancillary Agreements.

 

5.3                                Indemnification by OPC .  Subject to Section 5.4, OPC shall indemnify, defend and hold harmless CRC, each member of the CRC Group and each of their respective past, present and future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing (collectively, the “ CRC Indemnitees ”), from and against any and all Liabilities of the CRC Indemnitees arising out of or resulting from (without duplication):

 

(a)                                  any CRC Third Party Claim to the extent arising out of or resulting from any of the following items (without duplication):

 

(i)                                      the failure of OPC or any other member of the OPC Group or any other Person to pay, perform or otherwise promptly discharge any OPC Liabilities, whether prior to or after the Distribution Date;

 

(ii)                                   the OPC Business, any OPC Liabilities or any OPC Contracts;

 

(iii)                                any representation or other warranty (including any warranty of title) from or made by the CRC Group contained in any deed, agreement or other document constituting or relating to the OPC Assets or the OPC Business, including any conveyancing instrument whereby any of the OPC assets were conveyed, assigned or transferred to a member of the OPC Group (whether in connection with the Separation or a transaction not related to the Separation);

 

(iv)                               the Actions listed on Schedule 5.3(a)(iv) ;

 

(v)                                  any Corporate Action or Action relating to the OPC Business from which OPC is unable to cause a CRC Group party to be removed pursuant to Section 5.6(d) (but only to the extent relating to the OPC Business); and

 

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(vi)                               any untrue statement or alleged untrue statement of a material fact or omission or alleged omission to state a material fact required to be stated therein or necessary to make the statements therein not misleading, with respect to all information contained in any of the Form 10 (including in any amendments or supplements thereto), the Information Statement (as amended or supplemented if CRC will have furnished any amendments or supplements thereto) or any offering memorandum or other marketing materials prepared in connection with the CRC Financing Arrangements or otherwise, only to the extent based on information furnished by OPC solely in respect of the OPC Group (it being understood that, with respect to the Form 10 and the Information Statement, the only such information furnished by OPC is the information set forth in the section of the Form 10 titled “The Spin-Off—Reasons for the Spin-Off”); and

 

(b)                                  any breach by OPC or any member of the OPC Group of this Agreement or any of the Ancillary Agreements.

 

5.4                                Indemnification Obligations Net of Insurance Proceeds and Other Amounts .

 

(a)                                  The parties intend that any Liability subject to indemnification or reimbursement pursuant to this Article V or Article VI will be net of Insurance Proceeds that actually reduce the amount of the Liability.  Accordingly, the amount which any party (an “ Indemnifying Party ”) is required to pay to any Person entitled to indemnification hereunder (an “ Indemnitee ”) will be reduced by any Insurance Proceeds theretofore actually recovered by or on behalf of the Indemnitee in respect of the related Liability.  If an Indemnitee receives a payment (an “ Indemnity Payment ”) required by this Agreement from an Indemnifying Party in respect of any Liability and subsequently receives Insurance Proceeds, then the Indemnitee will pay to the Indemnifying Party an amount equal to the excess of the Indemnity Payment received over the amount of the Indemnity Payment that would have been due if the Insurance Proceeds had been received, realized or recovered before the Indemnity Payment was made.

 

(b)                                  An insurer who would otherwise be obligated to pay any claim shall not be relieved of the responsibility with respect thereto or, solely by virtue of the indemnification provisions hereof, have any subrogation rights with respect thereto, it being expressly understood and agreed that no insurer or any other Third Party shall be entitled to a “windfall” ( i.e. , a benefit they would not be entitled to receive in the absence of the indemnification provisions) by virtue of the indemnification provisions hereof.

 

(c)                                   The parties intend that any indemnification or reimbursement payment in respect of a Liability pursuant to this Article V or Article VI shall be (i) reduced to take into account the amount of any Tax Benefit actually realized by the indemnified or reimbursed Person in respect of such Liability by the end of the taxable year in which the indemnification or reimbursement payment is made and (ii) increased as necessary to ensure that, after all required Taxes on the indemnification or reimbursement payment are paid (including Taxes applicable to any increases in the indemnity payment under this Section 5.4(c)), the indemnified or reimbursed Person receives the amount it would have received if the indemnity payment was not taxable.  For purposes of this Section 5.4(c), the amount of any Tax Benefit and any Income Taxes shall be calculated on the basis that the indemnified or reimbursed Person is subject to the highest marginal regular statutory income Tax rate, has sufficient taxable income to permit the realization or receipt of any relevant Tax Benefit at the earliest possible time and is not subject to the alternative minimum tax.

 

(d)                                  Each of OPC and CRC shall, and shall cause its Subsidiaries to, when appropriate, use commercially reasonable efforts to obtain waivers of subrogation for each of the insurance policies identified on Schedule 6.1(c) .  Each of OPC and CRC hereby waives, for itself and each member of its Group, its rights to recover against the other party in subrogation or as subrogee for a third Person.

 

(e)                                   For all claims as to which indemnification is provided under Section 5.2 or Section 5.3 other than Third-Party Claims (as to which Section 5.5 shall apply), the reasonable fees and expenses of counsel to the Indemnitee for the enforcement of the indemnity obligations shall be borne by the Indemnifying Party.

 

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5.5                                Procedures for Indemnification of Third-Party Claims .

 

(a)                                  If an Indemnitee shall receive written notice of a Third Party Claim with respect to which an Indemnifying Party may be obligated to provide indemnification to such Indemnitee pursuant to Section 5.2 or 5.3, or any other Section of this Agreement or any other Ancillary Agreement, such Indemnitee shall give such Indemnifying Party written notice thereof within fourteen (14) days of such written notice.  Any such notice shall describe the Third-Party Claim in reasonable detail and include copies of all notices and documents (including court papers) received by the Indemnitee relating to the Third-Party Claim.  Notwithstanding the foregoing, the failure of an Indemnitee to provide notice in accordance with this Section 5.5(a) shall not relieve an Indemnifying Party of its indemnification obligations under this Agreement, except to the extent to which the Indemnifying Party shall demonstrate that it was materially prejudiced by the Indemnitee’s failure to provide notice in accordance with this Section 5.5(a).

 

(b)                                  An Indemnifying Party may elect to defend (and, unless the Indemnifying Party has specified any reservations or exceptions, to seek to settle or compromise), at such Indemnifying Party’s own expense and by such Indemnifying Party’s own counsel, any Third-Party Claim.  Within thirty (30) days after the receipt of notice from an Indemnitee in accordance with Section 5.5(a) (or sooner, if the nature of such Third-Party Claim so requires), the Indemnifying Party shall notify the Indemnitee of its election whether the Indemnifying Party will assume responsibility for defending such Third-Party Claim, which election shall specify any reservations or exceptions.  After notice from an Indemnifying Party to an Indemnitee of its election to assume the defense of a Third-Party Claim, such Indemnitee shall have the right to employ separate counsel and to participate in (but not control) the defense, compromise, or settlement thereof, but the fees and expenses of such counsel shall be the expense of such Indemnitee except as set forth in the next sentence.

 

(c)                                   If the Indemnifying Party has elected to assume the defense of the Third-Party Claim but has specified, and continues to assert, any reservations or exceptions in such notice, then, in any such case, the reasonable fees and expenses of one separate counsel for all Indemnitees shall be the expense of such Indemnitees, but shall be reimbursed by the Indemnifying Party.

 

If the Indemnifying Party has elected to assume the defense of the Third Party Claim but has specified, and continues to assert, any reservations or exceptions in such notice, then the Indemnifying Party must obtain the consent of the Indemnitee prior to any settlement or compromise.

 

(d)                                  Notwithstanding an election by an Indemnifying Party to defend a Third-Party Claim pursuant to Section 5.5(b), the Indemnitee may, upon notice to the Indemnifying Party, elect to take over the defense of such Third-Party Claim if (i) in its exercise of reasonable business judgment, the Indemnitee determines that the Indemnifying Party is not defending such Third-Party Claim competently or in good faith, (ii) the Credit Rating of the Indemnifying Party is or falls below the Minimum Credit Rating as determined by at least two Rating Agencies, (iii) the Indemnitee determines in its exercise of reasonable business judgment that there exists a compelling business reason for such Indemnitee to defend such Third-Party Claim (other than as contemplated by the foregoing clause (i)), (iv) the Indemnifying Party makes a general assignment for the benefit of creditors, has filed against it or files a petition in bankruptcy or insolvency or is declared bankrupt or insolvent or declares that it is bankrupt or insolvent, or (v) there occurs a change of control of the Indemnifying Party since the Distribution Date.

 

(e)                                   If an Indemnifying Party elects not to assume responsibility for defending a Third-Party Claim, or fails to notify an Indemnitee of its election as provided in Section 5.5(b), or if an Indemnitee takes over the defense of a Third-Party Claim as provided in Section 5.5(d), the Indemnifying Party shall bear all of the Indemnitee’s reasonable costs and expenses incurred in defending such Third-Party Claim.

 

(f)                                    If, pursuant to Section 5.5(d) or for any other reason, the Indemnifying Party is not defending a Third-Party Claim for which indemnification is provided under this Agreement, the Indemnifying Party shall have the right, at its own expense, to monitor reasonably the defense of such Third-Party Claim; provided , that such monitoring activity shall not interfere in any material respect with the conduct of such defense.

 

(g)                                   If an Indemnifying Party has failed to assume the defense of the Third-Party Claim in accordance with the terms of this Agreement or an Indemnitee takes over the defense of a Third-Party Claim as

 

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provided in Section 5.5(d)(i), an Indemnitee may settle or compromise the Third-Party Claim without the consent of the Indemnifying Party.  If an Indemnitee takes over the defense of a Third-Party Claim as provided in Section 5.5(d)(ii)-(v), such Indemnitee may not settle or compromise any Third-Party Claim without the consent of the Indemnifying Party, such consent not to be unreasonably withheld or delayed.

 

(h)                                  In the case of a Third-Party Claim, no Indemnifying Party shall consent to entry of any judgment or enter into any settlement of the Third-Party Claim without the consent of the Indemnitee if the effect thereof is to permit any injunction, declaratory judgment, regulatory penalty or other non-monetary relief to be entered, directly or indirectly against any Indemnitee.

 

(i)                                      CRC or OPC, as applicable, shall prepare and circulate a legal hold order (“ LHO ”) covering relevant categories of documents as promptly as practical following receipt of any notice pursuant to Section 5.5(a) and shall promptly notify the other party after such LHO has been circulated.  OPC or CRC, as applicable, shall prepare and circulate a LHO covering documents in the possession, custody or control of the members of its Group with respect to any Action so notified to the other party.

 

(j)                                     The provisions of this Section 5.5 (other than this Section 5.5(j)) and the provisions of Section 5.6 shall not apply to Taxes (Taxes being governed by the Tax Sharing Agreement).

 

(k)                                  All Assumed Actions have been tendered by OPC to CRC and are deemed to be formally accepted by CRC upon the execution of this Agreement.

 

(l)                                      An Indemnifying Party shall provide the Indemnitee with a monthly written report identifying any Third Party Claims which such Indemnifying Party has elected to defend pursuant to Section 5.5(b) or, in the case of CRC, which are identified on Schedule 5.5(l) .  In addition, the Indemnifying Party shall establish a procedure reasonably acceptable to the Indemnitee to automatically send electronic notice from the Indemnifying Party to the Indemnitee through the litigation management system or any successor system when any such Third Party Claim is closed, regardless of whether such Third Party Claim was decided by settlement, verdict, dismissal or was otherwise disposed of.

 

5.6                                Additional Matters .

 

(a)                                  Indemnification payments in respect of any Liabilities for which an Indemnitee is entitled to indemnification under this Article V shall be paid by the Indemnifying Party to the Indemnitee as such Liabilities are incurred upon demand by the Indemnitee, including reasonably satisfactory documentation setting forth the basis for the amount of such indemnification payment, including documentation with respect to calculations made and consideration of any Insurance Proceeds that actually reduce the amount of such Liabilities; provided, however, that if requested by the Indemnitee, in the case of any Third Party Claims for which the Indemnifying Party is liable under the terms of this Agreement, the Indemnifying Party will pay the amounts due to such Third Party as a result of any settlement of such Third Party Claim in accordance with Section 5.5 directly to the Third Party as opposed to reimbursing the Indemnitee for the amounts paid in any such settlement.  THE INDEMNITY AGREEMENTS CONTAINED IN THIS ARTICLE V SHALL REMAIN OPERATIVE AND IN FULL FORCE AND EFFECT, REGARDLESS OF (I) ANY INVESTIGATION MADE BY OR ON BEHALF OF ANY INDEMNITEE AND (II) THE KNOWLEDGE BY THE INDEMNITEE OF LIABILITIES FOR WHICH IT MIGHT BE ENTITLED TO INDEMNIFICATION HEREUNDER.

 

(b)                                  Any claim on account of a Liability that does not result from a Third-Party Claim shall be asserted by written notice given by the Indemnitee to the related Indemnifying Party.  Such Indemnifying Party shall have a period of thirty (30) days after the receipt of such notice within which to respond thereto.  If such Indemnifying Party does not respond within such thirty (30)-day period, such Indemnifying Party shall be deemed to have refused to accept responsibility to make payment.  If such Indemnifying Party does not respond within such thirty (30)-day period or rejects such claim in whole or in part, such Indemnitee shall be free to pursue such remedies as may be available to such party as contemplated by this Agreement and the other Ancillary Agreements.

 

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(c)                                   In the event of payment by or on behalf of any Indemnifying Party to any Indemnitee in connection with any Third-Party Claim, such Indemnifying Party shall be subrogated to and shall stand in the place of such Indemnitee as to any events or circumstances in respect of which such Indemnitee may have any right, defense or claim relating to such Third-Party Claim against any claimant or plaintiff asserting such Third-Party Claim or against any other Person.  Such Indemnitee shall cooperate with such Indemnifying Party in a reasonable manner, and at the cost and expense of such Indemnifying Party, in prosecuting any subrogated right, defense or claim.

 

(d)                                  In the event of an Action for which indemnification is sought pursuant to Section 5.2 or 5.3 and in which the Indemnifying Party is not a named defendant, if either the Indemnitee or Indemnifying Party shall so request, the parties shall use commercially reasonable efforts to substitute the Indemnifying Party for the named defendant.

 

(e)                                   If CRC or OPC shall establish a risk accrual in an amount of at least $25 million with respect to any Third-Party Claim for which such party has indemnified the other party pursuant to Section 5.2 or 5.3, as applicable, it shall notify the other party of the existence and amount of such risk accrual ( i.e. , when the accrual is recorded in the financial statements as an accrual for a potential liability), subject to the parties entering into an appropriate agreement with respect to the confidentiality and/or Privilege thereof.

 

5.7                                Remedies Cumulative .  The remedies provided in this Article V shall be cumulative and shall not preclude assertion by any Indemnitee of any other rights or the seeking of any and all other remedies against any Indemnifying Party expressly provided in this Agreement or any Ancillary Agreement; provided , however , if a party has recovered any Losses from the other party pursuant to any provision of this Agreement or any Ancillary Agreement or otherwise, it shall not be entitled to recover the same Losses pursuant to any other provision of this Agreement or any Ancillary Agreement.

 

5.8                                Survival of Indemnities .  The rights and obligations of each of OPC and CRC and their respective Indemnitees under this Article V shall survive the sale or other transfer by any party of any Assets or businesses or the assignment by it of any Liabilities.

 

5.9                                Guarantees, Letters of Credit and other Obligations .  In furtherance of, and not in limitation of, the obligations set forth in Section 2.6 and Section 8.3 hereof:

 

(a)                                  On or prior to the Distribution Date or as soon as practicable thereafter, CRC shall (with the reasonable cooperation of the applicable member(s) of the OPC Group) use its commercially reasonable efforts to have any member(s) of the OPC Group removed as guarantor of or obligor for any CRC Liability, including in respect of those guarantees, letters of credit and other obligations set forth on Schedule 5.9(a) .

 

(b)                                  On or prior to the Distribution Date, to the extent required to obtain a release from a guarantee, letter of credit or other obligation of any member of the OPC Group, CRC shall execute a substitute document substantially in the form of any such existing guarantee or letter of credit, as applicable, or such other form as is agreed to by the relevant parties to such guarantee agreement, letter of credit or other obligation, provided that CRC shall not be required to make or agree to any representations, covenants or other terms or provisions in an existing guarantee, letter of credit or other obligation to the extent (i) CRC would not be reasonably able to comply therewith or (ii) CRC would reasonably be expected to be in breach thereof.

 

(c)                                   If the parties are unable to obtain, or to cause to be obtained, any such required removal as set forth in clauses (a) and (b) of this Section 5.9, (i) CRC shall indemnify, defend and hold harmless each of the OPC Indemnitees for any Liability arising from or relating to such guarantee, letter of credit or other obligation, as applicable, and shall, as agent or subcontractor for the applicable OPC Group guarantor or obligor, pay, perform and discharge fully all of the obligations or other Liabilities of such guarantor or obligor thereunder, and (ii) CRC shall not, and shall cause the other members of the CRC Group not to, agree to renew or extend the term of, increase any obligations under, or transfer to a third Person, any loan, guarantee, letter of credit, lease, contract or other obligation for which a member of the OPC Group is or may be liable unless all obligations of the members of the OPC Group with respect thereto are thereupon terminated by documentation satisfactory in form and substance to OPC in its sole and absolute discretion.

 

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5.10                         No Impact on Third Parties .  For the avoidance of doubt, except as expressly set forth in this Agreement, the indemnifications provided for in this Article V are made only for purposes of allocating responsibility for Liabilities between the OPC Group, on the one hand, and the CRC Group, on the other hand, and are not intended to, and shall not, affect any obligations to, or give rise to any rights of, any Third Parties.

 

5.11                         No Cross-Claims or Third-Party Claims .  Each of CRC and OPC agrees that it shall not, and shall not permit any of its respective Subsidiaries or controlled Affiliates to, in connection with any Third-Party Claim, assert as a counterclaim or third-party claim against any member of the OPC Group or CRC Group, respectively, any claim (whether sounding in contract, tort or otherwise) that arises out of or relates to this Agreement, any breach or alleged breach hereof, the transactions contemplated hereby (including all actions taken in furtherance of the transactions contemplated hereby on or prior to the date hereof), or the construction, interpretation, enforceability or validity hereof, which in each such case shall be asserted only as contemplated by Article IV.

 

5.12                         Severability .  If any indemnification provided for in this Article IV is determined by any arbitrator or arbitral tribunal with authority to make such determination under Article IV or by a Texas federal or state court to be invalid, void or unenforceable, the Liability shall be apportioned between the Indemnitee and the Indemnifying Party as determined in a separate proceeding in accordance with Article IV.

 

5.13                         Change of Control .  If any third Person or “group” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) acquires, including by way of merger, consolidation or other business combination, fifty percent (50%) or more of the assets or voting equity of CRC, CRC shall take all necessary action so that such third Person or group shall become a guarantor of the obligations of CRC under this Agreement and the Ancillary Agreements.

 

ARTICLE VI
INSURANCE MATTERS

 

6.1                                Insurance Matters .

 

(a)                                  OPC and CRC agree to cooperate in good faith to arrange insurance coverage for CRC to be effective no later than the Distribution Date.  In no event shall OPC, any other member of the OPC Group or any OPC Indemnitee have Liability or obligation whatsoever to any member of the CRC Group if any insurance policy or other contract or policy of insurance shall be terminated or otherwise cease to be in effect for any reason, shall be unavailable or inadequate to cover any Liability of any member of the CRC Group for any reason whatsoever or shall not be renewed or extended beyond the current expiration date.

 

(b)                                  From and after the Distribution Date, other than as provided in Section 6.1(c) or in Schedule 6.1(c) , neither CRC nor any member of the CRC Group shall have any rights to or under any of OPC’s or its Affiliates’ insurance policies.  At the Distribution Date, CRC shall have in effect all insurance programs required to comply with CRC’s contractual obligations and such other insurance policies as reasonably necessary, and, following the Distribution Date, CRC shall maintain such insurance programs and policies with insurers which comply with the minimum financial credit rating standards set by the major global insurance brokers.

 

(c)                                   From and after the Distribution Date, except with respect to the insurance matters identified on Schedule 6.1(c) , whose treatment shall be as set forth on such Schedule, with respect to any losses, damages and liabilities incurred by any member of the CRC Group prior to or in respect of the period prior to the Distribution Date, OPC will provide CRC with access to, and CRC may, upon 10 days’ prior written notice to OPC, make claims under OPC’s third-party insurance policies and captive insurance policies, to the extent they have been reinsured in place at the time of the Initial Distribution and OPC’s historical policies of insurance, but solely to the extent that such policies provided coverage for the CRC Group prior to the Distribution; provided , that such access to, and the right to make claims under such insurance policies, shall be subject to the terms and conditions of such insurance policies, including any limits on coverage or scope, any deductibles and other fees and expenses, and shall be subject to the following additional conditions:

 

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(i)                                      CRC shall provide OPC with a written report sixty (60) days prior to any such third-party insurance policy’s renewal date, as advised by OPC, identifying any claims made by CRC for which notice has previously been provided to insurers of OPC;

 

(ii)                                   CRC and its Affiliates shall indemnify, hold harmless and reimburse OPC and its Affiliates for any deductibles, self-insured retention, fees and expenses incurred by OPC or its Affiliates to the extent resulting from any such access to, or any claims made by CRC or any of its Affiliates under, any insurance provided pursuant to this Section 6.1(c), including any indemnity payments, settlements, judgments, legal fees and allocated claims expenses and claim handling fees, whether such claims are made by CRC, its employees or third Persons; and

 

(iii)                                CRC shall exclusively bear (and neither OPC nor its Affiliates shall have any obligation to repay or reimburse CRC or its Affiliates for) and shall be liable for all uninsured, uncovered, unavailable or uncollectible amounts of all such claims made by CRC or any of its Affiliates under the policies as provided for in this Section 6.1(c).

 

If an insurance policy aggregate is exhausted, or believed likely to be exhausted, due to noticed claims, the CRC Group, on the one hand, and the OPC Group, on the other hand, shall be responsible for their pro rata portion of the reinstatement premium, based upon the losses of such Group submitted to OPC’s insurance carrier(s) (including any submissions prior to the Distribution Date).  To the extent that the OPC Group or the CRC Group is allocated more than its pro rata portion of such premium due to the timing of losses submitted to OPC’s insurance carrier(s), the other party shall promptly pay the first party an amount so that each Group has been properly allocated its pro rata portion of the reinstatement premium.  OPC and CRC can mutually agree not to reinstate the policy aggregate and each Group then will bear all of its own future costs.

 

If any member of the OPC Group incurs any losses, damages or Liability prior to the Distribution Date under CRC’s third-party insurance policies, the same process pursuant to this Section 6.1(c) shall apply, substituting “OPC” for “CRC” and “CRC” for “OPC.”

 

(d)                                  All payments and reimbursements by CRC pursuant to this Section 6.1 will be made within fifteen (15) days after CRC’s receipt of an invoice therefor from OPC.  If OPC incurs costs to enforce CRC’s obligations herein, CRC agrees to indemnify OPC for such enforcement costs, including attorneys’ fees.

 

(e)                                   All payments and reimbursements by OPC pursuant to this Section 6.1 will be made within fifteen (15) days after OPC’s receipt of an invoice therefor from CRC.  If CRC incurs costs to enforce OPC’s obligations herein, OPC agrees to indemnify CRC for such enforcement costs, including attorneys’ fees.

 

(f)                                    OPC shall retain the exclusive right to control its insurance policies and programs, including the right to exhaust, settle, release, commute, buy-back or otherwise resolve disputes with respect to any of its insurance policies and programs and to amend, modify or waive any rights under any such insurance policies and programs, notwithstanding whether any such policies or programs apply to any CRC Liabilities and/or claims CRC has made or could make in the future, and no member of the CRC Group shall, without the prior written consent of OPC, erode, exhaust, settle, release, commute, buy-back or otherwise resolve disputes with OPC’s insurers with respect to any of OPC’s insurance policies and programs, or amend, modify or waive any rights under any such insurance policies and programs.  CRC shall cooperate with OPC and share such information at CRC’s cost as is reasonably necessary in order to permit OPC to manage and conduct its insurance matters as it deems appropriate.  Neither OPC nor any of its Affiliates shall have any obligation to secure extended reporting for any claims under any of OPC’s or its Affiliates’ liability policies for any acts or omissions by any member of the CRC Group incurred prior to the Distribution Date.

 

(g)                                   This Agreement shall not be considered as an attempted assignment of any policy of insurance or as a contract of insurance and shall not be construed to waive any right or remedy of any member of the OPC Group in respect of any insurance policy or any other contract or policy of insurance.

 

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(h)                                  CRC does hereby, for itself and each other member of the CRC Group, agree that no member of the OPC Group shall have any Liability whatsoever as a result of the insurance policies and practices of OPC and its Affiliates as in effect at any time, including as a result of the level or scope of any such insurance, the creditworthiness of any insurance carrier, the terms and conditions of any policy, or the adequacy or timeliness of any notice to any insurance carrier with respect to any claim or potential claim or otherwise.

 

(i)                                      The parties acknowledge that to the extent there are losses or premium adjustments under the parties’ tripartite insurance agreements, such losses or adjustments will be governed by such tripartite insurance agreements.

 

ARTICLE VII
EXCHANGE OF INFORMATION; CONFIDENTIALITY

 

7.1                                Agreement for Exchange of Information .  Subject to Section 7.7 and any other applicable confidentiality obligations, each of OPC and CRC, on behalf of its respective Group, agrees to provide, or cause to be provided, to the other Group, at any time before or after the Distribution Date, as soon as reasonably practicable after written request therefor, any Information in the possession or under the control of such respective Group which the requesting party reasonably needs (a) to comply with reporting, disclosure, filing or other requirements imposed on the requesting party (including under applicable securities or tax Laws) by a Governmental Authority having jurisdiction over the requesting party, (b) for use in any other judicial, regulatory, administrative, tax or other proceeding or in order to satisfy audit, accounting, claims, regulatory, litigation, tax or other similar requirements, in each case other than claims or allegations that one party to this Agreement has against the other, or (c) subject to the foregoing clause (b), to comply with its obligations under this Agreement or any other Ancillary Agreement; provided, however , that, in the event that any party determines that any such provision of Information could be commercially detrimental, violate any Law or agreement, or waive any privilege otherwise available under applicable Law, including the attorney-client privilege, work product, joint defense, common interest or other applicable privilege (each, a “ Privilege ”) the parties shall take all reasonable measures to permit the compliance with such obligations in a manner that avoids any such harm or consequence.

 

7.2                                Ownership of Information .  Any Information owned by one Group that is provided to a requesting party pursuant to Section 7.1 or Section 7.6 shall be deemed to remain the property of the providing party.  Unless specifically set forth herein, nothing contained in this Agreement shall be construed as granting or conferring rights of license or otherwise in any such Information.

 

7.3                                Compensation for Providing Information .  The party requesting Information agrees to reimburse the other party for the reasonable costs, if any, of creating, gathering and copying such Information, to the extent that such costs are incurred for the benefit of the requesting party.  Except as may be otherwise specifically provided elsewhere in this Agreement or in any other agreement between the parties, such costs shall be computed in accordance with the providing party’s standard methodology and procedures.

 

7.4                                Record Retention .  To facilitate the possible exchange of Information pursuant to this Article VII and other provisions of this Agreement after the Distribution Date, the parties agree to use their commercially reasonable efforts to retain all Information in their respective possession or control on the Distribution Date in accordance with the policies of OPC as in effect on the Distribution Date or such other policies as may be adopted by OPC after the Distribution Date ( provided , in the case of CRC, that OPC notifies CRC of any such change).  No party will destroy, or permit any of its Subsidiaries to destroy, any Information which the other party may have the right to obtain pursuant to this Agreement prior to the end of the retention period set forth in such policies without first notifying the other party of the proposed destruction and giving the other party the opportunity to take possession of such information prior to such destruction ; provided, however , that in the case of any Information relating to Taxes, employee benefits or Environmental Liabilities, such retention period shall be extended to the expiration of the applicable statute of limitations (giving effect to any extensions thereof).  Notwithstanding the foregoing, Section [ · ] of the Tax Sharing Agreement shall govern the retention of Tax Records (as defined in the Tax Sharing Agreement).

 

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7.5                                Other Agreements Providing for Exchange of Information .  The rights and obligations granted under this Article VII are subject to any specific limitations, qualifications or additional provisions on the sharing, exchange, retention or confidential treatment of Information set forth in this Agreement or any Ancillary Agreement.

 

7.6                                Production of Witnesses; Records; Cooperation .

 

(a)                                  After the Distribution Date, except in the case of an adversarial Action by one party against another party, each party hereto shall use its commercially reasonable efforts to make available to the other party, upon written request, the former, current and future directors, officers, employees, managers, other personnel and agents of the members of its respective Group as witnesses and any Records or other documents within its control or which it otherwise has the ability to make available, to the extent that any such person (giving consideration to business demands of such directors, officers, employees, managers, other personnel and agents) or Records or other documents may reasonably be required in connection with any Action in which the requesting party may from time to time be involved, regardless of whether such Action is a matter with respect to which indemnification may be sought hereunder.  The requesting party shall bear all costs and expenses in connection therewith.

 

(b)                                  If an Indemnifying Party chooses to defend or to seek to compromise or settle any Third-Party Claim, the other party shall make available to such Indemnifying Party, upon written request, the former, current and future directors, officers, employees, managers, other personnel and agents of the members of its respective Group as witnesses and any Records (unless the provision of any Record would result in the waiver of any applicable Privilege) or other documents within its control or which it otherwise has the ability to make available, to the extent that any such person (giving consideration to business demands of such directors, officers, employees, managers, other personnel and agents) or Records or other documents may reasonably be required in connection with such defense, settlement or compromise, or such prosecution, evaluation or pursuit, as the case may be, and shall otherwise cooperate in such defense, settlement or compromise, or such prosecution, evaluation or pursuit, as the case may be.

 

(c)                                   Without limiting the foregoing, the parties shall cooperate and consult to the extent reasonably necessary with respect to any Actions.

 

(d)                                  Without limiting any provision of this Section 7.6, each of the parties agrees to cooperate, and to cause each member of its respective Group to cooperate, with each other in the defense of any infringement or similar claim with respect any Intellectual Property and shall not claim to acknowledge, or permit any member of its respective Group to claim to acknowledge, the validity or infringing use of any Intellectual Property of a third Person in a manner that would hamper or undermine the defense of such infringement or similar claim.

 

(e)                                   The obligation of the parties to provide witnesses pursuant to this Section 7.6 is intended to be interpreted in a manner so as to facilitate cooperation and shall include the obligation to provide as witnesses inventors and other officers without regard to whether the witness or the employer of the witness could assert a possible business conflict (subject to the exception set forth in the first sentence of Section 7.6(a)).

 

(f)                                    In connection with any matter contemplated by this Section 7.6, the parties will enter into a mutually acceptable joint defense agreement so as to maintain to the extent practicable any applicable Privilege of any member of any Group.

 

7.7                                Confidentiality .

 

(a)                                  Subject to Section 7.8, until the five (5)-year anniversary of the Distribution Date, CRC, on behalf of itself and each member of the CRC Group, agrees to hold, and to cause its Representatives to hold, in strict confidence, with at least the same degree of care that applies to OPC’s confidential and proprietary information pursuant to policies in effect as of the Distribution Date, all Information concerning the OPC Group that is either in its possession (including Information in its possession prior to the Distribution Date) or furnished by the OPC Group or its Representatives at any time pursuant to this Agreement, any Ancillary Agreement or otherwise, except, in each case, to the extent that such Information has been (i) in the public domain through no fault of CRC or

 

37



 

any member of the CRC Group or any of their respective Representatives, (ii) later lawfully acquired from other sources by CRC (or any member of the CRC Group) which sources are not themselves bound by a confidentiality obligation, or (iii) independently generated without reference to any proprietary or confidential Information of OPC.

 

(b)                                  CRC, on behalf of itself and each member of the CRC Group, agrees not to release or disclose, or permit to be released or disclosed, any such Information to any other Person, except its Representatives who need to know such Information (who shall be advised of their obligations hereunder with respect to such Information), except in compliance with Section 7.8. Without limiting the foregoing, when any Information is no longer needed for the purposes contemplated by this Agreement or any Ancillary Agreement, CRC will promptly after request of the other party either return to the other party all Information in a tangible form (including all copies thereof and all notes, extracts or summaries based thereon) or certify to OPC that it has destroyed such Information (and such copies thereof and such notes, extracts or summaries based thereon); provided, however, that a party shall not be required to destroy or return any such Information to the extent that (i) CRC is required to retain the Information in order to comply with any applicable Law, (ii) the Information has been backed up electronically pursuant to CRC’s standard document retention policies and will be managed and ultimately destroyed consistent with such policies or (iii) it is kept in CRC’s legal files for purposes of resolving any dispute that may arise under this Agreement or any Ancillary Agreement.

 

7.8                                Protective Arrangements .  If any party or any member of its Group either determines on the advice of its counsel that it is required to disclose any Information pursuant to applicable Law or receives any demand under lawful process or from any Governmental Authority to disclose or provide Information of any other party (or any member of any other party’s Group) that is subject to the confidentiality provisions hereof, such party shall use commercially reasonable efforts to notify the other party prior to disclosing or providing such Information and shall cooperate at the expense of the requesting party in seeking any reasonable protective arrangements requested by such other party.  Subject to the foregoing, the Person that received such request may thereafter disclose or provide Information to the extent required by such Law (as so advised by counsel) or by lawful process or such Governmental Authority.

 

ARTICLE VIII
FURTHER ASSURANCES AND ADDITIONAL COVENANTS

 

8.1                                Further Assurances .

 

(a)                                  In addition to the actions specifically provided for elsewhere in this Agreement, each of the parties shall use its commercially reasonable efforts, prior to, on and after the Distribution Date, to take, or cause to be taken, all actions, and to do, or cause to be done, all things, reasonably necessary, proper or advisable under applicable Laws, regulations and agreements, to consummate and make effective the transactions contemplated by this Agreement and the Ancillary Agreements.

 

(b)                                  Without limiting the foregoing, prior to, on and after the Distribution Date, each party hereto shall cooperate with the other parties, and without any further consideration, but at the expense of the requesting party, to execute and deliver, or use its commercially reasonable efforts to cause to be executed and delivered, all instruments, including instruments of conveyance, assignment and transfer, and to make all filings with, and to obtain all consents, approvals or authorizations of, any Governmental Authority or any other Person under any permit, license, agreement, indenture or other instrument (including any third-party consents or Governmental Approvals), and to take all such other actions as such party may reasonably be requested to take by any other party hereto from time to time, consistent with the terms of this Agreement and the Ancillary Agreements, in order to effectuate the provisions and purposes of this Agreement and the Ancillary Agreements and the transfers of the CRC Assets and the assignment and assumption of the CRC Liabilities and the other transactions contemplated hereby and thereby.

 

(c)                                   On or prior to the Distribution Date, OPC and CRC in their respective capacities as direct and indirect stockholders of their respective Subsidiaries, shall each ratify any actions which are reasonably necessary or desirable to be taken by any Subsidiary of OPC, as the case may be, to effectuate the transactions contemplated by this Agreement and the Ancillary Agreements.

 

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(d)                                  OPC and CRC, and each of the members of their respective Groups, waive (and agree not to assert against any of the others) any claim or demand that any of them may have against any of the others for any Liabilities or other claims relating to or arising out of: (i) the failure of CRC or any member of the CRC Group, on the one hand, or of OPC or any member of the OPC Group, on the other hand, to provide any notification or disclosure required under any state Environmental Law in connection with the Separation or the other transactions contemplated by this Agreement or the Ancillary Agreements, including the transfer by any member of any Group to any member of the other Group of ownership or operational control of any Assets not previously owned or operated by such transferee; or (ii) any inadequate, incorrect or incomplete notification or disclosure under any such state Environmental Law by the applicable transferor.  To the extent any Liability to any Governmental Authority or any third Person arises out of any action or inaction described in clause (i) or (ii) above, the transferee of the applicable Asset hereby assumes and agrees to pay any such Liability.

 

(e)                                   Prior to the first anniversary of the Distribution Date, if one or more of the parties identifies any commercial or other service that is needed to assure a smooth and orderly transition of the businesses in connection with the consummation of the transactions contemplated hereby, and that is not otherwise governed by the provisions of this Agreement or any Ancillary Agreement, the parties will cooperate in determining whether there is a mutually acceptable basis on which the other party will provide such service; provided , that if such service is to extend beyond the first anniversary of the Distribution Date, the terms and conditions upon which the services are to be provided beyond the first anniversary of the Distribution Date shall be market and arm’s-length terms and conditions; and further provided , that in no event will such service extend beyond the second anniversary of the Distribution Date.

 

8.2                                Performance .  OPC will cause to be performed, and hereby guarantees the performance of, all actions, agreements and obligations set forth in this Agreement or in any Ancillary Agreement to be performed by any member of the OPC Group.  CRC will cause to be performed, and hereby guarantees the performance of, all actions, agreements and obligations set forth in this Agreement or in any Ancillary Agreement to be performed by any member of the CRC Group.  Each party (including its permitted successors and assigns) further agrees that it will (a) give timely notice of the terms, conditions and continuing obligations contained in this Section 8.2 to all of the other members of its Group, and (b) cause all of the other members of its Group not to take any action or fail to take any such action inconsistent with such party’s obligations under this Agreement, any Ancillary Agreement or the transactions contemplated hereby or thereby.

 

8.3                                OPC Guarantees .  CRC acknowledges that in the course of conduct of the CRC Business, OPC and members of the OPC Group may have entered into various arrangements in which guarantees, bonds, letters of credit or similar arrangements were issued or arranged by OPC or members of the OPC Group to support or facilitate the CRC Business.  Any such arrangements entered into by OPC and its Affiliates are, to the extent related to the CRC Business, hereinafter referred to as the “ OPC Guarantees .”  Except as otherwise agreed by OPC and CRC, CRC agrees that it will use its commercially reasonable efforts to obtain or provide replacement guarantees, bonds, letters of credit or similar arrangements, which will be in effect at the Distribution Date, and obtain the release of OPC and members of the OPC Group from any OPC Guarantees in accordance with Section 5.9.

 

8.4                                Third-Party Agreements .  CRC agrees that it will use its commercially reasonable efforts to obtain or provide replacement agreements with third parties for agreements between such third parties and OPC or any member of the OPC Group that are CRC Contracts and cannot be assigned to CRC.

 

8.5                                OPC Names and Marks .

 

(a)                                  CRC agrees that, after the Distribution Date, no member of the CRC Group nor any Person that becomes an Affiliate of a member of the CRC Group after the Distribution Date, shall have any rights in and to the OPC Names and Marks, and (except as expressly set forth in this Section 8.5) will not, at any time after the Distribution Date, market, promote, advertise or offer for sale any products, goods or services utilizing any of the OPC Names and Marks or otherwise hold itself out as having any affiliation with the OPC Group.  CRC agrees that (i) if the CRC Assets include any signage or facility bearing the OPC Names and Marks in a manner that is visible to consumers or the general public, CRC shall remove and replace the OPC Names and Marks on such signage or facility within thirty (30) days after the Distribution Date, (ii) if the CRC Assets include any vehicles that bear any of the OPC Names and Marks and are visible to consumers or the general public, CRC shall remove and

 

39



 

replace such OPC Names and Marks within thirty (30) days after the Distribution Date, and (iii) if any of the other CRC Assets, including any promotional materials or printed forms, bear any of the OPC Names and Marks, CRC shall, prior to distributing, selling or otherwise making use of such CRC Assets for consumers or the general public, remove, delete or render illegible the OPC Names and Marks as they may appear on such CRC Assets.  Notwithstanding the foregoing, for a period of ninety (90) days after the Distribution Date, CRC may distribute and display marketing, promotional and advertising materials including business cards, stationery, packaging materials, displays, signs, promotional materials and other similar materials that include one or more of the OPC Names and Marks (collectively, “ Supplies ”), provided such Supplies (i) were included within the inventory of CRC Assets as of the Distribution Date, (ii) are used solely in connection with the promotion, marketing, advertising and sale of the CRC Business’ products of the type sold, and in a manner consistent with that used, prior to the Distribution Date and (iii) clearly indicate that (A) no member of the CRC Group is affiliated with any member of the OPC Group and (B) the inclusion of the OPC Names and Marks in the Supplies shall not be construed as an endorsement of any of the CRC Business’ products by any member of the OPC Group.

 

(b)                                  CRC agrees to cause each member of the CRC Group whose name includes any of the OPC Names and Marks, promptly following the Distribution Date, and in any event within ten (10) business days after the Distribution Date, change its name such that its name does not include any of the OPC Names and Marks.

 

(c)                                   Notwithstanding anything to the contrary provided in this Section 8.5, CRC may use the OPC Names and Marks (i) on internal office supplies or signage not visible to consumers or the general public, provided that such supplies or signage are replaced promptly in the ordinary course of business, (ii) in a neutral, non-trademark manner to describe the historical relationship of the CRC Group and the OPC Group, or (iii) to the extent required by Law in legal or business documents already in existence on the Distribution Date.

 

8.6                                Conflicts with and between Ancillary Agreements .  Notwithstanding anything to the contrary in this Agreement or any Ancillary Agreement:

 

(a)                                  in the case of any conflict between this Agreement or any Ancillary Agreement (other than the Tax Sharing Agreement) and the Tax Sharing Agreement in relation to any matters addressed by the Tax Sharing Agreement, the Tax Sharing Agreement shall prevail;

 

(b)                                  except as set forth in Section 8.6(a), in the case of any conflict between this Agreement or any Ancillary Agreement (other than the Intellectual Property License Agreement) and the Intellectual Property License Agreement in relation to any matters addressed by the Intellectual Property License Agreement, the Intellectual Property License Agreement shall prevail;

 

(c)                                   except as set forth in Section 8.6(a) or Section 8.6(b), in the case of any conflict between this Agreement or any Ancillary Agreement (other than the Employee Matters Agreement) and the Employee Matters Agreement in relation to any matters addressed by the Employee Matters Agreement, the Employee Matters Agreement shall prevail; and

 

(d)                                  except as set forth in Section 8.6(a), Section 8.6(b) or Section 8.6(c), in the case of any conflict between this Agreement or any Ancillary Agreement in relation to any matters addressed by this Agreement, this Agreement shall prevail.

 

8.7                                Attorney Client Privilege .  CRC agrees that, in the event of any Dispute or other litigation, dispute, controversy or claim between OPC or a member of the OPC Group, on the one hand, and CRC or a member of the CRC Group, on the other hand, CRC will not, and will cause the members of its Group not to, seek any waiver of any applicable Privilege with respect to any oral or written communications relating to advice given prior to the Distribution Date by counsel to OPC or any Person that was a Subsidiary of OPC prior to the Distribution Date, regardless of any argument that such advice may have affected the interests of both parties.  Moreover, CRC will, and will cause the members of its Group to, honor any such applicable Privilege between OPC and the members of its Group and its or their counsel, and will not assert that OPC or a member of its Group has waived, relinquished or otherwise lost such Privilege.  For the avoidance of doubt, in the event of any litigation, dispute, controversy or claim between OPC or a member of its Group, on the one hand, and a Third Party other than a member of the CRC Group, on the other hand, OPC shall retain the right to assert any applicable Privilege with

 

40



 

respect to any communications relating to advice given prior to the Distribution Date by counsel to OPC or any Person that was a Subsidiary of OPC prior to the Distribution Date (it being understood, for the avoidance of doubt, that nothing in this Section 8.7 shall prevent CRC from asserting any applicable Privilege with respect to the matters discussed herein in the event such Privilege is not waived by OPC).

 

8.8                                No Attorney Testimony .  No in-house attorney or outside attorney may be called to testify about or present evidence covering the interpretation or meaning of this Agreement in any dispute between the parties.

 

ARTICLE IX
TERMINATION

 

9.1                                Termination .  This Agreement and any Ancillary Agreement may be terminated and the terms and conditions of the Distribution may be amended, modified or abandoned at any time prior to the Distribution Date by and in the sole and absolute discretion of the OPC Board without the approval of any Person, including CRC, in which case no party will have any liability of any kind to any other party by reason of this Agreement.  After the Distribution, this Agreement may not be terminated except by an agreement in writing signed by each of the parties to this Agreement.

 

ARTICLE X
MISCELLANEOUS

 

10.1                         Counterparts; Entire Agreement; Corporate Power .

 

(a)                                  This Agreement and each Ancillary Agreement may be executed in one or more counterparts, all of which shall be considered one and the same agreement, and shall become effective when one or more counterparts have been signed by each of the parties and delivered to the other party.

 

(b)                                  This Agreement and the Ancillary Agreements contain the entire agreement between the parties with respect to the subject matter hereof, supersede all previous agreements, negotiations, discussions, writings, understandings, commitments and conversations with respect to such subject matter and there are no agreements or understandings between the parties other than those set forth or referred to herein or therein.

 

(c)                                   OPC represents on behalf of itself and each other member of the OPC Group, and CRC represents on behalf of itself and each other member of the CRC Group, as follows:

 

(i)                                      each such Person has the requisite corporate or other power and authority and has taken all corporate or other action necessary in order to execute, deliver and perform each of this Agreement and each Ancillary Agreement to which it is a party and to consummate the transactions contemplated hereby and thereby; and

 

(ii)                                   this Agreement and each Ancillary Agreement to which it is a party has been duly executed and delivered by it and constitutes a valid and binding agreement of it enforceable in accordance with the terms thereof.

 

(d)                                  Each party hereto acknowledges that it and each other party hereto may execute certain of the Ancillary Agreements by facsimile, stamp or mechanical signature.  Each party hereto expressly adopts and confirms each such facsimile, stamp or mechanical signature made in its respective name as if it were a manual signature, agrees that it will not assert that any such signature is not adequate to bind such party to the same extent as if it were signed manually and agrees that at the reasonable request of any other party hereto at any time it will as promptly as reasonably practicable cause each such Ancillary Agreement to be manually executed (any such execution to be as of the date of the initial date thereof).

 

(e)                                   Notwithstanding any provision of this Agreement or any Ancillary Agreement, neither OPC nor CRC shall be required to take or omit to take any act that would violate its fiduciary duties to any minority stockholders of any non-wholly owned Subsidiary of OPC or CRC, as the case may be (it being understood that

 

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directors’ qualifying shares or similar interests will be disregarded for purposes of determining whether a Subsidiary is wholly owned).

 

10.2                         Governing Law; Waiver of Trial by Jury .

 

(a)                                  This Agreement and, unless expressly provided therein, each Ancillary Agreement (and any claims or disputes arising out of or related hereto or thereto or to the transactions contemplated hereby and thereby or to the inducement of any party to enter herein and therein, whether for breach of contract, tortious conduct or otherwise and whether predicated on common law, statute or otherwise) shall be governed by and construed and interpreted in accordance with the Laws of the State of Texas, irrespective of the choice of laws principles of the State of Texas as of the date of this Agreement, including all matters of validity, construction, effect, enforceability, performance and remedies.

 

(b)                                  THE PARTIES EXPRESSLY WAIVE AND FOREGO ANY RIGHT TO TRIAL BY JURY.

 

10.3                         Assignability .  Except as set forth in any Ancillary Agreement, this Agreement and each Ancillary Agreement shall be binding upon and inure to the benefit of the parties hereto and thereto, respectively, and their respective successors and permitted assigns; provided , however , that no party hereto or thereto may assign its respective rights or delegate its respective obligations under this Agreement or any Ancillary Agreement without the express prior written consent of the other parties hereto or thereto.

 

10.4                         Third-Party Beneficiaries .  Except for the indemnification rights under this Agreement or any Ancillary Agreement of any OPC Indemnitee or CRC Indemnitee in their respective capacities as such, (a) the provisions of this Agreement and each Ancillary Agreement are solely for the benefit of the parties and are not intended to confer upon any Person except the parties any rights or remedies hereunder or thereunder, and (b) there are no third-party beneficiaries of this Agreement or any Ancillary Agreement and neither this Agreement nor any Ancillary Agreement shall provide any third person with any remedy, claim, liability, reimbursement, claim of action or other right in excess of those existing without reference to this Agreement or any Ancillary Agreement.

 

10.5                         Notices .  All notices, requests, claims, demands or other communications under this Agreement and, to the extent, applicable and unless otherwise provided therein, under each of the Ancillary Agreements shall be in writing and shall be given or made (and shall be deemed to have been duly given or made upon receipt) by delivery in person, by overnight courier service, or by facsimile or electronic transmission with receipt confirmed (followed by delivery of an original via overnight courier service), to the respective parties at the following addresses (or at such other address for a party as shall be specified in a notice given in accordance with this Section 10.5):

 

If to OPC, to:

 

Occidental Petroleum Corporation

 

 

5 Greenway Plaza

 

 

Houston, Texas 77046

 

 

Attention: General Counsel

 

 

 

If to CRC, to:

 

California Resources Corporation

 

 

[                                ]

 

 

[                                ]

 

 

Attention: General Counsel

 

Any party may, by notice to the other party, change the address and contact person to which any such notices are to be given.

 

10.6                         Severability .  If any provision of this Agreement or any Ancillary Agreement or the application thereof to any Person or circumstance is determined by a court of competent jurisdiction to be invalid, void or unenforceable, the remaining provisions hereof or thereof, or the application of such provision to Persons or circumstances or in jurisdictions other than those as to which it has been held invalid or unenforceable, shall remain

 

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in full force and effect and shall in no way be affected, impaired or invalidated thereby.  Upon such determination, the parties shall negotiate in good faith in an effort to agree upon such a suitable and equitable provision to effect the original intent of the parties.

 

10.7                         Force Majeure .  No party shall be deemed in default of this Agreement or any Ancillary Agreement to the extent that any delay or failure in the performance of its obligations under this Agreement or any Ancillary Agreement, other than a delay or failure to make a payment, results from any cause beyond its reasonable control and without its fault or negligence, such as acts of God, acts of civil or military authority, embargoes, epidemics, war, riots, insurrections, fires, explosions, earthquakes, floods, unusually severe weather conditions, labor problems or unavailability of parts, or, in the case of computer systems, any failure in electrical or air conditioning equipment.  In the event of any such excused delay, the time for performance shall be extended for a period equal to the time lost by reason of the delay.

 

10.8                         Publicity .  Prior to the Distribution, CRC shall not, without the consent of OPC, issue any press releases or otherwise making public statements with respect to the Separation, the Distribution or any of the other transactions contemplated hereby and prior to making any filings with any Governmental Authority with respect thereto.

 

10.9                         Expenses .  Except as expressly set forth in this Agreement (including Sections 2.12 and 8.1(b)) or in any Ancillary Agreement, all fees, costs and expenses incurred in connection with the preparation, execution, delivery and implementation of this Agreement and any Ancillary Agreement, and with the consummation of the transactions contemplated hereby and thereby, will be borne by the party incurring such fees, costs or expenses.

 

10.10                  Late Payments .  Except as expressly provided to the contrary in this Agreement or in any Ancillary Agreement, any amount not paid when due pursuant to this Agreement or any Ancillary Agreement (and any amounts billed or otherwise invoiced or demanded and properly payable that are not paid within thirty (30) days of such bill, invoice or other demand) shall accrue interest at a rate per annum equal to the Prime Rate plus 2%.

 

10.11                  Headings .  The article, section and paragraph headings contained in this Agreement and in the Ancillary Agreements are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement or any Ancillary Agreement.

 

10.12                  Survival of Covenants .  Except as expressly set forth in any Ancillary Agreement, the covenants, representations and warranties contained in this Agreement and each Ancillary Agreement, and liability for the breach of any obligations contained herein or therein, shall survive the Separation and the Distribution and shall remain in full force and effect.

 

10.13                  Waivers of Default .  Waiver by any party of any default by the other party of any provision of this Agreement or any Ancillary Agreement shall not be deemed a waiver by the waiving party of any subsequent or other default, nor shall it prejudice the rights of such party.  No failure or delay by any party in exercising any right, power or privilege under this Agreement or any Ancillary Agreement shall operate as a waiver thereof nor shall a single or partial exercise thereof prejudice any other or further exercise thereof or the exercise of any other right, power or privilege.

 

10.14                  Specific Performance .  Subject to the provisions of Article IV, in the event of any actual or threatened default in, or breach of, any of the terms, conditions and provisions of this Agreement or any Ancillary Agreement, the party or parties who are, or are to be, thereby aggrieved shall have the right to specific performance and injunctive or other equitable relief in respect of its or their rights under this Agreement or such Ancillary Agreement, in addition to any and all other rights and remedies at law or in equity, and all such rights and remedies shall be cumulative.  The parties agree that the remedies at law for any breach or threatened breach, including monetary damages, are inadequate compensation for any loss and that any defense in any action for specific performance that a remedy at law would be adequate is waived.  Any requirements for the securing or posting of any bond with such remedy are waived by each of the parties to this Agreement.

 

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10.15                  Amendments .  No provisions of this Agreement or any Ancillary Agreement shall be deemed waived, amended, supplemented or modified by any party, unless such waiver, amendment, supplement or modification is in writing and signed by the authorized representative of the party against whom it is sought to enforce such waiver, amendment, supplement or modification.

 

10.16                  Interpretation .  In this Agreement and any Ancillary Agreement, (a) words in the singular shall be held to include the plural and vice versa and words of one gender shall be held to include the other genders as the context requires; (b) the terms “hereof,” “herein,” “herewith” and words of similar import, and the terms “Agreement” and “Ancillary Agreement” shall, unless otherwise stated, be construed to refer to this Agreement or the applicable Ancillary Agreement as a whole (including all of the Schedules, Exhibits and Appendices hereto and thereto) and not to any particular provision of this Agreement or such Ancillary Agreement; (c) Article, Section, Exhibit, Schedule and Appendix references are to the Articles, Sections, Exhibits, Schedules and Appendices to this Agreement (or the applicable Ancillary Agreement) unless otherwise specified; (d) the word “including” and words of similar import when used in this Agreement (or the applicable Ancillary Agreement) means “including, without limitation”; (e) the word “or” shall not be exclusive; and (f) unless expressly stated to the contrary in this Agreement or in any Ancillary Agreement, all references to “the date hereof,” “the date of this Agreement,” “hereby” and “hereupon” and words of similar import shall all be references to the date first stated in the preamble to this Agreement, regardless of any amendment or restatement hereof.  Nothing contained herein shall be interpreted or construed against the drafter(s) of these agreements.  Both parties had full and fair opportunity to contribute to the drafting of this Agreement.

 

10.17                  Relationship of the Parties .  It is expressly agreed that, from and after the Distribution Date and for purposes of this Agreement and the Ancillary Agreements, (a) no member of the CRC Group shall be deemed to be an Affiliate of any member of the OPC Group and (b) no member of the OPC Group shall be deemed to be an Affiliate of any member of the CRC Group.

 

10.18                  Limitations of Liability .  NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY OTHER THAN THE FOLLOWING PROVISO, NEITHER CRC OR ITS AFFILIATES, ON THE ONE HAND, NOR OPC OR ITS AFFILIATES, ON THE OTHER HAND, SHALL BE LIABLE UNDER THIS AGREEMENT TO THE OTHER FOR ANY CONSEQUENTIAL, SPECIAL, INDIRECT, PUNITIVE, EXEMPLARY, REMOTE, SPECULATIVE, LOSS OF PROFIT OR SIMILAR DAMAGES OF THE OTHER ARISING IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY; PROVIDED , THE AFORESAID LIMITATION ON DAMAGES SHALL NOT APPLY TO ANY SUCH DAMAGES THAT ARE OWED PURSUANT TO A THIRD PARTY CLAIM FOR WHICH INDEMNIFICATION IS REQUIRED UNDER ARTICLE V.

 

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IN WITNESS WHEREOF, the parties have caused this Agreement to be executed by their duly authorized representatives.

 

 

OCCIDENTAL PETROLEUM CORPORATION

 

 

 

 

 

By:

 

 

Name:

 

 

Title:

 

 

 

 

 

 

CALIFORNIA RESOURCES CORPORATION

 

 

 

 

 

By:

 

 

Name:

 

 

Title:

 

 

Signature Page to Separation and Distribution Agreement

 




EXHIBIT 10.3

 

[FORM OF]

 

EMPLOYEE MATTERS AGREEMENT

 

BY AND BETWEEN

 

OCCIDENTAL PETROLEUM CORPORATION

 

AND

 

CALIFORNIA RESOURCES CORPORATION

 

DATED AS OF                 , 2014

 



 

TABLE OF CONTENTS

 

ARTICLE I

GENERAL PRINCIPLES FOR ALLOCATION OF LIABILITIES

 

 

 

Section 1.1

General Principles

1

Section 1.2

Service Credit

3

Section 1.3

Plan Administration

3

Section 1.4

Retention of CRC Group Plans

4

Section 1.5

No Duplication or Acceleration of Benefits

4

Section 1.6

No Expansion of Participation

4

 

 

 

ARTICLE II

DEFINITIONS

 

 

 

Section 2.1

Definitions

4

Section 2.2

Interpretation

12

 

 

 

ARTICLE III

ASSIGNMENT OF EMPLOYEES

 

 

 

Section 3.1

Active Employees

14

Section 3.2

Employment Law Obligations

15

Section 3.3

Employee Records

16

 

 

 

ARTICLE IV

EQUITY AND LONG-TERM INCENTIVE AWARDS

 

 

 

Section 4.1

General Principles

17

Section 4.2

Restricted Stock

18

Section 4.3

Stock Appreciation Rights

19

Section 4.4

OPC LTI Mixed-Settlement Units

20

Section 4.5

Restricted Stock Units

20

Section 4.6

Long-Term Incentive Cash-Based and Cash-Settled Awards

21

Section 4.7

Section 16(b) of the Securities Exchange Act; Code Sections 162(m) and 409A

22

Section 4.8

Liabilities for Settlement of Awards

23

Section 4.9

Form S-8

23

Section 4.10

Tax Reporting and Withholding for Awards

23

Section 4.11

Approval of CRC New Equity Plan and CRC ESPP

23

 

 

 

ARTICLE V

BONUS AND SHORT-TERM INCENTIVE PLANS

 

 

 

Section 5.1

Establishment of CRC Short- Term Incentive Plans

23

Section 5.2

Treatment of Short-Term Incentives for Year of Initial Distribution

24

Section 5.3

Plan Liabilities

24

 

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ARTICLE VI

QUALIFIED DEFINED BENEFIT PLANS

 

 

 

Section 6.1

Retention of CRC Group Defined Benefit Plans

24

Section 6.2

Transfer of Assets

25

Section 6.3

OPC Defined Benefit Plans

25

 

 

 

ARTICLE VII

QUALIFIED DEFINED CONTRIBUTION PLANS

 

 

 

Section 7.1

Retention of CRC Existing Defined Contribution Plans

25

Section 7.2

Establishment of the CRC Defined Contribution Plans

25

Section 7.3

Vesting of CRC Employee Accounts

26

Section 7.4

CRC Group Employee Account Balances

26

 

 

 

ARTICLE VIII

NONQUALIFIED DEFERRED COMPENSATION PLANS

 

 

 

Section 8.1

Retention of CRC Existing Deferred Compensation Plan

26

Section 8.2

Establishment of CRC Deferred Compensation Plans

26

Section 8.3

Liability and Responsibility

27

Section 8.4

Special Provisions Relating to 2005 Deferred Stock Plan

27

Section 8.5

[Grantor Trusts

27

 

 

 

ARTICLE IX

WELFARE PLANS

 

 

 

Section 9.1

Retention of CRC Existing Welfare Plans

28

Section 9.2

Establishment of CRC Welfare Plans

28

Section 9.3

Special Provisions Relating to Post-Retirement Welfare Plans

28

Section 9.4

Transitional Matters Under CRC Welfare Plans

28

Section 9.5

Benefit Elections and Designations and Continuity of Benefits

29

Section 9.6

Insurance Contracts

31

Section 9.7

Third-Party Vendors

31

 

 

 

ARTICLE X

WORKERS’ COMPENSATION AND UNEMPLOYMENT COMPENSATION

 

 

 

Section 10.1

CRC Workers’ and Unemployment Compensation

31

Section 10.2

Assignment of Contribution Rights

31

Section 10.3

Collateral

32

Section 10.4

Cooperation

32

 

 

 

ARTICLE XI

SEVERANCE

 

 

 

Section 11.1

Establishment of CRC Severance Program

32

Section 11.2

Liability for Severance

32

 

ii



 

ARTICLE XII

BENEFIT ARRANGEMENTS AND OTHER MATTERS

 

 

 

Section 12.1

Termination of Participation

32

Section 12.2

Accrued Time Off

32

Section 12.3

Leaves of Absence

32

Section 12.4

Collective Bargaining Agreements

32

Section 12.5

Restrictive Covenants in Employment and Other Agreements

33

 

 

 

ARTICLE XIII

GENERAL PROVISIONS

 

 

 

Section 13.1

Preservation of Rights to Amend

33

Section 13.2

Confidentiality

33

Section 13.3

Administrative Complaints/Litigation

33

Section 13.4

Reimbursement and Indemnification

34

Section 13.5

Costs of Compliance with Agreement

34

Section 13.6

Fiduciary Matters

34

Section 13.7

Entire Agreement

35

Section 13.8

Binding Effect; No Third-Party Beneficiaries; Assignment

35

Section 13.9

Amendment; Waivers

35

Section 13.10

Remedies Cumulative

35

Section 13.11

Notices

35

Section 13.12

Counterparts

36

Section 13.13

Severability

36

Section 13.14

Governing Law

36

Section 13.15

Dispute Resolution

36

Section 13.16

Performance

36

Section 13.17

Construction

37

Section 13.18

Effect if Initial Distribution Does Not Occur

37

 

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EMPLOYEE MATTERS AGREEMENT

 

This EMPLOYEE MATTERS AGREEMENT , made and entered into effective as of [ · ], 2014, is by and between Occidental Petroleum Corporation, a Delaware corporation (“ OPC ”), and California Resources Corporation, a Delaware corporation and wholly-owned Subsidiary of OPC (“ CRC ”). OPC and CRC are also referred to in this Agreement individually as a “ Party ” and collectively as the “ Parties .”  Capitalized terms used herein not otherwise defined shall have the respective meanings assigned to them in Section 2.1 .

 

R E C I T A L S

 

WHEREAS , OPC has determined that it would be appropriate, desirable and in the best interests of OPC and the stockholders of OPC to separate the CRC Business from OPC;

 

WHEREAS , concurrently herewith, OPC and CRC will enter into the Separation and Distribution Agreement, dated as of the date hereof (the “ Separation Agreement ”), in connection with the separation of the CRC Business from OPC and the Distribution of CRC Common Stock to the stockholders of OPC;

 

WHEREAS , the Separation Agreement also provides for the execution and delivery of certain other agreements, including this Agreement, in order to facilitate and provide for the separation of CRC and its Subsidiaries from OPC; and

 

WHEREAS , in order to ensure an orderly transition under the Separation Agreement, it will be necessary for the Parties to allocate between them Assets, Liabilities and responsibilities with respect to certain employee compensation and benefit plans and programs, and certain other employment-related matters.

 

NOW, THEREFORE , in consideration of the foregoing and the covenants and agreements set forth below and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the Parties hereby agree as follows:

 

ARTICLE I
GENERAL PRINCIPLES FOR ALLOCATION OF LIABILITIES

 

Section 1.1                                     General Principles .

 

(a)                                  Cessation of Participation in OPC Benefit Plans by CRC Group Employees .  Each member of the OPC Group and each member of the CRC Group shall take any and all reasonable action as shall be necessary or appropriate so that active participation in the OPC Benefit Plans by all CRC Group Employees shall terminate in connection with the Initial Distribution as and when provided under this Agreement (or, if not specifically provided under this Agreement, as of the Effective Time).

 

(b)                                  Certain Obligations of the CRC Group .  Except as otherwise provided in this Agreement, effective as of the Effective Time, one or more members of the CRC Group (as

 

1



 

determined by CRC) shall assume or continue the sponsorship of, and no member of the OPC Group shall have any further Liability with respect to or under, the following agreements, obligations and Liabilities, and CRC shall indemnify each member of the OPC Group, and the officers, directors, and employees of each member of the OPC Group, and hold them harmless with respect to such agreements, obligations or Liabilities:

 

(i)                                      any and all individual agreements entered into between any member of the OPC Group or CRC Group and any CRC Group Employee or Former CRC Group Employee;

 

(ii)                                   any and all agreements entered into between any member of the OPC Group or CRC Group and any individual who is a consultant or an independent contractor providing services primarily for the benefit of the CRC Business;

 

(iii)                                any and all collective bargaining agreements, collective agreements and trade union or works council agreements entered into between any member of the OPC Group or CRC Group and any labor union, trade union, works council or other representative of CRC Group Employees;

 

(iv)                               any and all wages, salaries, incentive compensation (as the same may be modified by this Agreement), commissions, bonuses, payment owed for any vacation or paid time off entitlement and any other compensation or benefits payable to or on behalf of any CRC Group Employees or Former CRC Group Employees on or after the Distribution Date, without regard to when such wages, salaries, incentive compensation, commissions, bonuses, or other compensation or benefits are or may have been earned;

 

(v)                                  any and all Liabilities and other obligations relating to any Benefit Plan that is sponsored, maintained or contributed to exclusively by a member or members of the CRC Group or for the benefit of one or more CRC Group Employees or Former CRC Group Employees (whether or not such Liabilities relate to CRC Group Employees or Former CRC Group Employees) ;

 

(vi)                               any and all expenses and obligations related to relocation, repatriation, transfers or similar items incurred by or owed to any CRC Group Employees or Former CRC Group Employees that have not been paid prior to the Distribution Date;

 

(vii)                            any and all immigration-related, visa, work application or similar rights, obligations and Liabilities related to any CRC Group Employees and Former CRC Group Employees;

 

(viii)                         any employment tax, superannuation, employment insurance, pension plan or similar Liabilities incurred or owed with respect to CRC Group Employees and Former CRC Group Employees; and

 

(ix)                               any and all Liabilities and obligations whatsoever with respect to claims made by, on behalf of, or with respect to any CRC Group Employees, Former

 

2



 

CRC Group Employees or independent contractors providing services primarily for the CRC Business including any such Liability or obligation in connection with any labor or employment practice, workers’ compensation claims, labor or employment Laws , employee benefit plan, program or policy not otherwise expressly retained or assumed by any member of the OPC Group pursuant to this Agreement, including such Liabilities relating to actions or omissions of or by any member of the CRC Group or any officer, director, employee or agent thereof on or prior to the Effective Time.

 

(c)                                   Certain Obligations of the OPC Group .  Except as otherwise provided in this Agreement, effective as of the Effective Time, no member of the CRC Group shall have any further Liability for, and OPC shall indemnify each member of the CRC Group, and the officers, directors, and employees of each member of the CRC Group, and hold them harmless with respect to any and all Liabilities and obligations whatsoever with respect to, claims made by or with respect to any OPC Group Employees and Former OPC Group Employees in connection with any employee benefit plan, program or policy not otherwise retained or assumed by any member of the CRC Group pursuant to this Agreement, including such Liabilities relating to actions or omissions of or by any member of the OPC Group or any officer, director, employee or agent thereof on, prior to or after the Effective Time.

 

Section 1.2                                     Service Credit .

 

(a)                                  Service for Participation, Eligibility, Vesting, and Benefit Level Purposes Except as otherwise provided in any other provision of this Agreement, the CRC Benefit Plans shall, and CRC shall cause each member of the CRC Group to, recognize each CRC Group Employee’s full service credit for purposes of participation, eligibility, vesting and determination of level of benefits under any CRC Benefit Plan for such CRC Group Employee’s service with any member of the OPC Group on or prior to the Effective Time, to the same extent such service would be credited if it had been performed for a member of the CRC Group.

 

(b)                                  Evidence of Prior Servic e Notwithstanding anything to the contrary, but subject to applicable Law, upon reasonable request by one Party to the other Party, the first Party will provide to the other Party copies of any records available to the first Party to document such service, plan participation and membership of such Employees and cooperate with the first Party to resolve any discrepancies or obtain any missing data for purposes of determining benefit eligibility, participation, vesting and determination of level of benefits with respect to any Employee.

 

Section 1.3                                     Plan Administration .

 

(a)                                  Transition Services .   The Parties acknowledge that the OPC Group or the CRC Group may provide administrative services for certain of the other Party’s benefit programs for a transitional period under the terms of the Transition Services Agreement. The Parties agree to enter into a business associate or comparable agreement (if required by HIPAA or other applicable health information or privacy Laws) in connection with such Transition Services Agreement.

 

3



 

(b)                                  Participant Elections and Beneficiary Designations .   All participant elections and beneficiary designations made under any OPC Benefit Plan with respect to which Assets or Liabilities are transferred or allocated to plans maintained by a member of the CRC Group in accordance with this Agreement shall continue in effect under the applicable CRC Benefit Plan, including deferral, investment and payment form elections, dividend elections, coverage options and levels, beneficiary designations and the rights of alternate payees under qualified domestic relations orders, to the extent allowed by applicable Law.

 

Section 1.4                                     Retention of CRC Group Plans In the event any Benefit Plan is sponsored, maintained or contributed to exclusively by a member or members of the CRC Group or exclusively for the benefit of one or more CRC Group Employees or Former CRC Group Employees, from and after the Effective Time, CRC shall cause a member of the CRC Group to assume or retain sponsorship of such Benefit Plan and all Liabilities relating thereto (whether or not such Liabilities relate to CRC Group Employees or Former CRC Group Employees).

 

Section 1.5                                     No Duplication or Acceleration of Benefits .  Notwithstanding anything to the contrary in this Agreement, the Separation Agreement or any Transfer Document, no participant in the CRC Defined Contribution Plans, CRC Welfare Plans or other CRC Benefit Plans shall receive benefits that duplicate benefits provided by the corresponding OPC Benefit Plan or arrangement. Furthermore, unless expressly provided for in this Agreement, the Separation Agreement or in any Transfer Document or required by applicable Law, no provision in this Agreement shall be construed to create any right to accelerate vesting or entitlements to any compensation or Benefit Plan on the part of any OPC Group Employee, Former OPC Group Employee, OPC Director, CRC Director, CRC Group Employee or Former CRC Group Employee.

 

Section 1.6                                     No Expansion of Participation .  Unless otherwise expressly provided in this Agreement, as otherwise determined or agreed to by OPC and CRC, as required by applicable Law, or as explicitly set forth in a CRC Benefit Plan, a CRC Group Employee shall be entitled to participate in the CRC Benefit Plans only to the extent that such Employee was entitled to participate in the corresponding OPC Benefit Plan or Benefit Plan sponsored by a member of the CRC Group as in effect as of the Effective Time, with it being the intent of the Parties that this Agreement does not result in any expansion of the number of CRC Group Employees participating or the participation rights therein that they had prior to the Effective Time.

 

ARTICLE II
DEFINITIONS

 

Section 2.1                                     Definitions .  As used in this Agreement, the following terms have the meanings set forth in this Section 2.1 :

 

Actual LTI Performance ” means, with respect to an OPC LTI Cash Award or OPC RSU, the actual attainment of the performance objectives subject to such award, as determined by the OPC Committee based upon performance through the end of the latest practicable date prior to the Effective Time applicable to such award.

 

4



 

Additional OPC RSAs ” has the meaning set forth in Section 4.2(c) .

 

Adjusted OPC DRSU ” has the meaning set forth in Section 4.5(b) .

 

Adjusted OPC LTI Award ” means an Adjusted OPC DRSU, Adjusted OPC MSU, Adjusted OPC RSU and Adjusted OPC SAR.

 

Adjusted OPC MSU ” has the meaning set forth in Section 4.4(b) .

 

Adjusted OPC RSU ” has the meaning set forth in Section 4.5(d) .

 

Adjusted OPC SAR ” has the meaning set forth in Section 4.3(b) .

 

Adjusted OPC Share Number ” means, with respect to an Adjusted OPC LTI Award, (a) the number of shares of OPC Common Stock subject to the related OPC LTI Award immediately prior to the Effective Time (assuming, in the case of any OPC RSU, settlement based upon the target number of performance shares subject to such award) multiplied by (b) the OPC Equity Award Ratio, rounded (i) down to the nearest whole share of OPC Common Stock in the case of any Adjusted OPC SAR and (ii) [down] [up] to the nearest whole share of OPC Common Stock in the case of any Adjusted OPC LTI Award other than an Adjusted OPC SAR.

 

Affiliate ” has the meaning set forth in the Separation Agreement.

 

Agreement ” means this Employee Matters Agreement, together with all Schedules hereto and all amendments, modifications, and changes hereto entered into pursuant to Section 13.9 .

 

ASC 718 ” means Accounting Standards Codification Topic 718, Compensation — Stock Compensation, or any successor accounting standard.

 

Assets ” has the meaning set forth in the Separation Agreement.

 

Benefit Management Records ” has the meaning set forth in Section 3.3(b) .

 

Benefit Plan means any contract, agreement, policy, practice, program, plan, trust, commitment or arrangement (whether written or unwritten) providing for benefits, perquisites or compensation of any nature to any Employee, or to any family member, dependent, or beneficiary of any Employee, including pension plans, thrift plans, supplemental pension plans and welfare plans, and contracts, agreements, policies, practices, programs, plans, trusts, commitments and arrangements providing for terms of employment, fringe benefits, severance benefits, change in control protections or benefits, travel and accident, life, disability and accident insurance, tuition reimbursement, travel reimbursement, vacation, sick, personal or bereavement days, leaves of absences and holidays.

 

COBRA ” means the U.S. Consolidated Omnibus Budget Reconciliation Act of 1985, as codified at Section 601 et seq. of ERISA and at Section 4980B of the Code.

 

Code ” has the meaning set forth in the Separation Agreement.

 

5



 

Collective Bargaining Agreements ” has the meaning set forth in Section 3.1(h) .

 

CRC ” has the meaning set forth in the preamble to this Agreement.

 

CRC Benefit Plan ” means any Benefit Plan sponsored or maintained by a member of the CRC Group immediately following the Effective Time.

 

CRC Business ” has the meaning set forth in the Separation Agreement.

 

CRC Common Stock ” has the meaning set forth in the Separation Agreement.

 

CRC Deferred Compensation Beneficiaries ” has the meaning set forth in Section 8.2 .

 

CRC Deferred Compensation Plan ” has the meaning set forth in Section 8.2 .

 

CRC Defined Contribution Plans ” has the meaning set forth in Section 7.2 .

 

CRC Director ” means any individual who is a non-employee member of the Board of Directors of CRC immediately after the Effective Time and who is not at such time also a member of the Board of Directors of OPC.

 

CRC Director DRSU ” has the meaning set forth in Section 4.5(a) .

 

CRC DRSU ” has the meaning set forth in Section 4.5(a) .

 

CRC Employee LTI Cash Award ” has the meaning set forth in Section 4.6(a).

 

CRC Employee Mixed-Settlement Unit ” has the meaning set forth in Section 4.4(a) .

 

CRC Employee RSA ” has the meaning set forth in Section 4.2(b) .

 

CRC Employee RSU ” has the meaning set forth in Section 4.5(c) .

 

CRC Employee SAR ” has the meaning set forth in Section 4.3(a) .

 

CRC Entity ” means any member of the CRC Group.

 

CRC Equity Award Ratio ” means the quotient obtained by dividing the OPC Pre-Distribution Stock Value by the CRC Stock Value.

 

CRC ESPP ” means an “employee stock purchase plan” (as defined in Section 423 of the Code) which shall be adopted by CRC in accordance with Section 4.11 .

 

CRC Existing Deferred Compensation Plan ” means the Tidelands Deferred Compensation Plan.

 

CRC Existing Defined Contribution Plans ” means the Orchard Petroleum Inc. 401(k) Profit Sharing Plan and Trust and the Tidelands Oil Production Company Employees’ Deferred Compensation 401(k) Savings & Investment Plan.

 

6


 

CRC Existing Welfare Plans ” means the Tidelands Oil Production Company Employee Long Term Disability Plan, the Tidelands Oil Production Company Employee Welfare Plan and the Tidelands Oil Production Company Occupational AD&D Plan.

 

CRC FSA ” has the meaning set forth in Section 9.5(b) .

 

[“ CRC Grantor Trust ” has the meaning set forth in Section 8.5 .]

 

CRC Group ” has the meaning set forth in the Separation Agreement.

 

CRC Group Defined Benefit Plans ” means the THUMS Pension Plan and the Tidelands Oil Production Company Employees’ Pension Plan.

 

CRC Group Employees ” has the meaning set forth in Section 3.1(a) .

 

CRC LTI Awards ” means the CRC DRSUs, the CRC MSUs, the CRC RSAs, and the CRC SARs.

 

CRC MSU ” has the meaning set forth in Section 4.4(a) .

 

CRC New Equity Plan ” means the plan adopted by CRC and approved by a member of the OPC Group, in accordance with Section 4.11 , under which the CRC LTI Awards described in Article IV shall be issued.

 

CRC Pension Assets ” has the meaning set forth in Section 6.2 .

 

CRC Pension Trust ” has the meaning set forth in Section 6.2 .

 

CRC Post-Retirement Welfare Plan Participants ” has the meaning set forth in Section 9.3.

 

CRC Post-Retirement Welfare Plans ” has the meaning set forth in Section 9.3.

 

CRC RSA ” has the meaning set forth in Section 4.2(b) .

 

CRC SAR ” has the meaning set forth in Section 4.3(a) .

 

CRC Share Number ” means, with respect to a CRC LTI Award, (a) the number of shares of OPC Common Stock subject to the related OPC LTI Award immediately prior to the Effective Time (assuming, in the case of any OPC RSU, settlement based upon (i) target performance if there is 12 months or more remaining in the performance period applicable to such award, or (ii) attainment of Actual LTI Performance if there is less than 12 months remaining in the performance period applicable to such award) multiplied by (b) the CRC Equity Award Ratio, rounded (i) down to the nearest whole share of CRC Common Stock in the case of any CRC SAR and (ii) [down] [up] to the nearest whole share of CRC Common Stock in the case of any CRC LTI Award other than a CRC SAR.

 

CRC Short-Term Incentive Plans ” has the meaning set forth in Section 5.1 .

 

7



 

CRC Stock Value ” means the simple average of the volume weighted average per share price of CRC Common Stock trading on the NYSE during Regular Trading Hours on the first four Trading Days following the Distribution Date.

 

CRC Welfare Plan Participants ” has the meaning set forth in Section 9.1.

 

CRC Welfare Plans ” has the meaning set forth in Section 9.2 .

 

Distribution ” has the meaning set forth in the Separation Agreement.

 

Distribution Date ” has the meaning set forth in the Separation Agreement.

 

Distribution Ratio ” has the meaning set forth in the Separation Agreement.

 

[“ Distribution Year Blended Performance ” means, with respect to a bonus award under a CRC Short-Term Incentive Plan for the year in which the Distribution Date occurs, the combination of (a) performance of the OPC Group under the applicable prior OPC Short-Term Incentive Plan from January 1 of the year in which the Distribution Date occurs through and including the [last day of the calendar month coincident with or next preceding the] Distribution Date and (b) performance of the CRC Group under the applicable CRC Short-Term Incentive Plan from the day following the [last day of the calendar month coincident with or next preceding the] Distribution Date through and including December 31 of the year in which the Distribution Date occurs, with the relative performance results in clauses (a) and (b) pro rated based upon the number of days occurring in the periods described in clauses (a) and (b), respectively.]

 

Effective Time ” means the time immediately before the effective time of the Initial Distribution.

 

Employee ” means any OPC Group Employee, Former OPC Group Employee, Former CRC Group Employee or CRC Group Employee.

 

ERISA ” means the U.S. Employee Retirement Income Security Act of 1974, as amended, and the regulations promulgated thereunder.

 

FICA ” has the meaning set forth in Section 3.1(f) .

 

Former CRC Group Employees means all former employees of the OPC Group who have an employment end date on or before the Effective Time and who provided services primarily relating to the CRC Business while employed by the OPC Group .

 

Former OPC Group Employees ” means all former employees of the OPC Group who are not Former CRC Group Employees.

 

FSA Participation Period ” has the meaning set forth in Section 9.5(b) .

 

FUTA ” has the meaning set forth in Section 3.1(f) .

 

8



 

HIPAA ” means the U.S. Health Insurance Portability and Accountability Act of 1996, as amended, and the regulations promulgated thereunder and any similar foreign, state, provincial or local Law.

 

Initial Distribution ” has the meaning set forth in the Separation Agreement.

 

Law ” has the meaning set forth in the Separation Agreement.

 

Liabilities ” has the meaning set forth in the Separation Agreement.

 

NYSE ” means the New York Stock Exchange.

 

OPC ” has the meaning set forth in the preamble.

 

OPC Benefit Plan ” means any Benefit Plan sponsored or maintained by a member of the OPC Group immediately prior to the Effective Time other than any Benefit Plan sponsored or maintained exclusively by a member of the CRC Group.

 

OPC Committee ” means the Executive Compensation Committee of the Board of Directors of OPC.

 

OPC Common Stock ” has the meaning set forth in the Separation Agreement.

 

OPC Deferred Compensation Plans ” means the Occidental Petroleum Corporation Modified Deferred Compensation Plan and the Occidental Petroleum Corporation Supplemental Retirement Plan II, each as amended.

 

OPC Defined Benefit Plans ” means all Benefit Plans sponsored by one or more members of the OPC Group that are subject to Title IV of ERISA, other than the CRC Group Defined Benefit Plans.

 

OPC Defined Contribution Plans ” means the Occidental Petroleum Corporation Savings Plan and the Occidental Petroleum Corporation Retirement Plan, each as amended.

 

OPC Director ” means any individual who is a non-employee member of the Board of Directors of OPC immediately prior to the Effective Time.

 

OPC Director DRSU ” has the meaning set forth in Section 4.5(b) .

 

OPC DRSU ” means a restricted stock unit award granted pursuant to any of the OPC Equity Plans to an individual who was a non-employee member of the Board of Directors of OPC on the date of grant.

 

OPC DSP ” means the Occidental Petroleum Corporation 2005 Deferred Stock Program, as amended.

 

OPC Employee Mixed-Settlement Unit ” has the meaning set forth in Section 4.4(b) .

 

9



 

OPC Employee RSA ” has the meaning set forth in Section 4.2(c) .

 

OPC Employee RSU ” has the meaning set forth in Section 4.5(d) .

 

OPC Employee SAR ” has the meaning set forth in Section 4.3(b) .

 

OPC Entity ” means any member of the OPC Group.

 

OPC Equity Award Ratio ” means the quotient obtained by dividing the OPC Pre-Distribution Stock Value by the OPC Post-Distribution Stock Value.

 

OPC Equity Plans ” means the Occidental Petroleum Corporation 2005 Long-Term Incentive Plan, the Occidental Petroleum Corporation Phantom Share Unit Award Plan, and any other plan or agreement sponsored or maintained by OPC as of the Effective Time pursuant to which equity or other long-term incentive awards are or may be granted (in each case, as amended from time to time).

 

OPC Full Year Performance ” has the meaning set forth in Section 5.2 .

 

OPC Group ” has the meaning set forth in the Separation Agreement.

 

OPC Group Employees ” has the meaning set forth in Section 3.1(b) .

 

OPC LTI Awards ” means the OPC DRSUs, the OPC LTI Cash Awards, the OPC LTI Mixed-Settlement Units, the OPC RSAs, the OPC RSUs and the OPC SARs.

 

OPC LTI Cash Award ” means a cash-based and cash-settled award granted pursuant to any of the OPC Equity Plans to an individual who was an employee on the date of grant of such award, and which award is subject to performance-based vesting and forfeiture conditions.

 

OPC LTI Mixed-Settlement Unit ” means a long-term incentive unit granted pursuant to any of the OPC Equity Plans and with respect to which each unit represents one share of OPC Common Stock and is generally intended to be settled 50% in shares of OPC Common Stock and 50% in cash.

 

OPC Master Trust ” means the trust established pursuant to that certain Master Trust Agreement dated as of April 1, 2004 between Occidental Petroleum Corporation, BNY Western Trust Company and The Bank of New York, as amended from time to time.

 

OPC Post-Distribution Stock Value ” means the simple average of the volume weighted average per share price of OPC Common Stock trading on the NYSE during Regular Trading Hours on the first four Trading Days following the Distribution Date.

 

OPC Post-Retirement Welfare Plan ” means any Welfare Plan sponsored or maintained by any one or more members of the OPC Group as of immediately prior to the Effective Time, for the benefit of retired employees of the OPC Group.

 

10



 

OPC Pre-Distribution Stock Value ” means the simple average of the volume weighted average per share price of OPC Common Stock trading “regular way with due bills” on the NYSE during Regular Trading Hours on the Distribution Date and the three immediately preceding Trading Days.

 

OPC PSU ” means a Phantom Share Unit Award granted pursuant to the Occidental Petroleum Corporation Phantom Share Unit Award Plan.

 

OPC RSA ” means a restricted stock award granted pursuant to any of the OPC Equity Plans (including any such award issued to an OPC Director that may be fully vested but that is subject to transfer restrictions immediately prior to the Effective Time).

 

OPC RSU ” means an award of deferred stock granted pursuant to any of the OPC Equity Plans to an individual who was an employee on the date of grant of such award, and which award is subject to performance-based vesting and forfeiture conditions.

 

OPC SAR ” means a stock appreciation right granted pursuant to any of the OPC Equity Plans.

 

OPC Short-Term Incentive Plans ”  means those short-term incentive plans sponsored by the members of the OPC Group.

 

OPC Welfare Plan ” means any Welfare Plan sponsored or maintained by any one or more members of the OPC Group as of immediately prior to the Effective Time, other than an OPC Post-Retirement Welfare Plan.

 

Party ” or “ Parties ” has the meaning set forth in the preamble to this Agreement.

 

Pension Transfer Date ” has the meaning set forth in Section 6.2 .

 

Person ” has the meaning set forth in the Separation Agreement.

 

Regular Trading Hours ” means the period beginning at 9:30 A.M. New York City time and ending 4:00 P.M. New York City time.

 

Separation Agreement ” has the meaning set forth in the recitals to this Agreement.

 

Subsidiary ” has the meaning set forth in the Separation Agreement.

 

THUMS Pension Plan ” means the THUMS Long Beach Company Pension Plan.

 

Trading Day ” means the period of time during any given calendar day, commencing with the determination of the opening price on the NYSE and ending with the determination of the closing price on the NYSE, in which trading and settlement in shares of OPC Common Stock or CRC Common Stock is permitted on the NYSE.

 

Transfer Documents ” has the meaning set forth in the Separation Agreement.

 

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Transition Services Agreement ” has the meaning set forth in the Separation Agreement.

 

U.S. ” means the United States of America.

 

WARN ” means the U.S. Worker Adjustment and Retraining Notification Act, as amended, and the regulations promulgated thereunder, and any applicable foreign, state, provincial or local Law equivalent.

 

Welfare Plan ” means, where applicable, a “welfare plan” (as defined in Section 3(1) of ERISA) or a “cafeteria plan” under Section 125 of the Code, and any benefits offered thereunder, and any other plan offering health benefits (including medical, prescription drug, dental, vision, and mental health and substance abuse), disability benefits, or life, accidental death and disability, and business travel insurance, pre-tax premium conversion benefits, dependent care assistance programs, employee assistance programs, paid time off programs, contribution funding toward a health savings account or flexible spending accounts.

 

Section 2.2                                     Interpretation .  In this Agreement, unless the context clearly indicates otherwise:

 

(a)                                  words used in the singular include the plural and words used in the plural include the singular;

 

(b)                                  if a word or phrase is defined in this Agreement, its other grammatical forms, as used in this Agreement, shall have a corresponding meaning;

 

(c)                                   reference to any gender includes the other gender and the neuter;

 

(d)                                  the words “include,” “includes” and “including” shall be deemed to be followed by the words “without limitation”;

 

(e)                                   the words “shall” and “will” are used interchangeably and have the same meaning;

 

(f)                                    the word “or” shall have the inclusive meaning represented by the phrase “and/or”;

 

(g)                                   relative to the determination of any period of time, “from” means “from and including,” “to” means “to but excluding” and “through” means “through and including”;

 

(h)                                  all references to a specific time of day in this Agreement shall be based upon [Pacific] Standard Time or [Pacific] Daylight Savings Time, as applicable, on the date in question;

 

(i)                                      whenever this Agreement refers to a number of days, such number shall refer to calendar days;

 

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(j)                                     accounting terms used herein have the meanings historically ascribed to them by OPC and its Subsidiaries, including CRC for this purpose, in its and their internal accounting and financial policies and procedures in effect immediately prior to the date of this Agreement;

 

(k)                                  reference to any Article, Section or Schedule means such Article or Section of, or such Schedule to, this Agreement, as the case may be, and references in any Section or definition to any clause means such clause of such Section or definition;

 

(l)                                      the words “this Agreement,” “herein,” “hereunder,” “hereof,” “hereto” and words of similar import shall be deemed references to this Agreement as a whole and not to any particular Section or other provision of this Agreement;

 

(m)                              the term “commercially reasonable efforts” means efforts which are commercially reasonable to enable a Party, directly or indirectly, to satisfy a condition to or otherwise assist in the consummation of a desired result and which do not require the performing Party to expend funds or assume Liabilities other than expenditures and Liabilities which are customary and reasonable in nature and amount in the context of a series of related transactions similar to the Distribution;

 

(n)                                  reference to any agreement, instrument or other document means such agreement, instrument or other document as amended, supplemented and modified from time to time to the extent permitted by the provisions thereof and not prohibited by this Agreement;

 

(o)                                  reference to any Law (including statutes and ordinances) means such Law (including any and all rules and regulations promulgated thereunder) as amended, modified, codified or reenacted, in whole or in part, and in effect at the time of determining compliance or applicability;

 

(p)                                  references to any Person include such Person’s successors and assigns but, if applicable, only if such successors and assigns are permitted by this Agreement; a reference to such Person’s “Affiliates” shall be deemed to mean such Person’s Affiliates following the Initial Distribution and any reference to a third party shall be deemed to mean a Person who is not a Party or an Affiliate of a Party;

 

(q)                                  if there is any conflict between the provisions of the main body of this Agreement and the Schedules hereto, the provisions of the main body of this Agreement shall control unless explicitly stated otherwise in such Schedule;

 

(r)                                     unless otherwise specified in this Agreement, all references to dollar amounts herein shall be in respect of lawful currency of the U.S.;

 

(s)                                    the titles to Articles and headings of Sections contained in this Agreement, in any Schedule and exhibit and in the table of contents to this Agreement have been inserted for convenience of reference only and shall not be deemed to be a part of or to affect the meaning or interpretation of this Agreement; and

 

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(t)                                     any portion of this Agreement obligating a Party to take any action or refrain from taking any action, as the case may be, shall mean that such Party shall also be obligated to cause its relevant Subsidiaries to take such action or refrain from taking such action, as the case may be.

 

ARTICLE III
ASSIGNMENT OF EMPLOYEES

 

Section 3.1                                     Active Employees .

 

(a)                                  CRC Group Employees .   Except as otherwise set forth in this Agreement, effective not later than immediately prior to the Effective Time, the employment of each individual (i) who is employed by CRC or a Subsidiary of CRC as of immediately prior to the Effective Time or (ii) whose employment duties are to be exclusively related to the CRC Business immediately following the Effective Time (collectively, the “ CRC Group Employees ”) shall continue with a member of the CRC Group or shall be assigned and transferred to a member of the CRC Group (in each case, with such member as determined by CRC). Each of the Parties agrees to execute, and to seek to have the applicable employees execute, such documentation, if any, as may be necessary to reflect such assignments and transfers.

 

(b)                                  OPC Group Employees .   Except as otherwise set forth in this Agreement, effective not later than immediately prior to Effective Time, the employment of each individual who is employed by a member of the OPC Group and is not a CRC Group Employee (collectively, the “ OPC Group Employees ”) shall continue with a member of the OPC Group or shall be assigned and transferred to a member of the OPC Group (in each case as determined by OPC). Each of the Parties agrees to execute, and to seek to have the applicable employees execute, such documentation, if any, as may be necessary to reflect such assignments and transfers.

 

(c)                                   At-Will Status .   Notwithstanding the above or any other provision of this Agreement, nothing in this Agreement shall create any obligation on the part of any member of the OPC Group or any member of the CRC Group to (i) continue the employment of any Employee or permit the return from a leave of absence for any period following the date of this Agreement or the Distribution Date (except as required by applicable Law) or (ii) change the employment status of any Employee from “at will,” to the extent such Employee is an “at will” employee under applicable Law.

 

(d)                                  Separation from Service .   The Parties acknowledge and agree that the Distribution and the assignment, transfer or continuation of the employment of Employees as contemplated by this Section 3.1 (i) shall not be deemed a “separation from service” (as defined in Section 409A of the Code) of any Employee for purposes of this Agreement or any Benefit Plan of any member of the OPC Group or any member of the CRC Group but (ii) shall, with respect to CRC Group Employees and for purposes of the OPC Defined Contribution Plans, constitute a “severance from employment” (as described in Section 401(k)(2)(B) of the Code).

 

(e)                                   Not a Change of Control/Change in Control .   The Parties acknowledge and agree that neither the consummation of the Distribution nor any transaction in connection

 

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with the Distribution shall be deemed a “change of control,” “change in control,” or term of similar import for purposes of any Benefit Plan of any member of the OPC Group or any member of the CRC Group.

 

(f)                                    Payroll and Related Taxes .  OPC and CRC hereby agree to follow the standard procedure for U.S. employment tax withholding as provided in Section 4 of Rev. Proc. 2004-53, I.R.B. 2004-34.  Without limiting the generality of the foregoing, with respect to each CRC Group Employee, OPC and CRC shall, and shall cause their respective Affiliates to (to the extent permitted by applicable Law and practicable) (i) treat CRC (or the applicable CRC Entity) as a “successor employer” and OPC (or the applicable OPC Entity) as a “predecessor,” within the meaning of Sections 3121(a)(1) and 3306(b)(1) of the Code, to the extent appropriate, for purposes of taxes imposed under the U.S. Federal Insurance Contributions Act, as amended (“ FICA ”), or the U.S. Federal Unemployment Tax Act, as amended (“ FUTA ”), and (b) cooperate with each other to avoid, to the extent possible, the restart of FICA and FUTA upon or following the Effective Time with respect to each CRC Group Employee for the tax year during which the Effective Time occurs.

 

(g)                                   Employment Contracts; Expatriate Obligations .  Effective as of the Effective Time, CRC will assume and honor, or will cause a member of the CRC Group to assume and honor, any agreements to which any CRC Group Employee is party with any OPC Entity, including any (i) employment contract, executive agreement, offer letter, indemnification or consulting agreement, (ii) retention, severance or change of control arrangement or (iii) expatriate or relocation contract or arrangement (including agreements and obligations regarding repatriation, relocation, equalization of taxes and living standards in the host country).

 

(h)                                  Collective Bargaining Agreements .   Schedule 3.1(h) sets forth a list of collective bargaining agreements, collective agreements, trade union or works council agreements and any other contractual or other obligation to a labor union, trade union, works council or other representative of any CRC Group Employee relating to the CRC Group Employees in effect on the date of this Agreement (collectively, the “ Collective Bargaining Agreements ”). Prior to the Effective Time, OPC and CRC will take or cause to be taken all actions necessary (if any) to cause a CRC Entity to continue sponsorship of the Collective Bargaining Agreements. Nothing in this Agreement is intended to alter the provisions of any Collective Bargaining Agreement or modify in any way the obligations owed to the Employees covered by any such agreement.

 

Section 3.2                                     Employment Law Obligations .

 

(a)                                  WARN .   After the Effective Time, (i) OPC shall be responsible for providing any necessary WARN notice and satisfying WARN obligations with respect to any termination of employment of any OPC Group Employee that occurs after the Effective Time and (ii) CRC shall be responsible for providing any necessary WARN notice and satisfying WARN obligations with respect to any termination of employment of any CRC Group Employee that occurs after the Effective Time.

 

(b)                                  Compliance With Employment Laws . With respect to the time period occurring on and after the Effective Time (i) each member of the OPC Group shall be

 

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responsible for adopting and maintaining any policies or practices, and for all other actions and inactions, necessary to comply with employment-related Laws and requirements relating to the employment of OPC Group Employees and the treatment of any applicable Former OPC Group Employees in respect of their employment, and (ii) each member of the CRC Group shall be responsible for adopting and maintaining any policies or practices, and for all other actions and inactions, necessary to comply with employment-related Laws and requirements relating to the employment of CRC Group Employees and the treatment of any applicable Former CRC Group Employees in respect of their employment.

 

Section 3.3                                     Employee Records .

 

(a)                                  Sharing of Information .   Subject to any limitations imposed by applicable Law, OPC and CRC (acting directly or through members of the OPC Group or the CRC Group, respectively) shall provide to the other and their respective agents and vendors all information reasonably necessary for the Parties to perform their respective duties under this Agreement. The Parties also hereby agree to enter into any business associate arrangements that may be required for the sharing of any information pursuant to this Agreement to comply with the requirements of HIPAA.

 

(b)                                  Transfer of Personnel Records and Authorization .  Subject to any limitations imposed by applicable Law, as soon as administratively feasible following the Distribution Date, OPC shall transfer and assign to CRC all personnel records, all immigration documents, including I-9 forms and work authorizations, all payroll deduction authorizations and elections, whether voluntary or mandated by Law, including but not limited to W-4 forms and deductions for benefits under the applicable CRC Benefit Plans and all absence management records, Family and Medical Leave Act and employee leave records, insurance beneficiary designations, flexible spending account enrollment confirmations, attendance, and return to work information (“ Benefit Management Records ”).  Subject to any limitations imposed by applicable Law, OPC, however, may retain originals of, copies of, or access to Benefit Management Records as long as necessary to provide services to CRC (acting pursuant to the Transition Services Agreement).  CRC will use Benefit Management Records for lawful purposes only, including calculation of withholdings from wages and personnel management.  It is understood that following the Distribution Date, OPC records so transferred and assigned may be maintained by CRC (acting directly or through one of its Subsidiaries) pursuant to CRC’s applicable records retention policy.

 

(c)                                   Access to Records .   To the extent not inconsistent with this Agreement and any applicable Laws, reasonable access to Employee-related records after the Distribution Date will be provided to members of the OPC Group and members of the CRC Group pursuant to the terms and conditions of Article VII of the Separation Agreement. In addition, notwithstanding anything to the contrary, CRC shall provide OPC with reasonable access to those records necessary for its administration of any plans or programs on behalf of OPC Group Employees and Former OPC Group Employees after the Distribution Date as permitted by any applicable Laws. OPC shall also be permitted to retain copies of all restrictive covenant agreements with any CRC Group Employee in which any member of the OPC Group has a valid business interest. In addition, OPC shall provide CRC with reasonable access to those records necessary for its administration of any plans or programs on behalf of CRC Group Employees and Former CRC

 

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Group Employees after the Distribution Date as permitted by any applicable Laws. CRC shall also be permitted to retain copies of all restrictive covenant agreements with any OPC Group Employee or Former OPC Group Employee in which any member of the CRC Group has a valid business interest.

 

(d)                                  Maintenance of Records .   With respect to retaining, destroying, transferring, sharing, copying and permitting access to all Employee-related information, OPC and CRC shall comply with all applicable Laws and shall indemnify and hold harmless each other from and against any and all Liability, claims, actions, and damages that arise from a failure (by the indemnifying party or its Subsidiaries or their respective agents) to so comply with all applicable Laws applicable to such information.

 

(e)                                   No Access to Computer Systems or Files .   Except as set forth in the Separation Agreement or any Transfer Document, no provision of this Agreement shall give (i) any member of the OPC Group direct access to the computer systems or other files, records or databases of any member of the CRC Group or (ii) any member of the CRC Group direct access to the computer systems or other files, records or databases of any member of the OPC Group, unless specifically permitted by the owner of such systems, files, records or databases.

 

(f)                                    Confidentiality .   The provisions of this Section 3.3 shall be in addition to, and not in derogation of, the provisions of the Separation Agreement governing confidential information, including Section 7.7 of the Separation Agreement. Except as otherwise set forth in this Agreement, all records and data relating to Employees shall, in each case, be subject to the confidentiality provisions of the Separation Agreement and any other applicable agreement and applicable Law.

 

(g)                                   Cooperation .   Each Party shall use commercially reasonable efforts to cooperate to share, retain, and maintain data and records that are necessary or appropriate to further the purposes of this Section 3.3 and for each Party to administer its respective Benefit Plans to the extent consistent with this Agreement and applicable Law, and each Party agrees to cooperate as long as is reasonably necessary to further the purposes of this Section 3.3 . Except as provided under any Transfer Document, no Party shall charge another Party a fee for such cooperation.

 

ARTICLE IV
EQUITY AND LONG-TERM INCENTIVE AWARDS(1)

 

Section 4.1                                     General Principles .

 

(a)                                  Additional Actions .  OPC and CRC shall take any and all reasonable actions as shall be necessary and appropriate to further the provisions of this Article IV , including, to the extent practicable, providing written notice or similar communication to each individual who holds one or more awards granted under any of the OPC Equity Plans informing

 


(1)   NTD : Article IV to be revised to address outstanding phantom stock awards under the OPC Phantom Share Unit Award Plan.  CRC will assume liability with respect to all such awards held by CRC Group Employees.

 

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such individual of (i) the actions contemplated by this Article IV with respect to such awards and (ii) whether (and during what time period) any “blackout” period shall be imposed upon holders of awards granted under any of the OPC Equity Plans during which time awards may not be exercised or settled, as the case may be.

 

(b)                                  Service Recognition; Change of Control .  From and after the Initial Distribution, (i) a grantee who has outstanding awards under one or more of the OPC Equity Plans and/or replacement awards under the CRC New Equity Plan shall be considered to have been employed by (or otherwise providing services to) the applicable plan sponsor before and after the Initial Distribution for purposes of (x) vesting and (y) determining the date of termination of employment (or any other applicable service relationship) as it applies to any such award and (ii) for purposes of determining whether any “change of control” has occurred with respect to any OPC LTI Award or CRC LTI Award, (x) a “change of control” shall only be deemed to have occurred for purposes of any award that is governed by the OPC Equity Plans upon a “change of control” of OPC and (y) a “change of control” shall only be deemed to have occurred for purposes of any award that is governed by the CRC New Equity Plan upon a “change of control” of CRC .

 

(c)                                   Consistency with Applicable Laws No award described in this Article IV , whether outstanding or to be issued, adjusted, substituted or cancelled by reason of or in connection with the Initial Distribution, shall be adjusted, settled, cancelled, or exercisable, until in the judgment of the administrator of the applicable plan or program such action is consistent with all applicable Laws, including federal securities Laws. Any period of exercisability will not be extended on account of a period during which such an award is not exercisable pursuant to the preceding sentence.

 

(d)                                  ASC 718 .  [The adjustment or conversion of OPC LTI Awards pursuant to this Article IV is intended to be effectuated in a manner so as to result in each Adjusted OPC LTI Award or CRC LTI Award, as applicable, having an aggregate “fair value” and an “intrinsic value” (in each case, within the meaning of ASC 718 and determined in accordance therewith), as of immediately following the Initial Distribution, that shall not be materially greater than the fair value and intrinsic value of the related OPC LTI Award immediately prior to the Initial Distribution.]

 

(e)                                   Section 409A of the Code .  The adjustment or conversion of OPC LTI Awards shall be effectuated in a manner that is intended to avoid the imposition of any penalty or other taxes on the holders thereof pursuant to Section 409A of the Code.

 

Section 4.2                                     Restricted Stock .

 

(a)                                  OPC Directors .  Each OPC Director who is the holder of outstanding OPC RSAs immediately prior to the Effective Time (which awards are vested but subject to transfer restrictions), shall receive, upon the Initial Distribution being made, such number of shares of CRC Common Stock as determined by applying the Distribution Ratio in the same way as if such outstanding OPC RSAs were fully vested and transferrable shares of OPC Common Stock as of the Effective Time. The shares of CRC Common Stock so distributed to such OPC Director shall be subject to substantially the same terms and conditions (including transfer restrictions)

 

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immediately following the Effective Time as applicable to the OPC RSAs held by such OPC Director immediately prior to the Effective Time.

 

(b)                                  CRC Employees .  Rather than participate in the Initial Distribution, each OPC RSA that is outstanding, unvested and held by a CRC Group Employee as of immediately prior to the Effective Time (a “ CRC Employee RSA ”) shall be cancelled upon the Effective Time and such holder shall be entitled to receive as soon as practicable following the Effective Time, a number of restricted shares of CRC Common Stock under the CRC New Equity Plan equal to the CRC Share Number (a “ CRC RSA ”).  Each CRC RSA described in the preceding sentence shall be subject to substantially the same terms and conditions after the Effective Time as the terms and conditions applicable to the corresponding CRC Employee RSA immediately prior to the Effective Time (including vesting); provided, however, that from and after the Effective Time, (i) any time-based vesting conditions applicable to the CRC RSA shall be determined based solely upon continued service with the CRC Group rather than the OPC Group and (ii) if the CRC Employee RSA was subject to performance-based vesting conditions immediately prior to the Effective Time, then the CRC RSA shall include such performance-based vesting conditions, if any, as may be determined by the OPC Committee in its sole discretion (which performance-based vesting conditions may be applicable to some recipients of CRC RSAs and not other such recipients).

 

(c)                                   Other Holders .  Rather than participate in the Initial Distribution, each OPC RSA that is outstanding, unvested and held by any Person other than an OPC Director or CRC Group Employee as of immediately prior to the Effective Time (an “ OPC Employee RSA ”) shall, following the Effective Time, remain outstanding and the holder thereof shall receive, in lieu of any shares of CRC Common Stock otherwise distributable in respect of such OPC Employee RSA upon the Initial Distribution, an additional OPC RSA (the “ Additional OPC RSAs ”) with respect to a number of shares of OPC Common Stock equal to (i) (x) the number of shares with respect to such OPC Employee RSA which are outstanding and unvested as of immediately prior to the Effective Time multiplied by (y) the OPC Equity Award Ratio (which product shall be rounded up to the nearest whole share of OPC Common Stock), minus (ii) the number of shares with respect to such OPC Employee RSA which are outstanding and unvested as of immediately prior to the Effective Time.  Each Additional OPC RSA shall be granted under the same terms and conditions as the related OPC Employee RSA.  Following the Effective Time, each OPC Employee RSA and Additional OPC RSA related thereto shall remain subject to the same terms and conditions as applicable to such OPC Employee RSA prior to the Effective Time.

 

Section 4.3                                     Stock Appreciation Rights .

 

(a)                                  CRC Employees .  Each OPC SAR, whether or not exercisable, that is outstanding and held by a CRC Group Employee as of immediately prior to the Effective Time (a “ CRC Employee SAR ”) shall, upon the Effective Time, be converted into a stock appreciation right granted under the CRC New Equity Plan with respect to a number of shares of CRC Common Stock equal to the CRC Share Number (a “ CRC SAR ”) with a grant price per share of CRC Common Stock equal to (i) the grant price of the relevant OPC SAR as of the Effective Time divided by (ii) the CRC Equity Award Ratio, rounded up to the nearest whole cent.  Each CRC SAR described in the preceding sentence shall be subject to the same terms and conditions

 

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after the Effective Time as the terms and conditions applicable to the corresponding CRC Employee SAR immediately prior to the Effective Time (including vesting); provided, however, that from and after the Effective Time, the vesting and exercisability of each CRC SAR shall be determined based upon continued service with the CRC Group rather than the OPC Group.

 

(a)                                  Other Holders .  Each OPC SAR, whether or not exercisable, that is outstanding and held by any Person other than a CRC Group Employee as of immediately prior to the Effective Time (an “ OPC Employee SAR ”) shall, upon the Effective Time, be adjusted such that (i) the number of shares of OPC Common Stock subject to such OPC Employee SAR is the Adjusted OPC Share Number (following such adjustment, the OPC Employee SAR shall be an “ Adjusted OPC SAR ”) and (ii) the per share grant price of such Adjusted OPC SAR is equal to (x) the grant price of the relevant OPC SAR as of the Effective Time divided by (y) the OPC Equity Award Ratio, rounded up to the nearest whole cent.  Other than as described in the preceding sentence, following the Effective Time the Adjusted OPC SAR shall remain subject to the same terms and conditions as applicable to the OPC Employee SAR prior to the Effective Time.

 

Section 4.4                                     OPC LTI Mixed-Settlement Units .

 

(a)                                  CRC Employees .   Each OPC LTI Mixed-Settlement Unit that is outstanding, unvested and held by a CRC Group Employee as of immediately prior to the Effective Time (a “ CRC Employee Mixed-Settlement Unit ”) shall, upon the Effective Time, be converted into an award of incentive units granted under the CRC New Equity Plan with respect to a number of shares of CRC Common Stock equal to the CRC Share Number (a “ CRC MSU ”).  Each CRC MSU described in the preceding sentence shall be subject to substantially the same terms and conditions after the Effective Time as the terms and conditions applicable to the corresponding CRC Employee Mixed-Settlement Unit immediately prior to the Effective Time (including vesting and the form of settlement (except that CRC Common Stock shall be substituted for OPC Common Stock)); provided, however, that from and after the Effective Time, the vesting of each CRC MSU shall be determined based upon continued service with the CRC Group rather than the OPC Group.

 

(b)                                  Other Holders .  Each OPC LTI Mixed-Settlement Unit that is outstanding and held by any Person other than a CRC Group Employee as of immediately prior to the Effective Time (an “ OPC Employee Mixed-Settlement Unit ”) shall, upon the Effective Time, be adjusted such that the number of shares of OPC Common Stock subject to such OPC LTI Mixed-Settlement Unit is the Adjusted OPC Share Number (such adjusted OPC LTI Mixed-Settlement Unit, an “ Adjusted OPC MSU ”).  Other than as described in the preceding sentence, following the Effective Time the Adjusted OPC MSU shall remain subject to the same terms and conditions as applicable to the OPC LTI Mixed-Settlement Unit prior to the Effective Time.

 

Section 4.5                                     Restricted Stock Units .

 

(a)                                  CRC Directors .   Each OPC DRSU that is outstanding and held by a CRC Director as of immediately prior to the Effective Time (a “ CRC Director DRSU ”) shall, upon the Effective Time, be converted into a restricted stock unit granted under the CRC New Equity Plan with respect to a number of shares of CRC Common Stock equal to the CRC Share Number (a

 

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CRC DRSU ”).  Each CRC DRSU described in the preceding sentence shall be subject to the same terms and conditions after the Effective Time as the terms and conditions applicable to the corresponding CRC Director DRSU immediately prior to the Effective Time.

 

(b)                                  OPC Directors .  Each OPC DRSU that is outstanding and held by an individual other than a CRC Director as of immediately prior to the Effective Time (an “ OPC Director DRSU ”) shall, upon the Effective Time, be adjusted such that the number of shares of OPC Common Stock subject to such OPC Director DRSU is the Adjusted OPC Share Number (an “ Adjusted OPC DRSU ”).  Other than as described in the preceding sentence, following the Effective Time the Adjusted OPC DRSU shall remain subject to the same terms and conditions as applicable to the OPC DRSU prior to the Effective Time.

 

(c)                                   CRC Employees .  Each OPC RSU that is outstanding and held by a CRC Group Employee as of immediately prior to the Effective Time (a “ CRC Employee RSU ”) shall, upon the Effective Time, be terminated at the Effective Time with the holder thereof entitled to receive, as soon as practicable following the Effective Time, (i) a number of CRC RSAs granted pursuant to the CRC New Equity Plan equal to the CRC Share Number and (ii) a payment from CRC with respect to any cash dividend equivalents that have accrued under such CRC Employee RSU and which remain unpaid as of the Effective Time (which payment shall (x) be determined based upon the level of performance assumed for purposes of determining the related CRC Share Number and (y) occur in no event later than March 15 of the calendar year following the calendar year in which the Effective Time occurs).  Other than as described in the preceding sentence, following the Effective Time, the CRC RSAs shall remain subject to substantially the same terms and conditions as applicable to the CRC Employee RSU prior to the Effective Time (including vesting); provided, however that (A) if the CRC Employee RSU was subject to both time-based and performance-based vesting conditions immediately prior to the Effective Time, then from and after the Effective Time the vesting of such CRC RSAs shall continue to be subject to the time-based vesting conditions based upon continued service with the CRC Group and such CRC RSAs shall include such performance-based vesting conditions, if any, as may be determined by the OPC Committee in its sole discretion (which performance-based vesting conditions may be applicable to some recipients of such CRC RSAs and not other such recipients), and (B) such CRC RSAs shall have such other rights as are generally applicable to other CRC RSAs (including, without limitation, any such rights relating to voting and dividends).

 

(d)                                  Other Holders .  Each OPC RSU that is outstanding and held by any Person other than a CRC Group Employee as of immediately prior to the Effective Time (an “ OPC Employee RSU ”) shall, upon the Effective Time, be adjusted such that the number of shares of OPC Common Stock subject to such OPC RSU is the Adjusted OPC Share Number (such adjusted OPC RSU, an “ Adjusted OPC RSU ”).  Other than as described in the preceding sentence, following the Effective Time the Adjusted OPC RSU shall remain subject to the same terms and conditions as applicable to the OPC RSU prior to the Effective Time .

 

Section 4.6                                     Long-Term Incentive Cash-Based and Cash-Settled Awards .

 

(a)                                  CRC Employees .   Each OPC LTI Cash Award that is outstanding and held by a CRC Group Employee as of immediately prior to the Effective Time (a “ CRC Employee

 

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LTI Cash Award ”) shall, upon the Effective Time, be terminated at the Effective Time with the holder thereof entitled to receive, as soon as practicable following the Effective Time, a number of time-vested CRC RSAs granted pursuant to the CRC New Equity Plan equal to the quotient obtained by dividing (i) the target incentive amount applicable to such CRC Employee LTI Cash Award (provided, however, that if there is less than 12 months remaining in the performance period applicable to such CRC Employee LTI Cash Award, then the amount determined under this clause (i) shall be equal to the amount that would be payable under such CRC Employee LTI Cash Award based upon attainment of Actual LTI Performance), by (ii) the CRC Stock Value.  Following the Effective Time, (x) the time-based vesting conditions applicable to the CRC Employee LTI Cash Award immediately prior to the Effective Time shall continue to apply to the CRC RSAs issued in accordance with the preceding sentence based solely upon continued service with the CRC Group rather than the OPC Group, (y) such CRC RSAs shall include such performance-based vesting conditions, if any, as may be determined by the OPC Committee in its sole discretion (which performance-based vesting conditions may be applicable to some recipients of such CRC RSAs and not other such recipients), and (z) such CRC RSAs shall have such other rights as are generally applicable to other CRC RSAs (including, without limitation, any such rights relating to voting and dividends).

 

(b)                                  Other Holders Each OPC LTI Cash Award that is outstanding and held by any Person other than a CRC Group Employee as of immediately prior to the Effective Time shall remain subject to the same terms and conditions as were applicable to such OPC LIP Cash Award prior to the Effective Time.

 

Section 4.7                                     Section 16(b) of the Securities Exchange Act; Code Sections 162(m) and 409A .

 

(a)                                  Section 16(b) of the Securities Exchange Act .  By approving the adoption of this Agreement, the respective Boards of Directors of each of OPC and CRC intend to exempt from the short-swing profit recovery provisions of Section 16(b) of the Securities Exchange Act of 1934, as amended, by reason of the application of Rule 16b-3 thereunder, all acquisitions and dispositions of equity incentive awards by directors and officers of each of the OPC Group and the CRC Group, and the respective Boards of Directors of OPC and CRC also intend expressly to approve, in respect of any equity-based award, the use of any method for the payment of an exercise price and the satisfaction of any applicable tax withholding (specifically including the actual or constructive tendering of shares in payment of an exercise price and the withholding of award shares from delivery in satisfaction of applicable tax withholding requirements) to the extent such method is permitted under the applicable OPC Equity Plan, CRC New Equity Plan and award agreement.

 

(b)                                  Code Sections 162(m) and 409A .  Notwithstanding anything in this Agreement to the contrary (including the treatment of supplemental and deferred compensation plans, outstanding long-term incentive awards and annual incentive awards as described herein), OPC and CRC agree to negotiate in good faith regarding the need for any treatment different from that otherwise provided herein to ensure that (i) a federal income tax deduction for the payment of such supplemental or deferred compensation or long-term incentive award, annual incentive award or other compensation is, to the extent prescribed under the terms of the applicable plan and award agreement, not limited by reason of Section 162(m) of the Code, and

 

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(ii) the treatment of such supplemental or deferred compensation or long-term incentive award, annual incentive award or other compensation does not cause the imposition of a penalty tax under Section 409A of the Code.

 

Section 4.8                                     Liabilities for Settlement of Awards .  Except as provided for pursuant to Section 4.10 , from and after the Effective Time (a) OPC shall be responsible for all Liabilities associated with OPC LTI Awards, including any exercise, share delivery, registration or other obligations related to the exercise, vesting or settlement of the OPC LTI Awards and (b) CRC shall be responsible for all Liabilities associated with CRC LTI Awards, including any exercise, share delivery, registration or other obligations related to the exercise, vesting or settlement of the CRC LTI Awards.

 

Section 4.9                                     Form S-8 .  Upon or as soon as reasonably practicable after the Effective Time and subject to applicable Law, CRC shall prepare and file with the Securities and Exchange Commission a registration statement on Form S-8 (or another appropriate form) registering under the Securities Act of 1933, as amended, the offering of a number of shares of CRC Common Stock at a minimum equal to the number of shares subject to the CRC LTI Awards.  CRC shall use commercially reasonable efforts to cause any such registration statement to be kept effective (and the current status of the prospectus or prospectuses required thereby to be maintained) as long as any CRC LTI Awards remain outstanding.

 

Section 4.10                              Tax Reporting and Withholding for Awards .  OPC (or one of its Subsidiaries) will be responsible for all income, payroll, or other tax reporting related to income of Persons from equity-based and other long-term incentive awards outstanding pursuant to the OPC Equity Plans, and CRC (or one of its Subsidiaries) will be responsible for all income, payroll, or other tax reporting related to income of Persons from equity-based and other long-term incentive awards granted under the CRC New Equity Plan. Further, OPC (or one of its Subsidiaries) shall be responsible for remitting applicable tax withholdings for Persons who hold equity-based and other long-term incentive awards outstanding pursuant to the OPC Equity Plans to each applicable taxing authority, and CRC (or one of its Subsidiaries) shall be responsible for remitting applicable tax withholdings for Persons who hold equity-based and other long-term incentive awards granted under the CRC New Equity Plan to each applicable taxing authority.  OPC and CRC acknowledge and agree that the Parties will cooperate with each other and with third-party providers to effectuate withholding and remittance of taxes, as well as required tax reporting, in a timely, efficient, and appropriate manner.

 

Section 4.11                              Approval of CRC New Equity Plan and CRC ESPP .  Not later than the Effective Time, CRC shall, or shall have caused a CRC Entity to, have adopted the CRC New Equity Plan and the CRC ESPP. The CRC New Equity Plan and the CRC ESPP shall each be approved prior to the Effective Time by the member of the OPC Group that is the sole shareholder of CRC at the time of such approval.

 

ARTICLE V
BONUS AND SHORT-TERM INCENTIVE PLANS

 

Section 5.1                                     Establishment of CRC Short- Term Incentive Plans .  Not later than the Effective Time, CRC shall, or shall cause another CRC Entity to, adopt one or more plans that

 

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will provide annual bonus and short-term cash incentive compensation opportunities for CRC Group Employees (the “ CRC Short-Term Incentive Plans ”), subject to CRC’s right to amend each such plan after the Effective Time in accordance with the terms thereof.

 

Section 5.2                                     Treatment of Short-Term Incentives for Year of Initial Distribution .  From and after the Effective Time, CRC Group Employees and Former CRC Group Employees shall cease participation in the annual bonus and short-term cash incentive compensation opportunities under the OPC Short-Term Incentive Plans and shall, for the avoidance of doubt, not be entitled to any benefits thereunder for the year in which the Distribution Date occurs.  [With respect to the year in which the Distribution Date occurs, CRC shall, or shall cause another CRC Entity to, provide each CRC Group Employee and Former CRC Group Employee who participated in an OPC Short-Term Incentive Plan and otherwise meets all service-based and other requirements to receive an award under a CRC Short-Term Incentive Plan, with an annual bonus payment under the appropriate CRC Short-Term Incentive Plan determined based upon (a) the Distribution Year Blended Performance, in the event the Distribution Date occurs on or prior to October 1 st  of such year, or (b) the performance of OPC under the applicable OPC Short-Term Incentive Plan for the entire year in which the Distribution Date occurs (“ OPC Full Year Performance ) , in the event the Distribution Date occurs on or after October 2 nd of such year.  As soon as practicable, and in no event later than sixty (60) days following the end of the year in which the Distribution Date occurs, OPC shall inform CRC in writing of either (i) the component of the Distribution Year Blended Performance which relates to the performance of OPC on and prior to the [last day of the calendar month coincident with or next preceding the] Distribution Date or (ii) the OPC Full Year Performance, as applicable.]

 

Section 5.3                                     Plan Liabilities .  For the avoidance of doubt, (i) the CRC Group shall be solely responsible for funding, paying, and discharging all obligations relating to any annual cash incentive awards that any CRC Group Employee or Former CRC Group Employee is eligible to receive under any CRC Group annual bonus and other short-term incentive compensation plans with respect to payments made beginning at or after the Effective Time, including the CRC Short-Term Incentive Plans, and no member of the OPC Group shall have any obligations with respect thereto, and (ii) the OPC Group shall be solely responsible for funding, paying, and discharging all obligations relating to any annual cash incentive awards that any OPC Group Employee or Former OPC Group Employee is eligible to receive under any OPC annual bonus and other short-term incentive compensation plans with respect to payments made beginning at or after the Effective Time, including the OPC Short-Term Incentive Plans, and no member of the CRC Group shall have any obligations with respect thereto.

 

ARTICLE VI
QUALIFIED DEFINED BENEFIT PLANS

 

Section 6.1                                     Retention of CRC Group Defined Benefit Plans .  At or prior to the Effective Time, CRC shall take all actions necessary (if any) to provide for the retention by the applicable CRC Entity of the sponsorship of each CRC Group Defined Benefit Plan.  Except as expressly set forth in Section 6.2 , from and after the Effective Time (a) the CRC Group shall be solely responsible for (and shall indemnify and hold harmless the OPC Group from) all Liabilities and obligations pursuant to the CRC Group Defined Benefit Plans (regardless of whether such Liabilities relate to a CRC Group Employee, Former CRC Group Employee, OPC

 

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Group Employee or Former OPC Group Employee) and (b) OPC Group Employees shall cease active participation in all CRC Group Defined Benefit Plans.

 

Section 6.2                                     Transfer of Assets .  As soon as practicable and in no event later than 60 days following the Effective Time, CRC shall, or shall cause a CRC Entity to, establish one or more trusts which relate to the THUMS Pension Plan and are exempt from taxation under Section 501(a) of the Code (together, the “ CRC Pension Trust ”).  No later than 60 days following the establishment of the CRC Pension Trust, OPC shall, or shall cause the appropriate OPC Entity to, cause the OPC Master Trust to transfer all Assets in the OPC Master Trust which are held for purposes of providing benefits pursuant to the THUMS Pension Plan (the “ CRC Pension Assets ”) to the CRC Pension Trust (the date of such transfer, the “ Pension Transfer Date ”).  The transfer of the CRC Pension Assets shall be in the form of cash or such other Assets as may be selected by the appropriate fiduciary of the OPC Master Trust in its sole discretion.  Through and including the Pension Transfer Date, OPC shall remain primarily responsible for causing benefits due under the THUMS Pension Plan through such date to be paid from the OPC Master Trust, with any such benefits paid reducing the CRC Pension Assets.  In connection with the transfer of CRC Pension Assets, the Parties (each acting directly or through their respective Affiliates) shall, to the extent necessary, file Internal Revenue Service Form 5310-A regarding the transfer of CRC Pension Assets from the OPC Master Trust to the CRC Pension Trust as provided in this Section 6.2 .

 

Section 6.3                                     OPC Defined Benefit Plans . From and after the Effective Time, CRC Group Employees shall cease active participation in all OPC Defined Benefit Plans, and shall not accrue credit for any purposes under the OPC Defined Benefit Plans with respect to service with the CRC Group after the Effective Time.  The applicable OPC Entities shall retain sponsorship of the OPC Defined Benefit Plans, and each OPC Defined Benefit Plan shall retain all Liabilities with respect to all benefits accrued thereunder (including with respect to CRC Group Employees and Former CRC Group Employees).

 

ARTICLE VII
QUALIFIED DEFINED CONTRIBUTION PLANS

 

Section 7.1                                     Retention of CRC Existing Defined Contribution Plans .  At or prior to the Effective Time, CRC shall take all actions necessary (if any) to provide for the retention by the applicable CRC Entity of the sponsorship of each CRC Existing Defined Contribution Plan.  From and after the Effective Time (a) the CRC Group shall be solely responsible for (and shall indemnify and hold harmless the OPC Group from) all Liabilities and obligations pursuant to the CRC Existing Defined Contribution Plans (regardless of whether such Liabilities relate to a CRC Group Employee, Former CRC Group Employee, OPC Group Employee or Former OPC Group Employee) and (b) OPC Group Employees shall cease active participation in all CRC Existing Defined Contribution Plans.

 

Section 7.2                                     Establishment of the CRC Defined Contribution Plans .  As of the Effective Time, CRC shall, or shall cause another CRC Entity to, establish one or more qualified defined contribution plans and trusts for the benefit of CRC Group Employees who were eligible to participate in the OPC Defined Contribution Plans (the “ CRC Defined Contribution Plans ”), at least one of which provides for a cash or deferred arrangement under Section 401(k) of the

 

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Code.  CRC shall be responsible for taking all necessary, reasonable, and appropriate action to establish, maintain, and administer the CRC Defined Contribution Plans so that each such plan is qualified under Section 401(a) of the Code and that the related trust thereunder is exempt under Section 501(a) of the Code.  CRC (acting directly or through its Affiliates) shall be responsible for any and all Liabilities and other obligations with respect to the CRC Defined Contribution Plans.

 

Section 7.3                                     Vesting of CRC Employee Accounts .  Effective as of the Effective Time, OPC shall, or shall cause the appropriate OPC Entity to, fully vest each CRC Group Employee in his or her account balance in each OPC Defined Contribution Plan.

 

Section 7.4                                     CRC Group Employee Account Balances .  CRC or the appropriate CRC Entity shall cause the appropriate CRC Defined Contribution Plan to accept the direct rollover of each CRC Group Employee’s account distributed from an OPC Defined Contribution Plan (including any notes representing participant loans); provided , however , that such direct rollover consists solely of cash (other than notes representing participant loans).

 

ARTICLE VIII
NONQUALIFIED DEFERRED COMPENSATION PLANS

 

Section 8.1                                     Retention of CRC Existing Deferred Compensation Plan .  At or prior to the Effective Time, CRC shall take all actions necessary (if any) to provide for the retention by the applicable CRC Entity of the sponsorship of the CRC Existing Deferred Compensation Plan.  From and after the Effective Time (a) the CRC Group shall be solely responsible for (and shall indemnify and hold harmless the OPC Group from) all Liabilities and obligations pursuant to the CRC Existing Deferred Compensation Plan (regardless of whether such Liabilities relate to a CRC Group Employee, Former CRC Group Employee, OPC Group Employee or Former OPC Group Employee) and (b) OPC Group Employees shall cease active participation in the CRC Existing Deferred Compensation Plan.

 

Section 8.2                                     Establishment of CRC Deferred Compensation Plans .  On or prior to the Effective Time, CRC shall, or shall cause another CRC Entity to, establish and adopt one or more deferred compensation plans (the “ CRC Deferred Compensation Plan ”) to provide each CRC Group Employee who was eligible to participate in one or more OPC Deferred Compensation Plans as of immediately prior to the Effective Time (the “ CRC Deferred Compensation Beneficiaries ”) benefits following the Effective Time.  As of the Effective Time, the CRC Group Employees shall no longer participate in the OPC Deferred Compensation Plans.  The Parties agree that, for purposes of the CRC Deferred Compensation Plans, the employment of a CRC Deferred Compensation Beneficiary shall not be considered to have terminated (and, for the avoidance of doubt, such CRC Deferred Compensation Beneficiary shall not be deemed to have incurred a “separation from service”) as a result of the Distribution or the transfer of employment from OPC (or an OPC Entity) to CRC (or a CRC Entity), and such employment shall only be considered to terminate for purposes of the applicable CRC Deferred Compensation Plans when the employment of such CRC Deferred Compensation Beneficiary with the CRC Group terminates in accordance with the terms of the applicable CRC Deferred Compensation Plan and applicable Laws.

 

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Section 8.3            Liability and Responsibility .   The Liabilities in respect of CRC Deferred Compensation Beneficiaries under the OPC Deferred Compensation Plans shall be assumed by the member of the CRC Group which sponsors the applicable CRC Deferred Compensation Plan, effective as of the Effective Time. CRC shall have sole responsibility for the administration of the CRC Deferred Compensation Plans and the payment of benefits thereunder to or on behalf of CRC Group Employees, and no member of the OPC Group shall have any liability or responsibility therefor. OPC shall have sole responsibility for the administration of the OPC Deferred Compensation Plans and the payment of benefits thereunder to or on behalf of OPC Group Employees, Former OPC Group Employees and Former CRC Group Employees, and no member of the CRC Group shall have any liability or responsibility therefor.

 

Section 8.4            Special Provisions Relating to 2005 Deferred Stock Plan .  [At the Effective Time, the number of “Deferred Shares” credited to each “Deferred Share Account” (as each such term is defined in the OPC DSP) under the OPC DSP shall be adjusted such that such number of Deferred Shares (each of which is deemed to represent one share of OPC Common Stock) shall equal the product of (a) the number of Deferred Shares credited to such Deferred Share Account immediately prior to the Effective Time multiplied by (b) the OPC Equity Award Ratio (rounded up to the nearest whole number).  The Parties agree that, for purposes of the OPC DSP, the employment of any CRC Group Employee with an account balance under the OPC DSP as of the Effective Time shall not be considered to have terminated (and, for the avoidance of doubt, such CRC Group Employee shall not be deemed to have a “separation from service”) as a result of the Distribution or the transfer of employment from OPC (or an OPC Entity) to CRC (or a CRC Entity), and such employment shall only be considered to terminate for purposes of the OPC DSP when such CRC Group Employee incurs a “separation from service” (as defined under the OPC DSP in a manner consistent with Section 409A of the Code) with the CRC Group.  OPC shall have sole responsibility for the administration of the OPC DSP and the provision of benefits thereunder to or on behalf of all Employees, and no member of the CRC Group shall have any liability or responsibility therefor; provided, however, that, CRC shall notify OPC in writing no later than 10 days following the date any CRC Group Employee with an account balance under the OPC DSP as of the Effective Time incurs a “separation from service” (as defined under the OPC DSP in a manner consistent with Section 409A of the Code) with the CRC Group.]

 

Section 8.5            [Grantor Trusts .  On or prior to the Effective Time, CRC shall, or shall cause a member of the CRC Group to, adopt a grantor trust (the “ CRC Grantor Trust ”). In connection with the assumption of the Liabilities under the OPC Deferred Compensation Plans in respect of CRC Deferred Compensation Beneficiaries, OPC shall (or shall cause a member of the OPC Group to), as soon as reasonably practicable after the Effective Time), transfer Assets in an amount equal to amounts funded in the OPC [ name of grantor trust ] with respect to CRC Deferred Compensation Beneficiaries (as determined by OPC) as of the Effective Time to the CRC Grantor Trust.  The form of the Asset transfers described in this Section 8.5 shall be in the sole discretion of OPC.]

 

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ARTICLE IX
WELFARE PLANS

 

Section 9.1            Retention of CRC Existing Welfare Plans .  At or prior to the Effective Time, CRC shall take all actions necessary (if any) to provide for the retention by the applicable CRC Entity of the sponsorship of each CRC Existing Welfare Plan.  From and after the Effective Time (a) the CRC Group shall be solely responsible for (and shall indemnify and hold harmless the OPC Group from) all Liabilities and obligations pursuant to the CRC Existing Welfare Plans (regardless of whether such Liabilities relate to a CRC Group Employee, Former CRC Group Employee, OPC Group Employee or Former OPC Group Employee) and (b) OPC Group Employees shall cease active participation in all CRC Existing Welfare Plans.

 

Section 9.2            Establishment of CRC Welfare Plans .  On or prior to the Effective Time, CRC shall, or shall cause another CRC Entity to, establish and adopt Welfare Plans (the “ CRC Welfare Plans ”) which will provide welfare benefits to each CRC Group Employee and Former CRC Group Employee who is, as of the Effective Time, a participant in any of the OPC Welfare Plans (and their eligible spouses and dependents, as the case may be) (collectively, the “ CRC Welfare Plan Participants ”). Coverage and benefits under the CRC Welfare Plans shall then be provided to the CRC Welfare Plan Participants on an uninterrupted basis under the newly established CRC Welfare Plans.  CRC Welfare Plan Participants shall cease to be eligible for coverage under the OPC Welfare Plans at the Effective Time. For the avoidance of doubt, CRC Welfare Plan Participants shall not participate in any OPC Welfare Plans after the Effective Time, and OPC Group Employees and Former OPC Group Employees shall not participate in any CRC Welfare Plans at any time.

 

Section 9.3            Special Provisions Relating to Post-Retirement Welfare Plans .  On or prior to the Effective Time, CRC shall, or shall cause another CRC Entity to, establish and adopt Welfare Plans (the “ CRC Post-Retirement Welfare Plans ”) which will provide post-retirement welfare benefits to each CRC Group Employee who is, as of the Effective Time, eligible to participate in any OPC Post-Retirement Welfare Plan (and their eligible spouses and dependents, as the case may be) (collectively, the “ CRC Post-Retirement Welfare Plan Participants ”).  Former CRC Group Employees who are, as of the Effective Time, receiving or are eligible to receive benefits pursuant to an OPC Post-Retirement Welfare Plan shall, subject to the terms thereof, continue to be covered or be eligible to be covered by such OPC Post-Retirement Welfare Plan and shall not be covered by or be eligible to be covered by any CRC Post-Retirement Welfare Plans.  Notwithstanding any provision herein to the contrary, CRC agrees that the CRC Post-Retirement Welfare Plans, and OPC agrees that the OPC Post-Retirement Welfare Plans, will be operated in accordance with the requirements set forth on Schedule 9.3.

 

Section 9.4            Transitional Matters Under CRC Welfare Plans .

 

(a)           Liability for Claims Incurred .  OPC, a member of the OPC Group, or the applicable OPC Welfare Plan shall be liable for all claims for benefits (other than flexible spending accounts) by CRC Welfare Plan Participants under the OPC Welfare Plans arising out of [claims incurred] on or prior to the Effective Time.  CRC or a member of the CRC Group shall be liable for all other Welfare Plan coverages for CRC Welfare Plan Participants under any

 

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Welfare Plan for which OPC, a member of the OPC Group or the applicable OPC Welfare Plan is not expressly liable, as set forth above.

 

(b)           Credit for Deductibles and Other Limits . [With respect to each CRC Welfare Plan Participant, each CRC Welfare Plan will give credit for the plan year in which the Distribution Date occurs for any amount paid, number of services obtained or provider visits by such CRC Welfare Plan Participant toward deductibles, out-of-pocket maximums, limits on number of services or visits, or other similar limitations to the extent such amounts are taken into account under the corresponding OPC Welfare Plan. For purposes of any life-time maximum benefit limit payable to a CRC Welfare Plan Participant under any CRC Welfare Plan, the CRC Welfare Plan will recognize any expenses paid or reimbursed by an OPC Welfare Plan with respect to such participant prior to the Effective Time to the same extent such expense payments or reimbursements would be recognized in respect of an active plan participant under the applicable OPC Welfare Plan.]

 

(c)           [ COBRA . At and after the Effective Time, CRC shall assume all Liabilities and other obligations under COBRA (and shall provide any required coverage under the CRC Welfare Plans) with respect to all CRC Group Employees and Former CRC Group Employees (and, in either case, their qualifying beneficiaries) who, at such time, were covered under an OPC Welfare Plan pursuant to COBRA or who have a COBRA qualifying event (as defined in Section 4980B of the Code) prior to the Effective Time.]

 

Section 9.5            Benefit Elections and Designations and Continuity of Benefits .

 

(a)           Benefit Elections and Designations . From and after the Effective Time, CRC or the appropriate CRC Entity shall cause each CRC Welfare Plan to recognize and give effect to all elections and designations (including all coverage and contribution elections and beneficiary designations) made by each CRC Welfare Plan Participant under, or with respect to, the corresponding OPC Welfare Plan for the plan year in which the Distribution Date occurs. Notwithstanding the foregoing, nothing in this Section 9.5(a)  will prohibit CRC from soliciting or causing the solicitation of new election forms or beneficiary designations from CRC Welfare Plan Participants to be effective under the CRC Welfare Plan as of the Distribution Date or any time thereafter.

 

(b)           Additional Details Regarding Flexible Spending Accounts . Pursuant to Section 9.2 , at or prior to the Effective Time, CRC shall, or shall cause another CRC Entity to, establish and adopt CRC Welfare Plans which will provide health care flexible spending account and dependent care flexible spending account benefits to CRC Welfare Plan Participants (each a “ CRC FSA ”).

 

(i)            It is the intention of the Parties that all activity under a CRC Welfare Plan Participant’s flexible spending account with OPC for the plan year in which the Distribution Date occurs be treated instead as activity under the corresponding CRC FSA. Accordingly, (x) any period of participation by a CRC Welfare Plan Participant in an OPC flexible spending account during the plan year in which the Distribution Date occurs (the “ FSA Participation Period ”) will be deemed a period when the CRC Welfare Plan Participant participated in the corresponding CRC FSA; (y) all expenses incurred

 

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during the FSA Participation Period will be deemed incurred while the CRC Welfare Plan Participant’s coverage was in effect under the corresponding CRC FSA; and (z) all elections and reimbursements made with respect to an FSA Participation Period under an OPC flexible spending account will be deemed to have been made with respect to the corresponding OPC FSA.

 

(ii)           If the aggregate reimbursement payouts made to CRC Welfare Plan Participants prior to the Effective Time from the applicable OPC Welfare Plan flexible spending accounts during the plan year in which the Distribution Date occurs are less than the aggregate accumulated contributions to such accounts made by such CRC Welfare Plan Participants prior to the Effective Time for such plan year, OPC shall cause an amount equal to the amount by which such contributions are in excess of such reimbursement payouts to be transferred to CRC (or a CRC Entity designated by CRC) by wire transfer of immediately available funds as soon as practicable, but in no event later than 45 days, following the Effective Time.

 

(iii)          If the aggregate reimbursement payouts made to CRC Welfare Plan Participants prior to the Effective Time from the applicable OPC Welfare Plan flexible spending accounts during the plan year in which the Distribution Date occurs exceed the aggregate accumulated contributions to such accounts made by the CRC Welfare Plan Participants prior to the Effective Time for such plan year, CRC shall cause an amount equal to the amount by which such reimbursement payouts are in excess of such contributions to be transferred to OPC (or an OPC Entity designated by OPC) by wire transfer of immediately available funds as soon as practicable, but in no event later than 45 days, following the Effective Time.

 

(iv)          Notwithstanding anything to the contrary in this Section 9.5(b) , at and after the Effective Time, the CRC Group shall assume, and cause the appropriate CRC FSA to be solely responsible for, all claims by CRC Welfare Plan Participants under the applicable OPC Welfare Plan flexible spending accounts that were incurred in the plan year in which the Distribution Date occurs, whether incurred prior to, on, or after the Effective Time, that have not been paid in full as of the Effective Time.

 

(c)           Employer Non-elective Contributions . As of immediately after the Effective Time, CRC shall cause any CRC Welfare Plan that constitutes a “cafeteria plan” under Section 125 of the Code to recognize and give effect to all non-elective employer contributions credited toward coverage of a CRC Welfare Plan Participant under the corresponding OPC Welfare Plan that is a cafeteria plan under Section 125 of the Code for the applicable plan year.

 

(d)           Waiver of Conditions or Restrictions . Unless prohibited by applicable Law or a Collective Bargaining Agreement, the CRC Welfare Plans will waive all limitations as to preexisting conditions, exclusions, service conditions, waiting period limitations or evidence of insurability requirements that would otherwise be applicable to the CRC Welfare Plan Participant following the Effective Time to the extent that such participant had previously satisfied such limitation under the corresponding OPC Welfare Plan.

 

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Section 9.6            Insurance Contracts .  To the extent any OPC Welfare Plan is funded through the purchase of an insurance contract or is subject to any stop loss contract, OPC and CRC will cooperate and use their commercially reasonable efforts to replicate such insurance contracts for CRC (except for design changes and to the extent changes are required under applicable state insurance Laws or filings by the respective insurers) and to maintain any pricing discounts or other preferential terms for both OPC and CRC for a reasonable term. Neither Party shall be liable for failure to obtain such insurance contracts, pricing discounts, or other preferential terms for the other Party. Each Party shall be responsible for any additional premiums, charges, or administrative fees that such Party may incur pursuant to this Section 9.6 .

 

Section 9.7            Third-Party Vendors .  Except as provided below, to the extent any OPC Welfare Plan is administered by a third-party vendor, OPC and CRC will cooperate and use their commercially reasonable efforts to replicate any contract with such third-party vendor for CRC (except for changes agreed to by the Parties) and to maintain any pricing discounts or other preferential terms for both OPC and CRC for a reasonable term. Neither Party shall be liable for failure to obtain such pricing discounts or other preferential terms for the other Party. Each Party shall be responsible for any additional premiums, charges, or administrative fees that such Party may incur pursuant to this Section 9.7 .

 

ARTICLE X
WORKERS’ COMPENSATION AND UNEMPLOYMENT COMPENSATION

 

Section 10.1          CRC Workers’ and Unemployment Compensation Effective as of the Effective Time, (a) the CRC Entity employing each CRC Group Employee shall have (and, to the extent it has not previously had such obligations, such CRC Entity shall assume) the obligations for all claims and Liabilities relating to workers’ compensation and unemployment compensation benefits for all CRC Group Employees employed by that CRC Entity and (b) CRC shall cause a member of the CRC Group to assume all obligations for all claims and Liabilities relating to workers’ compensation and unemployment compensation benefits for all Former CRC Group Employees. Effective as of the Effective Time, CRC, acting through the CRC Entity employing each CRC Group Employee, will be responsible for (a) obtaining workers’ compensation insurance, including providing all collateral required by the insurance carriers and providing all notices to CRC Group Employees required by applicable workers’ compensation Laws and (b) establishing new or transferred unemployment insurance employer accounts, policies and claims handling contracts with the applicable government agencies. To the extent that such unemployment insurance coverage cannot be either assigned to or obtained by CRC or a CRC Entity, in respect of unemployment claims and Liabilities otherwise to be assumed by CRC or a CRC Entity pursuant to this Section 10.1 , OPC shall remain primarily liable for such claims and Liabilities, but CRC shall indemnify and hold harmless OPC for any such claims and Liabilities. If the preceding sentence applies, then at one or more mutually agreed upon dates, OPC shall determine in good faith the present value of such claims and Liabilities and CRC shall reimburse OPC for that amount.

 

Section 10.2          Assignment of Contribution Rights .   OPC will transfer and assign (or cause another member of the OPC Group to transfer and assign) to a member of the CRC Group all rights to seek contribution or damages from any applicable third party (such as a third party

 

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who aggravates an injury to a worker who makes a workers’ compensation claim) with respect to any workers’ compensation claim for which CRC is responsible for pursuant to this Article X .

 

Section 10.3          Collateral .  From and after the Effective Time, CRC (acting directly or through a member of the CRC Group) shall be responsible for providing all collateral required by insurance carriers in connection with workers’ compensation claims for which Liability is allocated to the CRC Group under this Article X .

 

Section 10.4          Cooperation CRC and OPC shall use commercially reasonable efforts to provide that workers’ compensation and unemployment insurance costs are not adversely affected for either of them by reason of the Distribution.

 

ARTICLE XI
SEVERANCE

 

Section 11.1          Establishment of CRC Severance Program .  Effective as of the Effective Time, CRC shall, or shall cause another CRC Entity to, establish and adopt one or more severance plans, policies or arrangements at such levels and subject to such terms as CRC determines in its reasonable discretion.  As of the Effective Time, the CRC Group Employees shall no longer participate in any severance plan, policy or program of the OPC Group.

 

Section 11.2          Liability for Severance .  As of the Effective Time, OPC shall have no Liability or obligation under any OPC Group severance plan or policy with respect to CRC Group Employees or Former CRC Group Employees.

 

ARTICLE XII
BENEFIT ARRANGEMENTS AND OTHER MATTERS

 

Section 12.1          Termination of Participation Except as otherwise provided under this Agreement, effective as of the Effective Time, CRC Group Employees shall cease participation in each OPC Benefit Plan and shall no longer be eligible to participate in any OPC Benefit Plan.

 

Section 12.2          Accrued Time Off .  CRC shall recognize and assume all Liability for all unused vacation, holiday, sick leave, flex days, personal days and paid-time off and other time-off benefits with respect to CRC Group Employees which accrued prior to the Effective Time.

 

Section 12.3          Leaves of Absence .  CRC will continue to apply the appropriate leave of absence policies applicable to inactive CRC Group Employees who are on an approved leave of absence as of the Effective Time. Leaves of absence taken by CRC Group Employees prior to the Effective Time shall be deemed to have been taken as employees of a member of the CRC Group.

 

Section 12.4          Collective Bargaining Agreements .  The OPC Group shall have no Liability for or under any collective bargaining agreements, collective agreements, multiemployer plans, pension and welfare plans and arrangements, labor union, trade union or works council agreements that related to the CRC Business and which were entered into with any member of the OPC Group, any union, works council, or representative of any CRC Group

 

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Employee, and such agreements, plans, and arrangements (if any) shall, to the extent permitted under applicable Law and their respective terms, be assigned from the applicable OPC Entity to CRC (or a CRC Entity designated by CRC) effective as of the Effective Time and CRC shall cooperate in submitting and completing any required successor employer application, or similar application or notice, in order to effectuate any such assignment.

 

Section 12.5          Restrictive Covenants in Employment and Other Agreements .  To the fullest extent permitted by the agreements described in this Section 12.5 and applicable Law, OPC shall assign, or cause an applicable member of the OPC Group to assign (including through notification to employees, as applicable), to CRC or a member of the CRC Group, as designated by CRC, all agreements containing restrictive covenants (including confidentiality, non-competition and non-solicitation provisions) between a member of the OPC Group and a CRC Group Employee, with such assignment to be effective as of the Effective Time. To the extent that assignment of such agreements is not permitted, effective as of the Effective Time, each member of the CRC Group shall be considered to be a successor to each member of the OPC Group for purposes of, and a third-party beneficiary with respect to, all agreements containing restrictive covenants (including confidentiality, non-competition and non-solicitation provisions) between a member of the OPC Group and a CRC Group Employee, such that each member of the CRC Group shall enjoy all the rights and benefits under such agreements (including rights and benefits as a third-party beneficiary), with respect to the business operations of the CRC Group; provided , however , that in no event shall OPC be permitted to enforce such restrictive covenant agreements against CRC Group Employees for action taken in their capacity as employees of a member of the CRC Group.

 

ARTICLE XIII
GENERAL PROVISIONS

 

Section 13.1          Preservation of Rights to Amend .  The rights of each member of the OPC Group and each member of the CRC Group to amend, waive, or terminate any plan, arrangement, agreement, program, or policy referred to herein shall not be limited in any way by this Agreement.

 

Section 13.2          Confidentiality .  Each Party agrees that any information conveyed or otherwise received by or on behalf of a Party in conjunction herewith that is not otherwise public through no fault of such Party is confidential and is subject to the terms of the confidentiality provisions set forth herein and in the Separation Agreement, including Section 3.3(f)  of this Agreement and Section 7.7 of the Separation Agreement.

 

Section 13.3          Administrative Complaints/Litigation .  Except as otherwise provided in this Agreement, from and after the Effective Time, CRC shall assume, and be solely liable for, the handling, administration, investigation, and defense of actions, including ERISA, occupational safety and health, employment standards, union grievances, wrongful dismissal, discrimination or human rights, and unemployment compensation claims asserted at any time against OPC or any member of the OPC Group by (a) any CRC Group Employee or Former CRC Group Employee (including any dependent or beneficiary of any such Employee), (b) any consultant or independent contractor who provided or provides services primarily for the benefit of the CRC Business or (c) any other person to the extent such actions or claims otherwise arise

 

33



 

out of or relate to employment or the provision of services (whether as an employee, contractor, consultant, or otherwise) to or with respect to the business activities of any member of the CRC Group.  Clause (c) of the preceding sentence to the contrary notwithstanding, to the extent that any such legal action is brought by an OPC Group Employee or Former OPC Group Employee and relates to employment or the provision of services with respect to both the business activities of a member of the CRC Group and the business activities of a member of the OPC Group (excluding the CRC Group), reasonable costs and expenses incurred by the Parties in responding to such legal action shall be allocated among the Parties based upon the relative levels of service provided between the CRC Business and the businesses of the OPC Group other than the CRC Business.  Further notwithstanding the foregoing, to the extent that any legal action relates to a putative or certified class of plaintiffs, which includes both OPC Group Employees (or Former OPC Group Employees) and CRC Group Employees (or Former CRC Group Employees) and such action involves employment or benefit plan related claims, reasonable costs and expenses incurred by the Parties in responding to such legal action shall be allocated among the Parties equitably in proportion to a reasonable assessment of the relative proportion of Employees included in or represented by the putative or certified plaintiff class. The procedures contained in the indemnification and related litigation cooperation provisions of the Separation Agreement shall apply with respect to each Party’s indemnification obligations under this Section 13.3 .

 

Section 13.4          Reimbursement and Indemnification .  To the extent provided for under this Agreement, each Party agrees to reimburse the other Party, within 30 days of receipt from the other Party of reasonable verification, for all costs and expenses which the other Party may incur on its behalf as a result of any of the respective OPC and CRC Benefit Plans and, as contemplated by Article XI , any termination or severance payments or benefits. All Liabilities retained, assumed, or indemnified against by CRC pursuant to this Agreement, and all Liabilities retained, assumed, or indemnified against by OPC pursuant to this Agreement, shall in each case be subject to the indemnification provisions of the Separation Agreement. Notwithstanding anything to the contrary, (i) no provision of this Agreement shall require any member of the CRC Group to pay or reimburse to any member of the OPC Group any benefit-related cost item that a member of the CRC Group has paid or reimbursed to any member of the OPC Group prior to the Effective Time, and (ii) no provision of this Agreement shall require any member of the OPC Group to pay or reimburse to any member of the CRC Group any benefit-related cost item that a member of the OPC Group has paid or reimbursed to any member of the CRC Group prior to the Effective Time.

 

Section 13.5          Costs of Compliance with Agreement .  Except as otherwise provided in this Agreement or any other Transfer Document, each Party shall pay its own expenses in fulfilling its obligations under this Agreement.

 

Section 13.6          Fiduciary Matters .  OPC and CRC each acknowledges that actions required to be taken pursuant to this Agreement may be subject to fiduciary duties or standards of conduct under ERISA or other applicable Law, and no Party shall be deemed to be in violation of this Agreement if it fails to comply with any provisions hereof based upon its good-faith determination (as supported by advice from counsel experienced in such matters) that to do so would violate such a fiduciary duty or standard. Each Party shall be responsible for taking such actions as are deemed necessary and appropriate to comply with its own fiduciary

 

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responsibilities and shall fully release and indemnify the other Party for any Liabilities caused by the failure to satisfy any such responsibility.

 

Section 13.7          Entire Agreement .  This Agreement, together with the documents referenced herein (including the Separation Agreement, the Transfer Documents and the plans and agreements referenced herein), constitutes the entire agreement and understanding among the Parties with respect to the subject matter hereof and supersedes all prior written and oral and all contemporaneous oral agreements and understandings with respect to the subject matter hereof.  Any conflicts between the provisions of this Agreement and the Separation Agreement (and the agreements referenced therein) or any Transfer Document shall be addressed in the manner set forth in Section 8.6 of the Separation Agreement.

 

Section 13.8          Binding Effect; No Third-Party Beneficiaries; Assignment .  This Agreement shall inure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns. Except as otherwise expressly provided in this Agreement, this Agreement is solely for the benefit of the Parties and should not be deemed to confer upon any third parties any remedy, claim, Liability, reimbursement, cause of action, or other right in excess of those existing without reference to this Agreement. Nothing in this Agreement is intended to amend any employee benefit plan or affect the applicable plan sponsor’s right to amend or terminate any employee benefit plan pursuant to the terms of such plan. The provisions of this Agreement are solely for the benefit of the Parties, and no current or former Employee, officer, director, or independent contractor or any other individual associated therewith shall be regarded for any purpose as a third-party beneficiary of this Agreement. This Agreement may not be assigned by any Party, except with the prior written consent of the other Party.

 

Section 13.9          Amendment; Waivers .  No change or amendment may be made to this Agreement except by an instrument in writing signed on behalf of each of the Parties. Any Party may, at any time, (i) extend the time for the performance of any of the obligations or other acts of the other Party, (ii) waive any inaccuracies in the representations and warranties of the other Party contained herein or in any document delivered pursuant hereto, and (iii) waive compliance by the other Party with any of the agreements, covenants, or conditions contained herein. Any such extension or waiver shall be valid only if set forth in an instrument in writing signed by the Party to be bound thereby. No failure or delay on the part of any Party in the exercise of any right hereunder shall impair such right or be construed to be a waiver of, or acquiescence in, any breach of any representation, warranty, covenant, or agreement contained herein, nor shall any single or partial exercise of any such right preclude other or further exercises thereof or of any other right.

 

Section 13.10       Remedies Cumulative .  All rights and remedies existing under this Agreement or the Schedules attached hereto are cumulative to, and not exclusive of, any rights or remedies otherwise available.

 

Section 13.11       Notices .  Unless otherwise expressly provided herein, all notices, claims, certificates, requests, demands and other communications hereunder shall be in writing and shall be deemed to be duly given: (i) when personally delivered, (ii) if mailed by registered or certified mail, postage prepaid, return receipt requested, on the date the return receipt is executed or the letter is refused by the addressee or its agent, (iii) if sent by overnight courier which delivers only

 

35



 

upon the executed receipt of the addressee, on the date the receipt acknowledgment is executed or refused by the addressee or its agent, or (iv) if sent by facsimile or electronic mail, on the date confirmation of transmission is received ( provided that a copy of any notice delivered pursuant to this clause (iv) shall also be sent pursuant to clause (i), (ii) or (iii)), addressed to the attention of the addressee’s General Counsel at the address of its principal executive office or to such other address or facsimile number for a Party as it shall have specified by like notice.

 

Section 13.12       Counterparts .  This Agreement, including the Schedules hereto and the other documents referred to herein, may be executed in multiple counterparts, each of which when executed shall be deemed to be an original but all of which together shall constitute one and the same agreement.

 

Section 13.13       Severability .  If any term or other provision of this Agreement or the Schedules attached hereto is determined by a non-appealable decision by a court, administrative agency, or arbitrator to be invalid, illegal, or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any Party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the court, administrative agency, or arbitrator shall interpret this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that transactions contemplated hereby are fulfilled to the fullest extent possible. If any sentence in this Agreement is so broad as to be unenforceable, the provision shall be interpreted to be only so broad as is enforceable.

 

Section 13.14       Governing Law .  This Agreement (and any claims or disputes arising out of or related hereto or thereto or to the transactions contemplated hereby and thereby or to the inducement of any Party to enter herein and therein, whether for breach of contract, tortious conduct, or otherwise and whether predicated on common law, statute, or otherwise) shall be governed by and construed and interpreted in accordance with the Laws of the State of Texas irrespective of the choice of laws principles of the State of Texas, including all matters of validity, construction, effect, enforceability, performance, and remedies.

 

Section 13.15       Dispute Resolution .  The procedures set forth in Article IV of the Separation Agreement shall apply to any dispute, controversy or claim (whether sounding in contract, tort or otherwise) that arises out of or relates to this Agreement, any breach or alleged breach hereof, the transactions contemplated hereby (including all actions taken in furtherance of the transactions contemplated hereby on or prior to the date hereof), or the construction, interpretation, enforceability, or validity hereof.

 

Section 13.16       Performance .  Each of OPC and CRC shall cause to be performed, and hereby guarantees the performance of, all actions, agreements and obligations set forth herein to be performed by any member of the OPC Group and any member of the CRC Group, respectively. The Parties each agree to take such further actions and to execute, acknowledge, and deliver, or to cause to be executed, acknowledged, and delivered, all such further documents as are reasonably requested by the other for carrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement.

 

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Section 13.17       Construction .  This Agreement shall be construed as if jointly drafted by the Parties and no rule of construction or strict interpretation shall be applied against any Party.

 

Section 13.18       Effect if Initial Distribution Does Not Occur .  Notwithstanding anything in this Agreement to the contrary, if the Separation Agreement is terminated prior to the Effective Time, then this Agreement shall be of no further force and effect.

 

[Signature Page Follows]

 

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IN WITNESS WHEREOF , the Parties have caused this Agreement to be executed by their duly authorized representatives.

 

 

OCCIDENTAL PETROLEUM CORPORATION

 

 

 

 

 

By:

 

 

Name:

 

 

Title:

 

 

 

 

 

 

 

CALIFORNIA RESOURCES CORPORATION

 

 

 

 

 

By:

 

 

Name:

 

 

Title:

 

 

[ Signature Page to Employee Matters Agreement ]

 



 

[SCHEDULE 3.1(h) COLLECTIVE BARGAINING AGREEMENTS]

 

Schedule 3.1(h)

 



 

[SCHEDULE 9.3 PROVISIONS RELATING TO POST-RETIREMENT WELFARE PLANS]

 

Schedule 9.3

 




EXHIBIT 10.5

 

[FORM OF]

 

CALIFORNIA RESOURCES CORPORATION LONG-TERM INCENTIVE PLAN

 

1.                                       PURPOSE

 

The purposes of this Plan are (i) to furnish a significant incentive to the employees, consultants and non-employee Directors of the Company and its Affiliates by making available to them the benefits of increased ownership of Shares, (ii) to promote the alignment of the interests of employees, consultants and non-employee Directors of the Company and its Affiliates on the one hand and stockholders on the other hand and (iii) to assist in the recruitment and retention of employees, consultants and non-employee Directors of the Company and its Affiliates.

 

2.                                       DEFINITIONS

 

Affiliate ” means any corporation, partnership, limited liability company or partnership, association, trust, or other organization which, directly or indirectly, controls, is controlled by, or is under common control with, the Company.  For purposes of the preceding sentence, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any entity or organization, shall mean the possession, directly or indirectly, of the power (i) to vote more than 50% of the securities having ordinary voting power for the election of directors of the controlled entity or organization or (ii) to direct or cause the direction of the management and policies of the controlled entity or organization, whether through the ownership of voting securities or by contract or otherwise.

 

Board ” means the Board of Directors of the Company.

 

Business Combination ” means a merger, consolidation, or other reorganization, with or into, or the sale of all or substantially all of the Company’s business and/or assets as an entirety to, one or more entities that are not Affiliates.

 

Change in Control ” means the occurrence of any of the following events:

 

(a)                                  Approval by the stockholders of the Company of the dissolution or liquidation of the Company, other than in the context of a transaction that does not constitute a Change in Control under clause (b) below;

 

(b)                                  Consummation of a Business Combination, unless (1) as a result of the Business Combination, more than 50 percent of the outstanding voting power of the Successor Entity immediately after the reorganization is, or will be, owned, directly or indirectly, by persons who were holders of the Company’s voting securities immediately before the Business Combination; (2) no “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act), excluding the Successor Entity or an Excluded Person, beneficially owns, directly or indirectly, more than 30 percent of the outstanding shares or the combined voting power of the outstanding voting securities of the Successor Entity, after giving effect to the Business Combination, except to the extent that such ownership existed prior to the Business Combination; and (3) at least 50 percent of the members of the board of directors of the entity resulting from the Business Combination were Directors at the time of the execution of the initial agreement or of the action of the Board approving the Business Combination;

 

(c)                                   Any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act, but excluding any Excluded Person) is or becomes the beneficial owner (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing 30 percent or more of the combined voting power of the Company’s then outstanding voting securities, other than as a result of (1) an acquisition directly from the Company; (2) an acquisition by the Company; or (3) an acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or a Successor Entity; or

 



 

(d)                                  During any period not longer than two consecutive years and beginning no earlier than the Effective Date, individuals who at the beginning of such period constituted the Board cease to constitute at least a majority thereof, unless the election, or the nomination for election by the Company’s stockholders, of each new Director was approved by a vote of at least two-thirds (2/3) of the Directors then still in office who were Directors at the beginning of such period (including for these purposes, new members whose election or nomination was so approved), but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of Directors or other actual or threatened solicitation of proxies or consents by or on behalf of a person other than the Board.

 

Notwithstanding the foregoing, (i) if a Change in Control constitutes a payment event with respect to any Award that provides for the deferral of compensation and is subject to the Nonqualified Deferred Compensation Rules, then the transaction or event described in subsection (a), (b), (c) or (d) above with respect to such award must also constitute a “change in control event,” as defined in Treasury Regulation Section 1.409A-3(i)(5), and as relates to the holder of such Award, to the extent required to comply with the Nonqualified Deferred Compensation Rules and (ii) in no event shall the separation of the Company from Occidental be a Change in Control.

 

Code ” means the Internal Revenue Code of 1986, as amended from time to time.

 

Committee ” means the Compensation Committee of the Board or its successor, which shall be composed of not less than two members of the Board, each of whom shall be a “non-employee director” within the meaning of Rule 16b-3 and an “outside director” within the meaning of Section 162(m).   Notwithstanding the foregoing, for the period prior to the date the Company becomes a separate publicly-held corporation for purposes of Section 162(m), the “Committee” shall be the Executive Compensation Committee of the Board of Directors of Occidental Petroleum Corporation.

 

Company ” means California Resources Corporation, a Delaware corporation.

 

Covered Employee ” means an Eligible Person who is a Covered Employee as specified in Section 5.2 of this Plan.

 

Director ” means a member of the Board who is not an employee of the Company or an Affiliate.

 

Disability ” means permanent and total disability as defined in Section 22(e)(3) of the Code.

 

Effective Date ” means the date this Plan is approved by Occidental Petroleum Investment Co., in its capacity as the sole stockholder of the Company.

 

Eligible Person ” means any person who is an officer, employee or consultant of the Company or any Affiliate and any person who is a non-employee Director; provided, however that an ISO may be granted only to an individual who is employed by the Company or any “parent corporation” or “subsidiary corporation” (as such terms are defined in Section 424 of the Code) of the Company at the time the ISO is granted.

 

Exchange Act ” means the Securities Exchange Act of 1934, as amended from time to time.

 

Excluded Person ” means Occidental, any employee benefit plan of the Company or Occidental and any trustee or other fiduciary holding securities under a Company or Occidental employee benefit plan or any person described in and satisfying the conditions of Rule 13d-1(b)(i) of the Exchange Act; provided, however, that Occidental, employee benefit plans of Occidental and trustees and fiduciaries holding securities under an Occidental employee benefit plan shall cease to be Excluded Persons at such time as Occidental distributes the approximately [20]% of the Company’s outstanding common stock held by Occidental as contemplated in that certain Separation and Distribution Agreement dated as of [ · ], 2014, between the Company and Occidental.

 

Fair Market Value ” means, as of any specified date, the closing price of the a Share, if the Shares are listed on a national stock exchange registered under Section 6(a) of the Exchange Act, reported on the stock exchange composite tape on that date (or such other reporting service approved by the Committee); or, if no closing

 

2



 

price is reported on that date, on the last preceding date on which such closing price of the Share is so reported.  If the Shares are traded over the counter at the time a determination of its fair market value is required to be made hereunder, its fair market value shall be deemed to be equal to the average between the reported high and low or closing bid and asked prices of a Share on the most recent date on which Shares were publicly traded.  In the event Shares are not publicly traded at the time a determination of its value is required to be made hereunder, the determination of its fair market value shall be made by the Committee in such manner as it deems appropriate and as is consistent with the requirements of Section 409A of the Code.

 

ISO ” means an incentive stock option qualified under Section 422 of the Code.

 

Nonqualified Deferred Compensation Rules ” means the limitations or requirements of Section 409A of the Code and the guidance and regulations promulgated thereunder.

 

Occidental ” means Occidental Petroleum Corporation, a Delaware corporation, and its Affiliates.

 

Performance-Based Award ” means any Qualifying Option or award granted pursuant to Section 5.  The Committee may grant Performance-Based Awards intended to constitute Section 162(m) Awards or Performance-Based Awards not intended to constitute Section 162(m) Awards.

 

Performance Goal ” means a preestablished targeted level or levels of any one or more Performance Objectives.

 

Performance Objectives ” means those performance objectives described in Section 5.2.

 

Plan ” means this California Resources Corporation Long-Term Incentive Plan, as amended from time to time.

 

Qualifying Options ” mean options and stock appreciation rights granted with an exercise price not less than Fair Market Value on the date of grant.  Qualifying Options are intended to be Performance-Based Awards.

 

Rule 16b-3 ” means Rule 16b-3 under Section 16 of the Exchange Act.

 

Section 162(m) ” means Section 162(m) of the Code and the applicable regulations and interpretations thereunder.

 

Section 162(m) Award ” means a Performance-Based Award intended to satisfy the requirements for “performance-based compensation” within the meaning of Section 162(m).

 

Share Limit ” means the maximum number of Shares, as adjusted, that may be delivered pursuant to all awards granted under this Plan.

 

Shares ” mean the Company’s Common Stock, par value $0.01 per share.

 

Substitute Award ” means an award granted in substitution for similar awards held by individuals who become Eligible Persons as a result of a merger, consolidation, acquisition or other transaction by the Company or an Affiliate with or of another entity or the assets of another entity.

 

Successor Entity ” means the surviving or resulting entity or a parent thereof of a Business Combination.

 

3.                                       SHARES SUBJECT TO PLAN

 

3.1                                AGGREGATE SHARE LIMIT - Subject to adjustment as provided in or pursuant to this Section 3 or Section 7, (a) a total of [ · ] Shares shall be authorized for issuance pursuant to awards granted under this Plan and (b) the aggregate maximum number of Shares that may be issued under this Plan through ISOs shall not exceed [ · ] (which amount shall be included within the total Share limit set forth in clause (a) of this sentence).

 

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3.2                                INDIVIDUAL LIMIT - Subject to adjustment as provided in or pursuant to this Section 3 or Section 7, the maximum number of Shares that may be subject to options, stock appreciation rights or other awards (other than cash-based awards) granted under the Plan to any one individual during the ten-year period beginning on the Effective Date may not exceed [ insert number equal to 50% of the aggregate maximum number of Shares authorized for issuance pursuant the Plan ] Shares.  The maximum amount of compensation that may be paid under all Performance-Based Awards denominated in cash (including the Fair Market Value of any Shares paid in satisfaction of such Performance-Based Awards) granted to any one individual during any calendar year may not exceed $[ · ] (and any payment due with respect to such a Performance-Based Award shall be paid no later than 10 years after the date of grant of such Performance-Based Award).

 

3.3                                REISSUE OF AWARDS AND SHARES - Awards payable in cash or payable in cash or Shares, including restricted shares, that are forfeited, cancelled, or for any reason do not vest under this Plan, and Shares that are subject to awards that expire or for any reason are terminated, cancelled or fail to vest shall be available for subsequent awards under this Plan.  If an award under this Plan is or may be settled only in cash, such award need not be counted against any of the share limits under this Section 3, except as may be required to preserve the status of an award as “performance-based compensation” under Section 162(m).  Shares subject to options or stock appreciation rights that are exercised shall not be available for subsequent awards.  The following transactions involving Shares will not result in additional Shares becoming available for subsequent awards under this Plan:  (i) Shares tendered in payment of an option; (ii) Shares withheld for taxes; and (iii) Shares repurchased by the Company using option proceeds.

 

3.4                                SOURCE OF SHARES DELIVERED UNDER PLAN — The Shares to be offered pursuant to the grant of an award may (a) be authorized but unissued Shares, (b) Shares held in the treasury of the Company, or (c) previously issued Shares reacquired by the Company, including shares purchased on the open market.

 

4.                                       PLAN ADMINISTRATION

 

This Plan shall be administered by the Committee.

 

4.1                                POWERS OF THE COMMITTEE - Subject to the express provisions of this Plan, the Committee shall be authorized and empowered to do all things necessary or desirable in connection with the authorization of awards and the administration of this Plan within its delegated authority, including, without limitation, the authority to:

 

(a)                                  adopt, amend and rescind rules, regulations and procedures relating to this Plan and its administration or the awards granted under this Plan and determine the forms and terms of individual awards;

 

(b)                                  determine who is an Eligible Person and to which Eligible Persons, if any, awards will be granted under this Plan;

 

(c)                                   grant awards to Eligible Persons and determine the terms and conditions of such awards, including but not limited to the number and value of Shares issuable pursuant thereto, the times (subject to Section 5.5) at which and conditions upon which awards become exercisable or vest or shall expire or terminate, and (subject to applicable law) the consideration, if any, to be paid upon receipt, exercise or vesting of awards;

 

(d)                                  determine the date of grant of an award, which may be a designated date after but not before the date of the Committee’s action;

 

(e)                                   determine whether (subject to Section 7.2), and the extent to which, adjustments are required pursuant to Section 7 hereof;

 

(f)                                    interpret and construe this Plan and terms and conditions of any award granted hereunder (including under any award agreement) and correct any defect therein, whether before or after the date set forth in Section 5;

 

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(g)                                   determine the circumstances under which, consistent with the provisions of Section 8.2, any outstanding award may be amended and make any amendments thereto that the Committee determines are necessary or appropriate; and

 

(h)                                  acquire or settle rights under options, stock appreciation rights or other awards in cash, stock of equivalent value, or other consideration.

 

All authority granted herein shall remain in effect so long as any award remains outstanding under this Plan.  The Committee and each member thereof shall be entitled to, in good faith, rely or act upon any report or other information furnished to him or her by any officer or employee of the Company or any Affiliate, the Company’s legal counsel, independent auditors, consultants or any other agents assisting in the administration of this Plan.  Members of the Committee and any officer or employee of the Company or any Affiliate acting at the direction or on behalf of the Committee shall not be personally liable for any action or determination taken or made in good faith with respect to this Plan, and shall, to the fullest extent permitted by law, be indemnified and held harmless by the Company with respect to any such action or determination.

 

4.2                                SPECIFIC COMMITTEE RESPONSIBILITY AND DISCRETION REGARDING AWARDS - Subject to the express provisions of this Plan, the Committee, in its sole and absolute discretion, shall determine all of the terms and conditions of each award granted under this Plan, which terms and conditions may include, subject to such limitations as the Committee may from time to time impose, among other things, provisions that:

 

(a)                                  permit the recipient of such award to pay the purchase price of the Shares or other property issuable pursuant to such award, or any applicable tax withholding obligation upon such issuance or in respect of such award or Shares, in whole or in part, by any one or more of the following:

 

(i)                                      cash, cash equivalent, or electronic funds transfer,

 

(ii)                                   the delivery of previously owned shares of capital stock of the Company (including shares acquired as or pursuant to awards) or other property,

 

(iii)                                a reduction in the amount of Shares or other property otherwise issuable pursuant to such award,

 

(iv)                               a cashless exercise, or

 

(v)                                  any other legal consideration the Committee deems appropriate;

 

(b)                                  are intended to qualify such award as an ISO;

 

(c)                                   accelerate the receipt of benefits pursuant to an award or adjust the exercisability, term (subject to other limits) or vesting schedule of any or all outstanding awards, adjust the number of Shares subject to any award, adjust the price of any or all outstanding awards or otherwise change previously imposed terms and conditions, pursuant to a termination of employment or an event referenced in Section 7 (in which case the Committee’s discretion shall be exercised in a manner consistent with Section 7) or in other circumstances or upon the occurrence of other events as deemed appropriate by the Committee, by amendment of an outstanding award, by substitution of an outstanding award, by waiver or by other legally valid means (which may result, among other changes, in a greater or lesser number of shares subject to the award, a shorter or longer vesting or exercise period, or, except as provided below, an exercise or purchase price that is higher or lower than the original or prior award), in each case subject to Sections 3 and 8.2; provided, however, that in no case (other than an adjustment contemplated by Section 7.2) shall the exercise price of any option or stock appreciation right be reduced by an amendment to the award or a cancellation and re-grant of the award to effect a repricing of the award to a price below the Fair Market Value of the underlying Shares on the grant date of the original option or stock appreciation right unless specific stockholder consent is obtained;

 

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(d)                                  authorize (subject to Sections 7, 8, and 10) the conversion, succession or substitution of one or more outstanding awards upon the occurrence of an event of the type described in Section 7 or in other circumstances or upon the occurrence of other events as deemed appropriate by the Committee; and

 

(e)                                   determine the value of and acquire or otherwise settle awards upon termination of employment, upon such terms as the Committee (subject to Sections 7, 8 and 10) deems appropriate.

 

4.3                                DELEGATION - Subject to Section 4.5, the Board may delegate different levels of authority to different committees with administrative and grant authority under this Plan, provided that each designated committee granting any awards hereunder shall consist exclusively of a member or members of the Board.  A majority of the members of the acting committee shall constitute a quorum.  The vote of a majority of the members present assuming the presence of a quorum or the unanimous written consent of the Committee shall constitute action by the committee.  The Committee may delegate authority to grant awards under this Plan for new employees to an officer of the Company who is also a director and may delegate ministerial, non-discretionary functions to individuals who are officers or employees of the Company or a subsidiary or to third parties.  Notwithstanding the foregoing, no such delegation pursuant to this Section 4.3 shall be made to the extent that such delegation would result in the loss of an exemption under Rule 16b-3(d)(1) for awards granted to Eligible Persons subject to Section 16 of the Exchange Act in respect of the Company and will not cause Performance-Based Awards intended to qualify as “performance-based compensation” under Section 162(m) to fail to so qualify.

 

4.4                                BIFURCATION - Notwithstanding anything to the contrary in this Plan, the provisions of this Plan may at any time be bifurcated by the Board or the Committee in any manner so that provisions of any award agreement (or this Plan) intended or required in order to satisfy the applicable requirements of Rule 16b-3, Section 162(m) or other applicable law, to the extent permitted thereby, are applicable only to persons subject to those provisions and to those awards to those persons intended to satisfy the requirements of the applicable legal restriction.

 

4.5                                AWARDS TO NON-EMPLOYEE DIRECTORS - Notwithstanding any provision in this Plan to the contrary and without being subject to management discretion, the Board, acting through the non-employee Directors only, shall have the authority, in its sole and absolute discretion, to select non-employee Directors to receive awards other than ISOs under this Plan.  The Board, acting through the non-employee Directors only shall set the terms of any such awards in its sole and absolute discretion, and the Board, acting through the non-employee Directors only, shall be responsible for administering and construing such awards in substantially the same manner that the Committee administers and construes awards to other Eligible Persons.

 

5.                                       AWARDS

 

5.1                                TYPE AND FORM OF AWARDS - All awards shall be evidenced in writing (including electronic form), substantially in the form approved by the Committee or its delegate.  The types of awards that the Committee may grant include, but are not limited to, any of the following, on an immediate or deferred basis, either singly, or in tandem or in combination with or in substitution for, other awards of the same or another type:  (i) Shares, (ii) options (ISOs or nonqualified stock options), stock appreciation rights (including limited stock appreciation rights), restricted stock, stock units, or similar rights to purchase or acquire shares, whether at a fixed or variable price or ratio related to the Shares, upon the passage of time, the occurrence of one or more events, or the satisfaction of Performance Goals or other conditions, or any combination thereof, (iii) any similar securities with a value derived from the value of or related to the Shares or other securities of the Company and/or returns thereon, or (iv) cash.  Share-based awards may include (without limitation) stock options, stock purchase rights, stock bonuses, stock units, stock appreciation rights, limited stock appreciation rights, phantom stock, dividend equivalents (independently or in tandem with any form of stock grant), dividend rights (independently or in tandem with any form of stock grant), Shares, any of which may be payable in Shares or cash, and may consist of one or more of such features in any combination, as determined by the Committee.

 

5.2                                PERFORMANCE-BASED AWARDS -

 

5.2.1                      Performance Conditions - The right of a participant to exercise or receive a grant or settlement of any type of award listed in Section 5.1, and the timing thereof, may be subject to such performance conditions as may be specified by the Committee.  The Committee may use such business criteria and other

 

6



 

measures of performance as it may deem appropriate in establishing any performance conditions, and may exercise its discretion to reduce or increase the amounts payable under any award subject to performance conditions, except as limited under Section 5.2.2 in the case of a Performance-Based Award intended to qualify under Section 162(m).

 

5.2.2                      Performance-Based Awards Granted to Designated Covered Employees   —  If the Committee determines that a Performance-Based Award to be granted to an Eligible Person who is designated by the Committee as likely to be a Covered Employee should qualify as “performance-based compensation” for purposes of Section 162(m), the grant, exercise and/or settlement of such Performance-Based Award may be contingent upon achievement of pre-established Performance Goals and other terms set forth in this Section 5.2.2.

 

(a)                                  Performance Goals Generally .  The Performance Goals for such Performance-Based Awards shall consist of one or more business criteria or individual performance criteria and a targeted level or levels of performance with respect to each of such criteria, as specified by the Committee consistent with this Section 5.2.2, which level may also be expressed in terms of a specified increase or decrease in the particular criteria compared to a past period.  Performance Goals shall be objective and shall otherwise meet the requirements of Section 162(m), including the requirement that the level or levels of performance targeted by the Committee result in the achievement of Performance Goals being “substantially uncertain” at the time the Committee actually establishes the Performance Goal or Goals.  The Committee may determine that such Performance-Based Awards shall be granted, exercised and/or settled upon achievement of any one Performance Goal or that two or more of the Performance Goals must be achieved as a condition to grant, exercise and/or settlement of such Performance-Based Awards.  Performance Goals may differ for Performance-Based Awards granted to any one participant or to different participants.

 

(b)                                  Business and Individual Performance Criteria .

 

(i)                                      Business Criteria .  Means any one or more of the following business criteria for the Company, on a consolidated basis, and/or for specified subsidiaries or business or geographical units of the Company (except with respect to the total stockholder return (TSR) and earnings per share (EPS) criteria): (A) accounts receivable to day sales outstanding, (B) accounts receivable to sales, services and/or other income, (C) debt, (D) debt to debt plus stockholder equity, (E) debt to earnings before interest expense and taxes (EBIT) or earnings before interest expense, taxes, depreciation and amortization (EBITDA), (F) EBIT, (G) EBITDA, (H) EPS, (I) economic value added, (J) expense reduction or improvement, (K) interest coverage, (L) inventory to sales, (M) inventory turns, (N) net income, (O) operating cash flow,(P) pre-tax margin, (Q) return on assets, (R) return on capital employed, (S) return on equity, (T) sales, (U) stock price appreciation, (V) TSR, (W) operational measures such as changes in proved reserves, production goals, drilling costs, lifting costs, exploration costs, environmental compliance, safety and accident rates, (X) mix of oil and natural gas production or reserves; (Y) finding and development costs; (Z) recycling ratios; (AA) reserve growth, (BB) additions or revisions; (CC) captured prospects; (DD) lease operating expense; (EE) captured net risked resource potential, in each case, as determined on an absolute or relative basis or as compared to the performance of a published or special index deemed applicable by the Committee including, but not limited to, the Standard & Poor’s 500 Stock Index or a group of comparable companies.  These terms are used as applied under generally accepted accounting principles (if applicable) and in the Company’s financial reporting.  In addition, subject to any limitations under Section 162(m), such performance measures may be subject to adjustment by the Committee for changes in accounting principles, to satisfy regulatory requirements and other specified significant extraordinary items or events.

 

7



 

(ii)                                   Individual Performance Criteria .  The grant, exercise and/or settlement of Performance-Based Awards may also be contingent upon individual performance goals established by the Committee.  If required for compliance with Section 162(m), such criteria shall be approved by the stockholders of the Company.

 

(c)                                   Performance Period; Timing for Establishing Performance Goals .  Achievement of Performance Goals in respect of such Performance-Based Awards shall be measured over a performance period of up to ten years, as specified by the Committee.  Performance Goals shall be established not later than 90 days after the beginning of any performance period applicable to such Performance-Based Awards, or at such other date as may be required or permitted for “performance-based compensation” under Section 162(m).

 

(d)                                  Performance-Based Award Pool .  The Committee may establish a Performance-Based Award pool, which shall be an unfunded pool, for purposes of measuring performance of the Company in connection with Performance-Based Awards.  The amount of such Performance-Based Award pool shall be based upon the achievement of a Performance Goal or Goals based on one or more of the criteria set forth in Section 5.2.2(b)(i) during the given performance period, as specified by the Committee in accordance with this Section 5.2.2.  The Committee may specify the amount of the Performance-Based Award pool as a percentage of any of such criteria, a percentage thereof in excess of a threshold amount, or as another amount which need not bear a strictly mathematical relationship to such criteria.

 

(e)                                   Settlement of Performance-Based Awards; Other Terms .  After the end of each performance period, the Committee shall certify the amount, if any, of (A) the Performance-Based Award pool, and the maximum amount of the potential Performance-Based Award payable to each Participant in the Performance-Based Award pool, or (B) the amount of the potential Performance-Based Award otherwise payable to each Participant.  Settlement of such Performance-Based Awards shall be in cash, Stock, other awards or other property, in the discretion of the Committee.  The Committee may, in its discretion, reduce the amount of a settlement otherwise to be made in connection with such Performance-Based Awards, but may not exercise discretion to increase any such amount payable to a Covered Employee in respect of a Performance-Based Award subject to this Section 5.2.2.  The Committee shall specify the circumstances in which such Performance-Based Awards shall be paid or forfeited in the event of termination of employment by the participant prior to the end of a performance period or settlement of Performance-Based Awards.

 

(f)                                    Written Determinations .  All determinations by the Committee as to the establishment of Performance Goals, the amount of any Performance-Based Award pool or potential individual Performance-Based Awards and as to the achievement of Performance Goals relating to and final settlement of Performance-Based Awards under this Section 5.2.2 shall be certified in writing in the case of any award intended to qualify as a Section 162(m) Award.  The Committee may not delegate any responsibility relating to such Performance-Based Awards.

 

(g)                                   Status of Performance-Based Awards under Section 162(m) .  It is the intent of the Company that Performance-Based Awards under Section 5.2.2 granted to persons who are designated by the Committee as likely to be Covered Employees within the meaning of Section 162(m) shall, if so designated by the Committee, constitute qualified “performance-based compensation” within the meaning of Section 162(m).  Accordingly, the terms of this Section 5.2, including the definitions of Covered Employee and other terms used therein, shall be interpreted in a manner consistent with Section 162(m).  The foregoing notwithstanding, because the Committee cannot determine with certainty whether a given Eligible Person will be a Covered Employee with respect to a fiscal year that has not yet been completed, the term Covered Employee as used herein shall mean only a person designated by the Committee, at the time of grant of a Performance-Based Award, who is likely to be a Covered Employee with respect to that fiscal year.  If any provision of this Plan or any agreement relating to such Performance-Based Awards that are designated as intended to comply with Section 162(m) does not comply or is inconsistent with the

 

8



 

requirements of Section 162(m), such provision shall be construed or deemed amended to the extent necessary to conform to such requirements.

 

5.3                                CONSIDERATION FOR SHARES - Shares may be issued pursuant to an award for any lawful consideration as determined by the Committee, including, without limitation, services rendered by the recipient of such award, but shall not be issued for less than the minimum lawful consideration.  Awards may be payable in cash, stock or other consideration or any combination thereof, as the Committee shall designate in or (except as required by Section 5.2) by amendment to the terms and conditions governing such award.

 

5.4                                LIMITED RIGHTS - Except as otherwise expressly authorized by the Committee or this Plan or in the applicable award terms and conditions, a participant will not be entitled to any privilege of stock ownership as to any Shares not actually delivered to and held of record by the participant.  No adjustment will be made for dividends or other rights as a stockholder for which a record date is prior to such date of delivery.

 

5.5                                OPTION/STOCK APPRECIATION RIGHT PRICING AND TERM LIMITS - The purchase price per share of the Shares covered by any option or the base price of any stock appreciation right shall be determined by the Committee at the time of the grant, but, except in the case of a Substitute Award, shall not be less than 100 percent of the Fair Market Value of a Share on the date of grant.  No option or stock appreciation right shall be exercisable after the expiration of 10 years from the date of grant.  An award may be converted or convertible, notwithstanding the foregoing limits, into or payable in, Shares or another award that otherwise satisfies the requirements of this Plan.

 

5.6                                SPECIAL LIMITATIONS RELATING TO ISOS - An ISO may be granted only to an individual who is employed by the Company or any “parent corporation” or “subsidiary corporation” (as such terms are defined in Section 424 of the Code) of the Company at the time the ISO is granted.  To the extent that the aggregate fair market value (determined at the time the respective ISO is granted) of stock with respect to which ISOs are exercisable for the first time by an individual during any calendar year under all incentive stock option plans of the Company and its parent and subsidiary corporations, within the meaning of Section 424 of the Code, exceeds $100,000 or such other amount as may be prescribed under Section 422 of the Code or applicable regulations or rulings from time to time, such ISOs shall be treated as options that do not constitute ISOs.  The Committee shall determine, in accordance with applicable provisions of the Code, Treasury regulations, and other administrative pronouncements, which of a participant’s ISOs will not constitute ISOs because of such limitation and shall notify the participant of such determination as soon as practicable after such determination.  No ISO shall be granted to an individual if, at the time the option is granted, such individual owns stock possessing more than 10% of the total combined voting power of all classes of stock of the Company or of its parent or subsidiary corporation, within the meaning of Section 422(b)(6) of the Code, unless (i) at the time such option is granted, the option price is at least 110% of the Fair Market Value of a Share and (ii) such option by its terms is not exercisable after the expiration of five years from the date of grant.  Except as otherwise provided in Sections 421 or 422 of the Code, an ISO shall not be transferable otherwise than by will or the laws of descent and distribution and shall be exercisable during the participant’s lifetime only by such participant or the participant’s guardian or legal representative.

 

5.7                                TRANSFER RESTRICTIONS - Unless otherwise expressly provided in or permitted by this Section 5.7, by applicable law or by the award terms and conditions (i) all awards are nontransferable and shall not be subject in any manner to sale, transfer, anticipation, alienation, assignment, pledge, encumbrance or charge; (ii) awards shall be exercised only by the holder; and (iii) amounts payable or shares issuable pursuant to an award shall be delivered only to (or for the account of) the holder.

 

5.7.1                      Exceptions by Committee Action - The Committee, in its sole discretion, may permit an award to be transferred for estate and/or tax planning purposes and on a basis consistent with the Company’s lawful issue of securities and the incentive purposes of the award and this Plan. Notwithstanding the foregoing, awards intended as ISOs or restricted stock awards for purposes of the Code shall be subject to any and all additional transfer restrictions necessary to preserve their status as ISOs or restricted shares, as the case may be, under the Code.

 

5.7.2                      Exclusions - The exercise and transfer restrictions in this Section 5.7 shall not apply to:

 

9



 

(a)                                  transfers to the Company,

 

(b)                                  the designation of a beneficiary to receive benefits in the event of the participant’s death or, if the participant has died, transfers to or exercise by the participant’s beneficiary, or, in the absence of a validly designated beneficiary, transfers by will or the laws of descent and distribution,

 

(c)                                   transfers pursuant to a domestic relations order (if approved or ratified by the Committee), if (in the case of ISOs) permitted by the Code,

 

(d)                                  if the participant has suffered a Disability, permitted transfers to or exercises on behalf of the holder by his or her legal representative, or

 

(e)                                   the authorization by the Committee of “cashless exercise” procedures with third parties who finance or who otherwise facilitate the exercise of awards consistent with applicable laws and the express authorization of the Committee.

 

5.8                                TAX WITHHOLDING - The Company and any of its Affiliates are authorized to withhold from any award granted, or any payment relating to an award under this Plan, including from a distribution of Shares, amounts of withholding and other taxes due or potentially payable in connection with any transaction involving an award, and to take such other action as the Committee may deem advisable to enable the Company, its Affiliates and participants to satisfy obligations for the payment of withholding taxes and other tax obligations relating to any award.  This authority shall include authority to withhold or receive Shares or other property and to make cash payments in respect thereof in satisfaction of a participant’s tax obligations, either on a mandatory or elective basis in the discretion of the Committee.  Notwithstanding the foregoing, the Company and its Affiliates may, in their sole discretion and in satisfaction of the foregoing requirement, withhold or permit the participant to elect to have the Company or its Affiliate withhold a sufficient number of Shares that are otherwise issuable to the participant pursuant to an award (or allow the surrender of Shares by the participant to the Company or its Affiliate).  The number of Shares that may be so withheld or surrendered shall be limited to the number of Shares that have a Fair Market Value on the date of withholding or repurchase equal to the aggregate amount of such liabilities based on the applicable minimum statutory withholding rates for U.S. federal, state, local or non-U.S. income and social insurance taxes and payroll taxes, as determined by the Committee.

 

5.9                                CASH AWARDS - The Committee shall have the express authority to pay awards in cash under this Plan, whether in lieu of, in addition to or as part of another award.

 

5.10                         TERMINATION OF EMPLOYMENT OR SERVICE - If an Eligible Person’s employment with or service to the Company or to any Affiliate terminates for any reason, his or her outstanding awards may thereafter be exercised (if at all) to the extent provided in the agreement evidencing such award, or as otherwise determined by the Committee.

 

6.                                       TERM OF PLAN

 

No award shall be granted under this Plan after the tenth anniversary of the Effective Date.  After that date, this Plan shall continue in effect as to then outstanding awards.  Any then outstanding award may be amended thereafter in any manner that would have been permitted earlier, except that no such amendment shall increase the number of Shares subject to, comprising or referenced in the award or reduce the exercise or base price of an option or stock appreciation right or permit cash payments in an amount that exceeds the limits of Section 3 (as adjusted pursuant to Section 7.2).

 

7.                                       ADJUSTMENTS; CHANGE IN CONTROL

 

7.1                                CHANGE IN CONTROL; ACCELERATION AND TERMINATION OF AWARDS - Unless prior to a Change in Control, the Committee determines that, upon its occurrence, benefits under any or all awards will not accelerate or determines that only certain or limited benefits under any or all awards will be accelerated and the

 

10



 

extent to which they will be accelerated, or establishes a different time in respect of such Change in Control for such acceleration, then upon the occurrence of a Change in Control:

 

(a)                                  each option and stock appreciation right shall become immediately exercisable,

 

(b)                                  restricted stock shall immediately vest free of restrictions,

 

(c)                                   each award under Section 5.2 shall become payable to the participant,

 

(d)                                  the number of Shares covered by each stock unit account shall be issued to the participant, and

 

(e)                                   any other rights of a participant under any other award will be accelerated to give the participant the benefit intended under any such award.

 

The Committee may override the limitations on acceleration in this Section 7.1 and may accord any Eligible Person a right to refuse any acceleration, whether pursuant to the award agreement or otherwise, in such circumstances as the Committee may approve. Any acceleration of awards shall comply with applicable legal and regulatory requirements, including the Nonqualified Deferred Compensation Rules. Without limiting the generality of the foregoing, the Committee may deem an acceleration to occur immediately prior to or up to 30 days before the applicable event and/or reinstate the original terms of an award if an event giving rise to an acceleration does not occur.

 

If any option or other right to acquire Shares under this Plan has been fully accelerated as required or permitted by this Plan but is not exercised prior to (i) a dissolution of the Company, or (ii) an event described in this Section 7.1 that the Company does not survive, or (iii) the consummation of a Change in Control approved by the Board, such option or right will terminate, subject to any provision that has been expressly made by the Committee or the Board through a plan of reorganization approved by the Board or otherwise for the survival, substitution, assumption, exchange or other settlement of such option or right.

 

7.2                                ADJUSTMENTS

 

7.2.1                      ADJUSTMENTS GENERALLY . The following provisions will apply if any extraordinary dividend or other extraordinary distribution occurs in respect of the Shares (whether in the form of cash, Shares, other securities, or other property), or any reclassification, recapitalization, stock split (including a stock split in the form of a stock dividend), reverse stock split, reorganization, merger, combination, consolidation, split-up, spin-off, repurchase, or exchange of Shares or other securities of the Company, or any similar, unusual or extraordinary corporate transaction (or event in respect of the Shares) or a sale of substantially all the assets of the Company as an entirety occurs. The Committee will, in such manner and to such extent (if any) as it deems appropriate and equitable:

 

(a)                                  proportionately adjust any or all of (i) the number and type of Shares (or other securities) that thereafter may be made the subject of awards (including the specific maxima and numbers of shares set forth elsewhere in this Plan and the individual award limitations set forth in Section 3), (ii) the number, amount and type of shares (or other securities or property) subject to any or all outstanding awards, (iii) the grant, purchase, or exercise price of any or all outstanding awards, (iv) the securities, cash or other property deliverable upon exercise of any outstanding awards, or (v) the Performance Goals or Performance Objectives appropriate to any outstanding awards, or

 

(b)                                  in the case of an extraordinary dividend or other distribution, recapitalization, reclassification, merger, reorganization, consolidation, combination, sale of assets, split-up, exchange, or spin-off, make provision for a cash payment or for the substitution or exchange of any or all outstanding awards or the cash, securities or property deliverable to the holder of any or all outstanding awards based upon the distribution or consideration payable to holders of the Shares of the Company upon or in respect of such event.

 

11



 

7.2.2                      EQUITY RESTRUCTURING - If the Company recapitalizes, reclassifies its capital stock or otherwise changes its capital structure or another change or event occurs that constitutes an “equity restructuring” pursuant to Accounting Standards Codification Topic 718, Compensation — Stock Compensation , or any successor accounting standard (a “ recapitalization ”), (a) the Committee shall equitably adjust the number and class of Shares (or other securities or property) covered by each outstanding award and the terms and conditions, including the exercise price and performance criteria (if any), of such award to equitably reflect such recapitalization and shall adjust the number and class of Shares (or other securities or property) with respect to which awards may be granted after such recapitalization and (b) the Committee shall make a corresponding and proportionate adjustment with respect to the maximum number of Shares (or other securities) that may be delivered with respect to awards under this Plan as provided in Section 3, the individual award limitations set forth in Section 3 and the class of Shares (or other securities) available for grant under this Plan.

 

8.                                       PLAN AMENDMENT AND TERMINATION

 

8.1                                AUTHORITY OF THE BOARD - Subject to Section 8.2, the Board may amend or terminate this Plan at any time and in any manner; provided, that, any such amendments shall be subject to the approval of the Company’s stockholders if such stockholder approval is required by any federal or state law or regulation or the rules of any stock exchange or automated quotation system on which the Shares may then be listed or quoted (and such approval shall be obtained in accordance with the requirements of such laws, regulations and rules).

 

8.2                                RESTRICTIONS - No amendment or termination of this Plan or change in or affecting any outstanding award shall deprive in any material respect the holder, without the consent of the holder, of any of his or her rights or benefits under or with respect to the award. Adjustments contemplated by Section 7 shall not be deemed to constitute a change requiring such consent.

 

9.                                       LEGAL MATTERS

 

9.1                                COMPLIANCE AND CHOICE OF LAW; SEVERABILITY - This Plan, the granting and vesting of awards under this Plan and the issuance and delivery of Shares and/or the payment of money under this Plan or under awards granted hereunder are subject to compliance with all applicable federal and state laws, rules and regulations and to such approvals by any listing, regulatory or governmental authority as may, in the opinion of counsel for the Company, be necessary or advisable in connection therewith.  This Plan, the awards, all documents evidencing awards and all other related documents shall be governed by, and construed in accordance with the laws of the state of Delaware. If any provision shall be held by a court of competent jurisdiction to be invalid and unenforceable, the remaining provisions of this Plan shall continue in effect.

 

9.2                                NO RIGHT TO AN AWARD - Neither the adoption of this Plan nor any action of the Board or of the Committee shall be deemed to give any individual any right to be granted an award or any other rights hereunder except as may be evidenced by an award agreement duly executed on behalf of the Company, and then only to the extent and on the terms and conditions expressly set forth therein.

 

9.3                                NON-EXCLUSIVITY OF PLAN - Nothing in this Plan shall limit or be deemed to limit the authority of the Board or the Committee to grant awards or authorize any other compensation, with or without reference to the Shares, under any other plan or authority.

 

9.4                                NO EMPLOYMENT RIGHTS CONFERRED - Nothing contained in this Plan (or in any other documents relating to this Plan or to any award) shall confer upon any Eligible Person or other participant any right to continue in the employ or other service of the Company or any Affiliate or constitute any contract or agreement of employment or other service, nor shall interfere in any way with the right of the Company or any Affiliate to change such person’s compensation or other benefits or to terminate the employment of such person, with or without cause.

 

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10.                                MISCELLANEOUS

 

10.1                         UNFUNDED PLAN - Unless otherwise determined by the Committee, this Plan shall be unfunded and shall not create (or be construed to create) a trust or a separate fund or funds. This Plan shall not establish any fiduciary relationship between the Company or any Affiliate and any participant or other person. To the extent any person holds any rights by virtue of awards granted under this Plan, such rights shall be no greater than the rights of an unsecured general creditor of the Company.

 

10.2                         AWARDS NOT COMPENSATION - Unless otherwise determined by the Committee, settlements of awards received by participants under this Plan shall not be deemed a part of a participant’s regular, recurring compensation for purposes of calculating payments or benefits from any Company benefit plan, severance program or severance pay law of any country.

 

10.3                         FRACTIONAL SHARES - The Company shall not be required to issue any fractional Shares pursuant to this Plan. The Committee may provide for the elimination of fractions or for the settlement thereof in cash.

 

10.4                         COMPLIANCE WITH SECURITIES LAWS - Nothing herein or in any award granted hereunder shall require the Company to issue any shares with respect to any award if that issuance would, in the opinion of counsel for the Company, constitute a violation of the Securities Act of 1933, as amended, or any similar or superseding statute or statutes, any other applicable statute or regulation, or the rules of any applicable securities exchange or securities association, as then in effect.

 

10.5                         CLAWBACK - The Committee shall have the right to provide, in an award agreement or otherwise, or to require a participant to agree by separate written or electronic instrument, that an award (including any proceeds, gains or other economic benefit actually or constructively received by the participant upon any receipt or exercise of any award or upon the receipt or resale of any Shares underlying any award) shall be subject to the provisions of any clawback policy implemented by the Company or its Affiliates, including, without limitation, any clawback policy adopted to comply with the requirements of applicable law, including without limitation the Dodd Frank Wall Street Reform and Consumer Protection Act and any rules or regulations promulgated thereunder, to the extent set forth in such clawback policy and/or in the applicable award agreement.

 

10.6                         SECTION 409A - In the event that any award granted pursuant to this Plan provides for a deferral of compensation within the meaning of the Nonqualified Deferred Compensation Rules, it is the general intention, but not the obligation, of the Company to design such award to comply with the Nonqualified Deferred Compensation Rules and such award should be interpreted accordingly.  Notwithstanding anything in this Plan to the contrary, to the extent that the Committee determines that any award under this Plan may be subject to the Nonqualified Deferred Compensation Rules, the Committee may, without a participant’s consent, adopt such amendments to this Plan and the applicable award agreement or take any other actions (including amendments and actions with retroactive effect), that the Committee, in its sole discretion, determines are necessary or appropriate to preserve the intended tax treatment of the award, including, without limitation, actions intended to (a) exempt such award from the Nonqualified Deferred Compensation Rules, or (b) comply with the requirements of the Nonqualified Deferred Compensation Rules; provided, however , that nothing in this Section 10.6 shall create any obligation on the part of the Company or any Affiliate to adopt any such amendment or take any other such action or any liability for any failure to do so. Notwithstanding anything herein to the contrary, in no event shall the Company or any Affiliate have any obligation to indemnify or otherwise compensate any participant for any taxes or interest imposed under the Nonqualified Deferred Compensation Rules or similar provisions of state or foreign law.

 

13




Exhibit 10.10

 

AGREEMENT FOR IMPLEMENTATION OF AN

 

OPTIMIZED WATERFLOOD PROGRAM

 

FOR THE LONG BEACH UNIT

 



 

TABLE OF CONTENTS

 

 

 

 

 

Page

 

 

 

 

 

RECITALS

1

 

 

 

 

 

Article 1

DEFINITIONS

3

 

 

 

 

 

 

1.01

 

Terms Defined in LBU Agreements

3

 

1.02

 

Other Defined Terms

4

 

1.03

 

Terms Defined in Other Sections

9

 

 

 

 

 

Article 2

OPTIMIZED WATERFLOOD PROGRAM

10

 

 

 

 

 

 

2.01

 

Agreement to Implement the Program

10

 

2.02

 

Services to be Provided by ALBI; Commitment of ALBI

10

 

2.03

 

Program Plans

16

 

2.04

 

Amendment of Program Plans

18

 

2.05

 

Annual Plans

18

 

2.06

 

Amendment of Annual Plans

21

 

2.07

 

Expenditures in Excess of Budget

22

 

2.08

 

Implementation of the Program

22

 

2.09

 

Standard of Care

22

 

2.10

 

Monthly Accountings

23

 

2.11

 

Payments by ALBI

24

 

2.12

 

Payments to ALBI and the City

25

 

2.13

 

City as Agent for Tract No. 2 Payments

25

 

2.14

 

Adjustments in the Value of Oil

26

 

2.15

 

No Late Payment Charges

27

 

2.16

 

Accounting Disputes

27

 

2.17

 

Dispute Resolution

29

 

2.18

 

Abandonment

29

 

2.19

 

Deposit of Computer Program

31

 

2.20

 

Termination of the Program

31

 

2.21

 

Effect of Termination

32

 

2.22

 

Effect of this Agreement on Sell-Offs

32

 

 

 

 

 

Article 3

EXTENSION OF CONTRACTORS’ AND TRACT NO. 2 AGREEMENTS

33

 

 

 

 

 

 

3.01

 

Extension of Contractors’ Agreement

33

 

3.02

 

Extension of Tract No. 2 Agreement

34

 

 

 

 

 

Article 4

COAL OIL POINT SETTLEMENT

35

 

 

 

 

 

 

4.01

 

Dismissal and Releases

35

 

 

 

 

 

Article 5

ENABLING LEGISLATION AND EFFECTIVENESS OF THIS AGREEMENT

36

 

 

 

 

 

 

5.01

 

Enabling Legislation

36

 

i



 

 

5.02

 

Effectiveness of this Agreement

37

 

 

 

 

 

Article 6

REPRESENTATIONS AND WARRANTIES

38

 

 

 

 

 

 

6.01

 

Representations and Warranties of the State

38

 

6.02

 

Representations and Warranties of the City

38

 

6.03

 

Representations and Warranties of the ARCO Parties

39

 

6.04

 

Deliveries Following Execution

40

 

 

 

 

 

Article 7

MISCELLANEOUS PROVISIONS

40

 

 

 

 

 

 

7.01

 

Expenses

40

 

7.02

 

Entire Agreement

40

 

7.03

 

Waivers; Accord and Satisfaction

41

 

7.04

 

Counterparts

41

 

7.05

 

Governing Law

42

 

7.06

 

Notices

42

 

7.07

 

Successors and Assigns

44

 

7.08

 

Headings

44

 

7.09

 

Severability; Waiver of Applicable Laws

44

 

7.10

 

Construction

45

 

7.11

 

Remedies Cumulative

45

 

7.12

 

Equitable Remedies

45

 

7.13

 

Agreement Not Admissible

45

 

7.14

 

Time of the Essence

45

 

7.15

 

Attorneys’ Fees and Costs

45

 

7.16

 

Relationship of Parties

45

 

7.17

 

Guarantee of Performance

46

 

7.18

 

Further Assurances

46

 

 

 

 

 

SCHEDULE OF EXHIBITS

 

 

 

 

 

 

 

A

Determination of Base Development Plan

 

 

B

Base Costs

 

 

C

Scope of the Program

 

 

D

Form of Depository Agreement

 

 

E

Form of CA Amendment

 

 

F

Form of T2 Amendment

 

 

G

Form of Releases

 

 

H

Form of Quitclaim

 

 

I

Enabling Legislation

 

 

J

Form of Certificate of Resolutions of ARCO Board of Directors

 

 

K

Form of Certificate of Resolutions of ALBI Board of Directors

 

 

ii



 

AGREEMENT FOR IMPLEMENTATION OF AN
OPTIMIZED WATERFLOOD PROGRAM
FOR THE LONG BEACH UNIT

 

THIS AGREEMENT FOR IMPLEMENTATION OF AN OPTIMIZED WATERFLOOD PROGRAM FOR THE LONG BEACH UNIT (this “Agreement”) is made and entered into as of the 5th day of November, 1991, by and among the State of California (the “State”), by and through the State Lands Commission (the “SLC”), the City of Long Beach (the “City”), Atlantic Richfield Company, a Delaware corporation (“ARCO”), and ARCO Long Beach, Inc., a Delaware corporation and a wholly owned subsidiary of ARCO (“ALBI”).  ARCO and ALBI are collectively referred to herein as the “ARCO Parties,” and the State, by and through the SLC, the City and the ARCO Parties are collectively referred to herein as the “Parties.”

 

RECITALS

 

A.                                     ALBI believes that, if given the opportunity, it can design and, in conjunction with the City, implement an optimized waterflood program that would result in the production of a substantial volume of oil from the Long Beach Unit over and above the volume of oil that would be produced from continuation of the development program employed historically.  If realized, the increased production would benefit all of the owners in the Long Beach Unit, as well as the State, which has the largest financial interest in the Long Beach Unit.

 

B.                                     Implementation of an optimized waterflood program will involve substantial additional costs.  Under the existing contractors’ agreements for Tracts 1 and 2 of the Long Beach Unit, the State would bear more than 95% of the additional costs allocated to those Tracts out of the revenues otherwise payable to the State.  The State is unwilling to bear this additional economic risk because (1) there is a significant risk that the additional production will

 



 

be insufficient to compensate for the additional costs and (2) important State water, education and general programs that depend upon oil revenue from the Long Beach Unit should not bear the risk of any reduction in revenues resulting from the costs of implementing the optimized waterflood program.

 

C.                                     Accordingly, in order to induce the State to allow ALBI to design and, in conjunction with the City, to implement an optimized waterflood program for the Long Beach Unit, it is necessary for ALBI to bear these additional costs, and in connection therewith ALBI will agree to make a minimum commitment of $100,000,000 to design and implement the Program.  The State in turn will grant to ALBI a 50% (49% from and after January 1, 2000) net profits interest in the State’s portion of the incremental production that may result from the program, reserving to the State the remaining 50% (51% from and after January 1, 2000) net profits interest from that production.

 

D.                                     The State and ARCO believe that it is in their respective interests to resolve a dispute concerning development of ARCO’s State oil and gas leases near Coal Oil Point, in State waters offshore Santa Barbara County, by ARCO’s surrender to the State of its interests in two of those leases and dismissal of a pending lawsuit and appeal, entitled Atlantic Richfield Co., et al. v. State Lands Commission, et al. , No. C663010 (Los Angeles County Superior Court) and No. 2 Civil B054449 (California Court of Appeal).  The surrender of these leases and dismissal of the lawsuit and appeal will settle for the State the right to maintain the area of the Coal Oil Point leases free from oil and gas development and will relieve the parties to the lawsuit from the burden of continued litigation expense.

 

E.                                      It is necessary and appropriate that the City perform various accountings under this Agreement.

 

2



 

F.                                       It is also necessary and appropriate to accomplish these objectives that this Agreement continue for the economic life of the Long Beach Unit and that the existing contractors’ agreements for Tracts 1 and 2 of the Long Beach Unit be extended through the economic life of the Long Beach Unit.  It is fair and equitable to the State and to all other parties to those contracts to provide each party to those contracts with the option to extend the term of its contract and to require that ARCO assume the extended term of any such party refusing the extension.

 

G.                                     The California legislature has enacted enabling legislation to authorize this Agreement on behalf of the State, to extend the terms of the existing contractors’ agreements and to give ALBI and the City the powers to accomplish the objectives of the optimized waterflood program.

 

NOW, THEREFORE, in consideration of the mutual promises herein set forth, it is agreed as follows:

 

ARTICLE 1
DEFINITIONS

 

1.01                     Terms Defined in LBU Agreements .  Except as otherwise provided herein or unless the specific context in which any such term is used in this Agreement indicates a contrary intention of the Parties, all terms defined in or for purposes of the LBU Agreements shall have the same meanings as used in this Agreement.  The terms “approval,” “determination” and “establish” as used herein (whether as nouns or verbs) shall have their normal meanings, and shall not have the defined meaning set forth in the Unitization Agreements (as defined in Section 1.51 of the Unit Agreement), unless the context so requires.

 

3



 

(a)                                  LBU Agreements .  “LBU Agreements” shall mean the Unit Agreement, the Unit Operating Agreement; the Contractors’ Agreement and the Tract No. 2 Agreement, as such agreements have been amended, modified or supplemented.

 

(b)                                  Unit Agreement .  “Unit Agreement” shall mean the Unit Agreement, dated as of November 1, 1964, among the City, the State and certain Working Interest Owners, relating to the unitization of the Long Beach Unit of the Wilmington Oil Field, California.

 

(c)                                   Unit Operating Agreement .  “Unit Operating Agreement” shall mean the Unit Operating Agreement, dated as of November 1, 1964, among the City, the State and certain Working Interest Owners, relating to the development and operation of the Unitized Formations and the Unitized Area.

 

(d)                                  Contractors’ Agreement .  “Contractors’ Agreement” shall mean the Contractors’ Agreement, effective as of the effective date of the Unit Agreement and the Unit Operating Agreement, among the City, the Field Contractor and the Nonoperating Contractors named therein, relating to the operation of Tract No. 1 by the Field Contractor under the direction and control of the City.

 

(e)                                   Tract No. 2 Agreement .  “Tract No. 2 Agreement” shall mean the Tract No. 2 Agreement, effective as of the effective date of the Unit Agreement and the Unit Operating Agreement, between the State and the Contractor named therein, relating to production from Tract No. 2.

 

1.02                     Other Defined Terms .

 

(a)                                  Actual Revenues .  “Actual Revenues” for any period shall mean the sum of all Unit revenues recognized for such period that are allocated as “credits” for

 

4



 

purposes of either Section 4(a)(1) of the Contractors’ Agreement or Section 4(a)(1) of the Tract No. 2 Agreement.

 

(b)                                  Actual Costs .  “Actual Costs” for any period shall mean the sum of all Unit costs and expenses incurred for such period that are allocated as “charges” for purposes of either Section 4(a)(2) of the Contractors’ Agreement or Section 4(a)(2) of the Tract No. 2 Agreement.

 

(c)                                   State’s Actual Weighted Average Net Profits Percentage Interest in Tract Nos. 1 and 2 .  “State’s Actual Weighted Average Net Profits Percentage Interest in Tract Nos. 1 and 2” for any period shall mean the weighted average of the City’s actual weighted average net profits percentage interest for Tract No. 1 and the State’s actual net profits percentage interest for Tract No. 2.

 

(d)                                  State’s Actual Net Profits .  The “State’s Actual Net Profits” for any period shall mean the difference between Actual Revenues and Actual Costs for such period multiplied by the State’s Actual Weighted Average Net Profits Percentage Interest in Tract Nos. 1 and 2 for such period.

 

(e)                                   Base Revenues .  “Base Revenues” for any period shall mean the lesser of (i) Actual Revenues for such period and (ii) Actual Revenues for such period multiplied by the quotient of base oil production for such period divided by total oil production from the Long Beach Unit for such period.  For purposes of the determination of Base Revenues, base oil production for any period shall be calculated by the Computer Program in the manner described in Exhibit A attached hereto.

 

(f)                                    Base Costs .  “Base Costs” for any period shall mean the sum of (i) Unit costs and expenses, other than the costs of abandoning Unit Wells and Unit Facilities,

 

5



 

anticipated to be incurred for such period that would be allocated as “charges” for purposes of either Section 4(a)(2) of the Contractors’ Agreement or Section 4(a)(2) of the Tract No. 2 Agreement if the Program were not implemented, as calculated in the manner described in Exhibit B attached hereto, and (ii) any Unit costs or expenses actually incurred during such period by reason of extraordinary events that materially impact Unit operations, including but not limited to (by way of example) a significant change in land use for a non-Unit development project such as an amusement park, an act of God such as a major earthquake, an extraordinary and material expense such as the replacement of all or most of the Unit pipelines, or an extraordinary and material change in environmental or land use regulation, which costs or expenses are allocated as “charges” for purposes of either Section 4(a)(2) of the Contractors’ Agreement or Section 4(a)(2) of the Tract No. 2 Agreement, but only to the extent such costs or expenses would have been incurred if the Program had not been implemented.

 

(g)                                   State’s Base Revenues .  The “State’s Base Revenues” for any period shall mean the Base Revenues for such period multiplied by the State’s Actual Weighted Average Net Profits Percentage Interest in Tract Nos. 1 and 2 for such period.

 

(h)                                  State’s Base Costs .  The “State’s Base Costs” for any period shall mean the Base Costs for such period multiplied by the State’s Actual Weighted Average Net Profits Percentage Interest in Tract Nos. 1 and 2 for such period.

 

(i)                                      State’s Base Net Profits .  The “State’s Base Net Profits” for any month shall mean the difference between the State’s Base Revenues and the State’s Base Costs for that, month; provided, however, (i) for any month in which the State’s Base Costs exceed the State’s Base Revenues, the State’s Base Net Profits shall be zero and the amount by which the State’s Base Costs exceeds the State’s Base Revenues shall be added to the State’s Incremental

 

6



 

Costs for such month, and (ii) if under Section 2.10(a) or 2.14 any future accounting reflects that for any period there exists a positive amount of the State’s Base Net Profits, the State’s Base Net Profits for such period shall be reduced (but not below zero) to the extent of the cumulative amount added to the State’s Incremental Costs pursuant to (i) above, and the State’s Incremental Costs for such month shall be reduced (but not below zero) by an equal amount.  If at any time after Fiscal Year 2000, the aggregate Base Costs for any period of 24 consecutive months are equal to or exceed the aggregate Base Revenues for such period, (i) the State’s Base Net Profits shall be equal to zero through the duration of Article 2, (ii) there shall be no further obligation to calculate the State’s Base Net Profits, the State’s Base Costs, the State’s Base Revenues, Base Costs and Base Revenues and (iii) for each period through the duration of Article 2: (A) the State’s Incremental Net Profits less the State’s entire share of abandonment costs shall be equal to the State’s Actual Net Profits, (B) Incremental Costs plus all abandonment costs allocable to Tract Nos. 1 and 2 shall be equal to Actual Costs, and (C) Incremental Revenues shall be equal to Actual Revenues.

 

(j)                                     Incremental Revenues .  “Incremental Revenues” for any period shall mean Actual Revenues less Base Revenues for such period.

 

(k)                                  Incremental Costs .  “Incremental Costs” for any period shall mean (i) Actual Costs less (ii) the sum of Base Costs and the costs allocable to Tract Nos. 1 and 2 of abandoning Unit Wells and Unit Facilities for such period.

 

(l)                                      State’s Incremental Revenues .  The “State’s Incremental Revenues” for any period shall mean the Incremental Revenues for such period multiplied by the State’s Actual Weighted Average Net Profits Percentage Interest in Tract Nos. 1 and 2 for such period.

 

7


 

(m)                              State’s Incremental Costs .  Subject to adjustment as provided in Section 1.02(i), the “State’s Incremental Costs” for any period shall mean the Incremental Costs for such period multiplied by the State’s Actual Weighted Average Net Profits Percentage Interest in Tract Nos. 1 and 2 for such period.

 

(n)                                  State’s Incremental Net Profits .  The “State’s Incremental Net Profits” for any month shall mean the difference between the State’s Incremental Revenues and the State’s Incremental Costs for that month; provided, however, that, for any month in which the State’s Incremental Costs exceed the State’s Incremental Revenues, the State’s Incremental Net Profits shall be zero and the amount by which the State’s Incremental Costs exceeds the State’s Incremental Revenues shall be added to a “Negative Incremental Net Profits Balance.” For any month that there exists a Negative Incremental Net Profits Balance, the State’s Incremental Net Profits, if any, calculated as in the preceding sentence shall be reduced (but not below zero) to the extent of the existing Negative Incremental Net Profits Balance, which Balance shall be reduced (but not below zero) by an equal amount.

 

(o)                                  Development Costs .  “Development Costs” for any period shall mean the aggregate amount of Unit Expense during such period for engineering studies, field surveys, data acquisition and analysis, drilling new wells and redrilling existing wells and such other capital items as shall be necessary to implement the Program, as such amount is determined by THUMS Long Beach Company and the City.  Development Costs shall not include routine repair and maintenance expenses.

 

(p)                                  Incremental Development Costs .  “Incremental Development Costs” for any period shall mean the positive amount, if any, of Development Costs for such period minus Base Drilling Capital for such period.  For this purpose, “Base Drilling Capital” for

 

8



 

any period shall be determined by the Computer Program in the manner described in Exhibit B attached hereto.

 

(q)                                  State’s Incremental Development Costs .  The “State’s Incremental Development Costs” for any period shall mean the Incremental Development Costs for such period multiplied by the State’s Actual Weighted Average Net Profits Percentage Interest in Tract Nos. 1 and 2 for such period.

 

(r)                                     Fiscal Year .  “Fiscal Year” means a fiscal year commencing on July 1 and ending on the following June 30, or such different fiscal year as from time to time may be agreed upon among the Parties.  A reference to a specified Fiscal Year shall be a reference to the Fiscal Year ending during such specified year.

 

(s)                                    Remaining Oil Revenue .  “Remaining Oil Revenue” means “remaining oil revenue” as defined in Section 4(d) of Chapter 138.

 

1.03                     Terms Defined in Other Sections .  Certain additional terms used herein are defined elsewhere in this Agreement, as follows:

 

 

Defined Term

 

Section

 

 

Annual Plan

 

2.05(a)

 

 

CA Amendment

 

3.01

 

 

CA Extended Term

 

3.01

 

 

Computer Program

 

2.19

 

 

Enabling Legislation

 

5.01

 

 

Program

 

2.01

 

 

Program Commencement Date

 

2.10(a)

 

 

Program Plans

 

2.03(a)

 

 

Section 2.02(a) Expenditures

 

2.02(a)

 

 

T2 Amendment

 

3.02

 

 

T2 Extended Term

 

3.02

 

 

9



 

ARTICLE 2
OPTIMIZED WATERFLOOD PROGRAM

 

2.01                     Agreement to Implement the Program .  As provided in this Agreement, the City, the State and ALBI hereby agree to implement and to cause the implementation of an optimized waterflood program for the Long Beach Unit (the “Program”) in accordance with the Program Plans to be adopted hereunder.  The scope of the Program shall include and be limited to the types of operational programs described in Exhibit C attached hereto.

 

2.02                     Services to be Provided by ALBI; Commitment of ALBI .

 

(a)                                  ALBI hereby agrees to use its reasonable best efforts to increase production above Base Production over the economic life of the Long Beach Unit to the greatest extent feasible using the Program.  ALBI’s efforts shall be reflected in its design of the Program, its proposal from time to time of such modifications to the Program as it shall deem appropriate and its implementation in conjunction with the City of the Program as provided more fully below.  Within 60 days after the end of each Fiscal Year during which the commitment set forth in Section 2.02(b) is in effect, ALBI shall deliver to the SLC and the City a written report, certified by the Business Manager for the Western District of ARCO Oil and Gas Company or another comparable or more senior officer of ARCO or one of its subsidiaries, specifying the costs incurred by or on behalf of ALBI under this Section 2.02(a) during the preceding Fiscal Year that are not Unit Expense (“Section 2.02(a) Expenditures”).  Such costs may include without limitation expenditures for engineering studies and work performed on behalf of ALBI by independent third party contractors or consultants.  Section 2.02(a) Expenditures that are incurred internally by ARCO, ALBI or another of ARCO’s wholly owned subsidiaries shall be accounted for on the basis of actual direct costs (including without limitation salaries, employee

 

10



 

benefits and associated wage burdens such as social security and payroll taxes) and indirect costs at the rate of 25% of direct costs; provided, however, that no indirect costs factor for computer services shall be includible as Section 2.02(a) Expenditures.  Charges for mainframe and super-computer usage shall be calculated using ARCO’s internal inter-departmental rates.  Section 2.02(a) Expenditures for engineering studies and work performed by independent third party contractors or consultants shall be accounted for on the basis of the ARCO Parties’ actual direct costs with no indirect costs factor applied.  Nothing herein shall prohibit expenditures otherwise eligible for inclusion as Section 2.02(a) Expenditures from being paid by the Long Beach Unit as Unit Expense.  At the time each annual budget is submitted to the SLC pursuant to Section 2.05(b), ALBI shall submit to the SLC a written estimate of the Section 2.02(a) Expenditures to be made during the Fiscal Year covered by the budget proposal.

 

(b)                                  It is understood and agreed that the Program shall include expenditures for engineering studies, field surveys, data acquisition and analysis, drilling new wells and redrilling existing wells and such other capital items as shall be necessary to implement the Program.  In connection with the preparation of each annual budget for the Long Beach Unit contemplated by Section 2.05(a), ALBI, subject to Section 2.20(c), will propose that the budget include expenditures in the form of Incremental Development Costs that, when combined with Section 2.02(a) Expenditures anticipated to be made during the Fiscal Year covered by the budget, would result in the cumulative aggregate expenditure of Incremental Development Costs and Section 2.02(a) Expenditures from the inception of the Program through the end of that Fiscal Year of not less than the amount set forth in the table below opposite the applicable Fiscal Year:

 

11



 

 

Fiscal Year

 

Cumulative
Expenditures
(in millions)

 

 

1993

 

$

15

 

 

1994

 

35

 

 

1995

 

55

 

 

1996

 

70

 

 

1997

 

85

 

 

1998

 

100

 

 

Notwithstanding any other provision hereof to the contrary, the maximum amount of Section 2.02(a) Expenditures that may be included in the foregoing cumulative expenditures (whether for the purpose of proposing expenditures or for the purpose of determining actual expenditures as provided in Section 2.02(c)) during such period shall be as set forth in the table below:

 

 

Fiscal Year

 

Cumulative
Maximum
Section 2.02(a)
Expenditures
(in millions)

 

 

1993

 

$

2.25

 

 

1994

 

5.25

 

 

1995

 

8.25

 

 

1996

 

10.50

 

 

1997

 

12.75

 

 

1998

 

15.00

 

 

(c)                                   In the event that the cumulative aggregate sum of Incremental Development Costs and Section 2.02(a) Expenditures is less than the amount set forth in Section 2.02(b) for any such Fiscal Year: (i) ALBI shall within 30 days after the end of such Fiscal Year submit a written report setting forth the reasons for the shortfall in expenditures; and (ii) the SLC may terminate this Article 2 within 105 days after the end of such Fiscal Year in the event ALBI within 60 days after the end of such Fiscal Year has failed to propose a budget or a modification to the budget for the succeeding Fiscal Year pursuant to Section 2.05 or 2.06 that,

 

12



 

together with the cumulative aggregate Section 2.02(a) Expenditures previously made and estimated for such succeeding Fiscal Year, will result in a total of Incremental Development Costs and Section 2.02(a) Expenditures equal to or greater than the amount set forth in Section 2.02(b) for such succeeding Fiscal Year; and (iii) the SLC may terminate this Article 2 within 45 days after the end of such succeeding Fiscal Year in the event that the cumulative aggregate sum of Incremental Development Costs and Section 2.02(a) Expenditures made through the end of such succeeding Fiscal Year is less than 90% of the amount set forth in Section 2.02(b) for such succeeding Fiscal Year.  If the cumulative aggregate sum of Incremental Development Costs and Section 2.02(a) Expenditures does not equal or exceed $100,000,000 through Fiscal Year 1998 (subject to extension as provided in Section 2.02(f)): (i) the SLC may terminate this Article 2 within 105 days after the end of such period in the event ALBI within 60 days after the end of such period has failed to propose a budget or a modification to the budget for either or both the current and the succeeding Fiscal Years, as appropriate, pursuant to Section 2.05 or 2.06 that, together with the cumulative aggregate Section 2.02(a) Expenditures previously made and estimated for such Fiscal Years, will result in a cumulative total of Incremental Development Costs and Section 2.02(a) Expenditures of not less than $100,000,000 through the end of the 12-month period following Fiscal Year 1998 (subject to extension as provided in Section 2.02(f)); and (ii) the SLC may terminate this Article 2 within 45 days after the end of such 12-month period in the event that the cumulative aggregate sum of Incremental Development Costs and Section 2.02(a) Expenditures made through the end of such period is less than $100,000,000.

 

(d)                                  (i) For periods succeeding the period covered by Section 2.02(b), as it may be extended by Section 2.02(f), ALBI, subject to Section 2.20(c), will continue in good

 

13



 

faith to make Section 2.02(a) Expenditures and to propose and implement, in conjunction with the City, budgets including Incremental Costs.

 

(ii)                                   In the course of its review of an annual budget under Section 2.05(b), the SLC may give written notice to ALBI and the City that it has determined that the Section 2.02(a) Expenditures and the annual budget proposed by ALBI are insufficient to fulfill the obligations of ALBI under Section 2.02(d)(i).  The SLC may terminate this Article 2 within 105 days after any such notice is given in the event ALBI within 60 days after any such notice is given fails to propose either or both additional Section 2.02(a) Expenditures and a revised budget or a modification to the budget pursuant to Section 2.05 or 2.06 sufficient to fulfill such obligations.

 

(e)                                   Notwithstanding anything to the contrary set forth in Sections 2.03 through 2.06, ALBI and the City shall not be required to make revisions to any Program Plan, Annual Plan, the budget included in any Annual Plan or any amendments or supplements to or modifications of any of the foregoing with respect to any Fiscal Year to incorporate any changes ordered by the SLC that would affect projects, developments or operations designated by ALBI as provided below involving (or reasonably anticipated to involve) up to a total maximum of $16,000,000 of Actual Costs, as increased by the GNP Inflator (as defined in Exhibit B hereto) through the last day of the month prior to the submission of an annual budget or an amendment or supplement thereto or modification thereof pursuant to Section 2.05(b) or 2.06, as applicable; provided, however, that the SLC shall be permitted to order a change otherwise prohibited by the foregoing clause if and only to the extent that the SLC specifically finds that such change is necessary to (i) prevent waste, (ii) conserve oil and gas, (iii) avoid significant safety or environmental risks or (iv) a combination of the foregoing.  The provisions of Sections 2.03

 

14



 

through 2.06, as applicable, shall govern the procedures by which any changes ordered by the SLC pursuant to the foregoing proviso shall be imposed, challenged and altered.  If the SLC orders any changes pursuant to Section 2.03, 2.04, 2.05 or 2.06 for reasons other than those set forth in this Section, ALBI shall be permitted to designate in writing to the SLC and the City those changes, if any, ordered by the SLC that will not be incorporated as permitted by this Section.  Any such designation by ALBI shall be given within 45 days after the SLC has ordered any such changes.  In the event of a challenge by ALBI alleging that the SLC is prohibited by this Section 2.02(e) from ordering any change, the court hearing the challenge shall determine whether the SLC is prohibited by this Section from ordering the change prior to determining whether the change ordered by the SLC is reasonable.

 

(f)                                    ALBI shall be relieved of its commitments set forth in this Section if and to the extent: (i) the budget or budgets, or any amendments or supplements thereto or any modifications thereof, approved in accordance with this Agreement and the LBU Agreements do not provide for expenditures sufficient to meet such commitments, or such expenditures are budgeted but not made, as a result of actions or omissions of the SLC or the City; (ii) the SLC concurs in the determination of ALBI and the City that additional expenditures are not necessary to increase production to the greatest extent feasible using the Program; (iii) the expenditure of such funds has been prevented, in whole or in material part, by strikes, lockouts, fire, war, civil disturbances, acts of God, federal, state, county or municipal laws, orders or regulations, inability to secure materials, accidents or other causes beyond the reasonable control of either or both of ALBI and the City, in which case such commitments shall be deferred and extended for as long as such circumstances prevent the expenditures; or (iv) the SLC otherwise determines that good cause exists for the failure to make such expenditures.

 

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(g)                                   The SLC’s sole remedy against the ARCO Parties for any failure by the ARCO Parties to meet the commitments set forth in this Section is to terminate this Agreement in accordance with the above provisions and retain all of the benefits theretofore granted the State under this Agreement (including the settlement of the Coal Oil Point dispute provided for in Article 4 and the benefits of any expenditures made by or on behalf of ALBI pursuant to this Article 2).  Any such termination shall be effective upon the giving of a notice of termination by the SLC to ALBI and the City.  Any termination pursuant to Section 2.02(c) shall not be subject to Section 2.21(b).

 

(h)                                  Except as provided elsewhere in this Agreement, the ARCO Parties shall not be entitled to any payments or fees from the City or the State in connection with their services under this Section or Sections 2.03 through 2.08.

 

2.03                     Program Plans .

 

(a)                                  ALBI and the City shall prepare plans (“Program Plans”) pursuant to which the Program is to be implemented and carried out.  Each Program Plan shall cover a period of five years commencing on the first day of the term of the immediately succeeding Annual Plan (except that the first Program Plan shall cover a period of approximately four and one-half years commencing as soon as practicable after December 31, 1991).  Each Program Plan shall also include two schedules setting forth for each of the first two years all of the matters (except the itemized budget of intended expenditures) required to be included in annual plans of development and operation as contemplated by Section 5(a) of Chapter 138 and Section 4.2 of the Unit Agreement.  The schedule for the first year included in the first Program Plan shall cover the period from a date as soon as practicable after December 31, 1991 through June 30, 1992.  Each Program Plan shall be subject to review and revision by the SLC for consistency

 

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with good oil field practice, the Program and the Unit and Unit Operating Agreements and for environmental and safety concerns.  Subject to Section 5(c) of Chapter 138, ALBI and the City shall revise each Program Plan to incorporate the changes ordered by the SLC where the SLC has found the changes to be necessary to assure that the Program Plan (i) is consistent with good oil field practice, or (ii) is consistent with the Program, or (iii) is consistent with the Unit and Unit Operating Agreements, or (iv) does not involve significant safety or environmental risks, or for any combination of the foregoing reasons (i) through (iv).  The SLC shall specify in writing with particularity the reason or reasons for each ordered change.  Either or both of ALBI and the City may apply to a court of competent jurisdiction to challenge the changes ordered by the SLC.  Subject to Section 5(c) of Chapter 138, the Program Plan adopted by ALBI and the City with whatever changes are ordered by the SLC shall go into effect and stay in effect, subject to any additional approvals that may be required by the Unit Agreement, unless and until a court of competent jurisdiction determines in the exercise of its independent judgment that the SLC is prohibited by Section 2.02(e) hereof from ordering any changes or that any changes ordered by the SLC are not reasonable.  In the event of such a judicial determination, the Program Plan shall be altered to revoke any changes ordered by the SLC found by the court to be prohibited by Section 2.02(e) or in other cases as ordered by the court.  The first Program Plan shall be prepared and formally submitted to the SLC not later than 60 days after this Agreement becomes effective in accordance with Section 5.02.  Each subsequent Program Plan shall be prepared and formally submitted to the SLC at least 100 days prior to the expiration of the second Annual Plan adopted pursuant to the then current Program Plan.  Each Program Plan shall be informally submitted in draft form to the staff of the SLC at the same time that it or any budget based upon it is formally submitted to the City Council of the City.  The SLC shall have a period of 45 days

 

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following the formal submission of each Program Plan to complete its review of the Program Plan.  If the SLC does not order any changes to a Program Plan within 45 days of its formal submission, such Program Plan shall be deemed to be reviewed and accepted by the SLC.

 

2.04       Amendment of Program Plans .  Any Program Plan may be amended, supplemented or modified as and when deemed necessary or appropriate by ALBI and the City, subject to review and revision by the SLC in accordance with the provisions of Section 2.03 hereof, except that the 45-day period set forth in Section 2.03 shall be a 30-day period for purposes of this Section 2.04.

 

2.05       Annual Plans .

 

(a)           Each year, ALBI and the City shall prepare an annual plan for the implementation of the then current Program Plan and as contemplated by and sufficient for purposes of Article 4 of the Unit Agreement (an “Annual Plan”).  Each Annual Plan shall consist of the appropriate schedule from the current Program Plan and an itemized budget of intended expenditures, which budget shall not be organized by operational programs but shall be organized by categories of total expenditures.  In the event that ALBI and the City are unable to resolve any dispute relating to the budget included or to be included in any Annual Plan or any amendment or supplement thereto or modification thereof, each of ALBI and the City shall submit to the SLC a statement of its position with respect to such dispute.  Subject to the rights of the SLC to order changes to a budget as provided in Section 2.05(b), the SLC shall resolve the dispute during the course of its budgetary review provided for in Section 2.05(b) by selecting for inclusion in the budget either the entire proposal of ALBI or the City; provided, however, that the SLC shall not be permitted to select a proposal of the City that would require a greater expenditure of Incremental Costs than the proposal of ALBI unless and only to the extent that the

 

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SLC specifically finds that such greater expenditure is necessary to avoid subsidence or significant environmental or safety risks.  Any such decision by the SLC shall be final and binding on ALBI and the City; except that either ALBI or the City may apply to a court of competent jurisdiction to challenge any decision made by the SLC pursuant to the proviso set forth in the preceding sentence.  The adoption of an Annual Plan or an amendment or supplement thereto or modification thereof under this Agreement shall constitute the adoption of such Annual Plan or such amendment, supplement or modification by the City and the State (subject to the rights of the SLC under Section 2.05(b)) for purposes of Article 4 of the Unit Agreement.  The City, the State and the ARCO Parties hereby covenant and agree to vote for, approve of and consent to each and every Annual Plan, and any and all amendments or supplements thereto or modifications thereof, after adoption under this Agreement to the extent that under any LBU Agreement any of them may or is required to vote on, approve of or consent to any such Annual Plan, amendment, supplement or modification.

 

(b)           Each proposed budget and each proposed amendment or supplement to or modification of a budget included in an Annual Plan shall be subject to review and revision by the SLC for consistency with the current Program Plan.  Subject to Section 5(c) of Chapter 138 and the limitations set forth below, ALBI and the City shall revise each budget, amendment, supplement or modification to incorporate changes ordered by the SLC where the SLC has found the changes to be necessary to assure the consistency of the budget with the Program Plan.  The SLC shall specify in writing with particularity the reason or reasons for each ordered change.  Either or both of ALBI and the City may apply to a court of competent jurisdiction to challenge the changes ordered by the SLC, with the challenge of ALBI limited to whether the SLC is prohibited by Section 2.02(e) hereof from ordering such changes.  Subject to

 

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Section 5(c) of Chapter 138 and the limitations set forth below, the budget, amendment, supplement or modification to a budget adopted by ALBI and the City with whatever changes are ordered by the SLC shall go into effect and stay in effect, subject to any additional approvals that may be required by the Unit Agreement, unless and until a court of competent jurisdiction determines in the exercise of its independent judgment that the SLC is prohibited by Section 2.02(e) hereof from ordering any changes or that any changes ordered by the SLC are not reasonable.  In the event of such a judicial determination, the budget shall be altered to revoke any changes ordered by the SLC found by the court to be prohibited by Section 2.02(e) or in other cases as ordered by the court.  Except as otherwise specifically provided in Section 2.05(a): (i) in the event the SLC orders any change to be made in a budget reviewed by it hereunder, any increase in any category of expenditures in excess of the amount set forth in the proposal of ALBI and the City (or the proposal of ALBI if ALBI and the City submit separate proposals as contemplated by Section 2.05(a)) shall be deemed to be Base Costs for all purposes of this Agreement; and (ii) if the aggregate Base Costs for any period of 24 consecutive months equal or exceed the aggregate Base Revenues for such period, the SLC thereafter shall not have the right to order any change to be made in a budget reviewed by it hereunder that would result in an increase in any category of expenditures in excess of the amount set forth in the proposal of ALBI and the City (or the proposal of ALBI if ALBI and the City submit separate proposals as contemplated by Section 2.05(a)).  Each proposed budget shall be prepared and formally submitted to the SLC at least 100 days prior to the first day of the Annual Plan year covered by such budget.  Each budget shall be informally submitted in draft form to the staff of the SLC at the same time that it is formally submitted to the City Council of the City.  The SLC shall have a period of 45 days following the formal submission of each budget to complete its review of the

 

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budget.  If the SLC does not order any changes to a budget within 45 days of its formal submission, such budget shall be deemed to be reviewed and accepted by the SLC.

 

(c)           Notwithstanding Section 2.05(b), the first Annual Plan, including the budgetary portion thereof, shall cover the period from a date as soon as practicable after December 31, 1991 through June 30, 1992, and shall be sufficient for purposes of constituting an amendment to the annual plan for Fiscal Year 1992 adopted pursuant to Article 4 of the Unit Agreement; and the first proposed budget to be included in the first Annual Plan shall be submitted to the SLC concurrently with the submission of the first Program Plan.

 

2.06       Amendment of Annual Plans .  The nonbudgetary portion of an Annual Plan may be amended, supplemented or modified as and when deemed necessary or appropriate by ALBI and the City, subject to review and revision by the SLC in accordance with the provisions of Section 2.04.  The budgetary portion of an Annual Plan may be amended, supplemented or modified as and when deemed necessary or appropriate by ALBI and the City, subject to review and revision by the SLC in accordance with the provisions of Section 2.05(b), except that the 45-day period set forth in Section 2.05(b) shall be a 30-day period for purposes of such review.  Any disputes between ALBI and the City with respect to any such amendment, supplement or modification shall be resolved by the SLC in accordance with the provisions of Section 2.05(a).  Notwithstanding the foregoing, the executive officer or acting executive officer of the SLC shall have the power to consent to an amendment or supplement to or modification of any portion of an Annual Plan, provided that such officer’s consent shall be subject to ratification by the SLC at its next regular meeting.  In the event the SLC does not ratify the consent of its executive officer or acting executive officer to such amendment, supplement or modification,

 

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neither the City, the ARCO Parties nor the Field Contractor shall be liable to the State for any actions taken or omitted under the consent or authority of the executive officer or acting executive officer.

 

2.07       Expenditures in Excess of Budget .  Notwithstanding the adoption of an Annual Plan hereunder, but subject to the approval, if required, of any parties to the Unit Agreement other than the State, the City or the ARCO Parties, the City, as the Unit Operator, acting with the consent of ALBI (which shall not be unreasonably withheld), shall have the authority to cause the expenditure of funds for Unit Operations in excess of the amount set forth in any budget included in an Annual Plan; provided, however, that no such expenditure shall be incurred that would result in any category of expenditures set forth in the budget to exceed 120% of the budgeted amount for that category.  Such categories of expenditures may include without limitation operating cost, staff expenses, taxes (other than income taxes), development drilling, geological/geophysical exploration and plant capital.

 

2.08       Implementation of the Program .  Each Party hereby agrees to do all things and to take all actions as shall be reasonably necessary, appropriate or convenient to formulate, adopt, modify and implement timely the Program, the Program Plans and the Annual Plans.  In addition to the procedures specifically provided for in this Article 2, the Parties shall consult with one another on an informal basis as shall be necessary, appropriate or convenient in connection with the implementation of the Program or the performance of this Article 2.

 

2.09       Standard of Care .  In any claim, action or proceeding by one or more of the Parties against any other Party or its directors, officers, employees, agents or independent contractors arising out of the design, formulation, proposal, adoption, amendment, supplementation, modification or implementation of the Program, any Program Plan or any Annual Plan, such other Party or person shall be held to the same standard of care as set forth for

 

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the Unit Operator in Section 7.9 of the Unit Operating Agreement.  This Agreement, however, shall not affect the standard of care or other liability standard set forth in any of the LBU Agreements with respect to any conduct to which such LBU Agreement applies.

 

2.10       Monthly Accountings .

 

(a)           For so long as this Article 2 remains in effect, the State shall receive as its total revenue from the Contractors’ Agreement and the Tract No. 2 Agreement for any period the sum of the State’s Base Net Profits plus 50% (51% from and after January 1, 2000) of the State’s Incremental Net Profits for such period, after adjusting for (by subtracting) the State’s allocable portion of abandonment costs for such period provided for in Section 2.18.  Subject to Section 2.14 hereof, an accounting of the State’s Base Net Profits, the State’s Incremental Net Profits, the Incremental Development Costs, the State’s Incremental Development Costs, the State’s entire share of abandonment costs and the State’s allocable portion of abandonment costs shall be made on a monthly basis, commencing on January 1, 1992 (the “Program Commencement Date”).  The accounting shall be made by the City in addition to the other accountings it performs under the LBU Agreements.  Each such monthly accounting shall be completed and reported in writing to ALBI and the SLC on or before the last working day of the following month.  Each accounting shall provide sufficient detail to permit the verification of the accounting by ALBI and the SLC.

 

(b)           In performing the accountings, the City will be required to have certain calculations made by the Computer Program as described in Exhibits A and B hereto.  The calculations made by the Computer Program will generate data on a quarterly basis, which must be converted to a monthly basis in order to perform the required accountings.  The City shall convert such data by dividing each item of data by the actual number of days in the quarter

 

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in question, and thereupon multiplying the resulting quotient by the actual number of days in the month in question.  If, for purposes of the determination of Base Revenues under Section 1.02(e) or the determination of Base Costs under clause (i) of Section 1.02(f), there shall be any conflict between the calculations contained in the Computer Program and the descriptions of such calculations set forth in Exhibit A or Exhibit B hereto, the calculations contained in the Computer Program shall control.  All additional calculations required in connection with this Agreement that are not made by the Computer Program shall be made in accordance with the relevant provisions of this Agreement.

 

(c)           The accountings to be made pursuant to Section 2.10(a) shall have no effect on the calculation of Remaining Oil Revenue for purposes of distributing to the City a portion of Remaining Oil Revenue; provided, however, that the costs incurred by the City in performing such accountings shall be included as amounts “expended by the City in administering oil and gas operations on the Long Beach tidelands” under Section 4(d) of Chapter 138.

 

2.11       Payments by ALBI .  If any monthly accounting pursuant to Section 2.10(a) reflects that (i) the aggregate sum for the month of the State’s Base Net Profits plus 50% (51% from and after January 1, 2000) of the State’s Incremental Net Profits, after adjusting for (by subtracting) the State’s allocable portion of abandonment costs provided for in Section 2.18, exceeded (ii) the State’s Actual Net Profits for the month, ALBI shall pay to the City, on or before the 35th day following the end of the month to which the accounting relates, an amount equal to such difference for such month, as set forth in the accounting made by the City.  The portion of any and all such payments in respect of Tract No. 1 shall be added to Tract No. 1 revenues in determining Remaining Oil Revenue for distribution between the State and the

 

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City.  The portion of any and all such payments in respect of Tract No. 2 shall be paid in its entirety by the City to the State.

 

2.12       Payments to ALBI and the City .  If any monthly accounting pursuant to Section 2.10(a) reflects that (i) the State’s Actual Net Profits for the month exceeded (ii) the aggregate sum for the month of the State’s Base Net Profits plus 50% (51% from and after January 1, 2000) of the State’s Incremental Net Profits, after adjusting for (by subtracting) the State’s allocable portion of abandonment costs provided for in Section 2.18, the City shall pay to ALBI, on or before the 35th day following the end of the month to which the accounting relates (but in any event prior to the payment to the State of any funds with respect to such month), an amount equal to such difference for such month, as set forth in the accounting made by the City.  In addition, commencing January 1, 1996, the State shall pay monthly to the City, at the same time of each payment to ALBI under this Section, the amount required by Section 2(b)(1) of the Enabling Legislation.  Each such payment shall be made by the retention of funds by the City otherwise due to the State from Tract No. 1.  Any and all such payments by the City to ALBI and itself shall be paid by the City on behalf of the State prior to any distribution between the SLC and the City from Remaining Oil Revenue.  Notwithstanding any other provision of this Agreement to the contrary, the State shall be and remain liable to ALBI for any and all payments to be made under this Agreement by the City to ALBI even if Remaining Oil Revenue and revenues of the State derived from production from Tract No. 2 are at any time insufficient to make such payment.

 

2.13       City as Agent for Tract No. 2 Payments .  In order to facilitate the accountings by the City required under this Agreement, the City shall act as agent for the State with respect to the receipt of net profit payments due the State from the Tract No. 2 Contractor.

 

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The City shall receive monthly the net profit payments directly from the Tract No. 2 Contractor and hold these payments in a separate interest-bearing account.  The City shall determine each month whether any portion of the payment is needed to make any payments to ALBI required by Sections 2.12 and 2.14.  As soon as it determines that no portion of the monthly net profit payment is needed to make the next payment to ALBI under Section 2.12 or any then due payment to ALBI under Section 2.14, the City shall transmit to the State the Tract No. 2 net profit payment with any interest earned and collected thereon.  If all or any portion of the Tract No. 2 net profit payment is needed to make a payment to ALBI, the City shall use this money to make that payment and then immediately transmit to the State any remaining balance with any remaining interest earned and collected thereon.

 

2.14       Adjustments in the Value of Oil .  If and when the Value of Oil Allocated to a Contractor or the Value of Oil Allocated to the Contract Lands, respectively, is adjusted pursuant to Section 9(e) of the Contractors’ Agreement or Section 7(e) of the Tract No. 2 Agreement (including any subsequent adjustments required upon the successful challenge by a Contractor under the Contractors’ Agreement or the Contractor under the Tract No. 2 Agreement of an adjustment made pursuant to Section 9(e) of the Contractors’ Agreement or Section 7(e) of the Tract No. 2 Agreement, as provided therein), all monthly accountings made pursuant to Section 2.10(a) hereof covering periods affected by any such adjustments shall also be adjusted in the same manner.  Adjustments under this Agreement shall be made by the City and reported in writing to ALBI and the SLC within 10 days after any such adjustments under the Contractors’ Agreement or the Tract No. 2 Agreement are made.  Each adjustment under this Agreement shall provide sufficient detail to permit the verification of the adjustment of the accountings by ALBI and the SLC.  Within 15 days after the adjustment payments under the

 

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Contractors’ Agreement and Tract No. 2 Agreement are received by the City, ALBI or the City shall pay to the other, and the State or the City shall pay to the other, the amount necessary to give effect to the adjustment made hereunder.  Any such payments to or by ALBI shall be made by or to the City, as the case may be, on behalf of the State.  Any such payment made by the City to ALBI or itself shall be made in the manner and in accordance with the priorities set forth in Section 2.12.

 

2.15       No Late Payment Charges .  There shall be no late penalties or interest assessed or payable in respect of any payments required under Sections 2.11, 2.12 and 2.14 that are not made when due.

 

2.16       Accounting Disputes .

 

(a)           In order to permit verification of the written reports provided by the ARCO Parties pursuant to Section 2.02(a), authorized representatives of the SLC may with respect to any such report (i) inspect the supporting accounting records of the ARCO Parties and (ii) obtain such additional information from the ARCO Parties as is relevant thereto within two years after such report has been delivered by the ARCO Parties.  In order to permit verification of the accountings made by the City pursuant to Section 2.10(a) and Section 2.14, authorized representatives of either the SLC or ALBI may with respect to any such report (i) inspect the supporting records of the city and (ii) obtain such additional information from the City as is relevant thereto for a period of two years after such report has been delivered by the City.  Notwithstanding the foregoing, (A) the two-year time limitation provided for in this Section shall be extended to five years with respect to any inspection or inquiry made for the purpose of determining whether one or more accounting errors have been made on a repetitive and recurrent basis, and (B) in the event that any Party formally disputes an accounting pursuant to Sections

 

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2.16(c) and (d) or 2.17, the rights provided for in this Section shall continue with respect to such accounting for the duration of the dispute.

 

(b)           For purposes of inspections and inquiries made under Section 2.16(a), the authorized representatives of a Party may include accounting, legal and engineering personnel of or retained by the Party.  Any Party desiring to conduct such an investigation shall give the Party whose records are to be inspected a notice requesting access for such purpose.  The involved Parties shall agree upon a reasonable time and place for the inspection to be made.  It shall be presumed to be reasonable if the Party whose records are to be inspected offers to permit the inspection to be made at the location where such records are regularly maintained within 10 business days after it receives the inspection request.  For purposes of this Section 2.16, the term inspection shall include the right to take notes of, make extracts from and make photocopies of the accounting records being inspected.  Any accounting records made available hereunder for inspection shall be held in confidence and shall not be disclosed by any of such persons to any third party except in connection with any disputes under Sections 2.16(c) and (d) or 2.17.  Neither the ARCO Parties nor the City shall dispose of any accounting records subject to inspection under this Section 2.16 until after the maximum time period for inspection permitted hereunder has expired.

 

(c)           In the event that the SLC or ALBI disputes any accounting made under Section 2.02(a), 2.10(a) or 2.14, it shall give written notice to the other Party and the City, specifying with particularity the errors it alleges in such accounting.  Such notice must be given within two years after the accounting was delivered by the Party responsible therefor; provided, however, that the foregoing two-year time limitation shall be extended to five years with respect to any dispute alleging that one or more accounting errors have been made on a repetitive and

 

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recurrent basis.  Promptly after any such notice has been given, the involved Parties shall in good faith attempt to resolve the dispute on a fair and equitable basis.

 

(d)           If the involved Parties are not able to resolve the dispute within 60 days after the initial written notice has been given under Section 2.16(c), the dispute shall be submitted for binding arbitration pursuant to Section 2.17.

 

2.17       Dispute Resolution .  Disputes arising under this Article 2 that are neither to be resolved by the SLC as provided in Section 2.05(a) nor specifically reserved herein to be heard by a court of competent jurisdiction shall be resolved by a general reference conducted in Los Angeles County, California, by a retired judge from the panel of Judicial Arbitration & Mediation Services, Inc. (JAMS), appointed pursuant to the provisions of California Code of Civil Procedure Sections 638(1)  et seq .  The Parties intend this general reference agreement to be specifically enforceable in accordance with said Section 638(1).  If the Parties cannot agree upon a member of the JAMS panel, one shall be appointed by the Presiding Judge of Los Angeles County Superior Court.

 

2.18       Abandonment .  This Agreement shall not in any way affect the responsibility for abandoning any Unit Wells or Unit Facilities, which responsibility shall remain as set forth in the LBU Agreements and under existing law.  This Agreement shall allocate between the State and ALBI the State’s share of the costs of abandoning Unit Wells and Unit Facilities, as follows:

 

(a)           The State shall bear its entire share of the costs of abandoning any Unit Wells and Unit Facilities existing as of the Program Commencement Date (“Existing Unit Wells” and “Existing Unit Facilities”) and any Unit Facilities that simply replace Existing Unit Facilities or that otherwise would have been built even if the Program had not been implemented.

 

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The Existing Unit Wells and Existing Unit Facilities shall be identified on a written inventory to be provided to ALBI and the SLC by the City within 60 days of the Program Commencement Date.  For purposes of this Section, any redrill of an Existing Unit Well other than a surface redrill shall be considered an Existing Unit Well.

 

(b)           ALBI shall bear 50% of the State’s entire share of the costs of abandoning any Unit Facilities built after the Program Commencement Date and that would not have been built had the Program not been implemented.

 

(c)           The State shall bear on a well-by-well basis that portion of its entire share of the costs of abandoning any Unit Wells not existing as of the Program Commencement Date equal to the sum of (i) the quotient of 1.42 times the number of Base Production Wells (as defined in Exhibit A) theoretically drilled after the Program Commencement Date pursuant to the base development plan embodied in the Computer Program and described in Exhibit A divided by the total number of unit wells (excluding redrills other than surface redrills) actually drilled after the Program Commencement Date, plus (ii) 50% of the remaining percentage of the State’s entire share of abandoning any Unit Well covered by the foregoing clause (i) but not borne by the State pursuant to such clause (i).

 

(d)           ALBI shall bear on a well-by-well basis the remainder of the State’s entire share of abandoning any Unit Well covered by subsection (c) above but not borne by the State pursuant to subsection (c).

 

(e)           The costs of abandoning Unit Wells or Unit Facilities are neither Base Costs nor Incremental Costs.  The allocations in subsections (a) through (d) above are and shall be independent of Base Costs and Incremental costs.  Notwithstanding the foregoing, the accountings to be made under Sections 2.10 through 2.12 shall be adjusted, as provided therein,

 

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to give effect to the allocation of the State’s entire share of abandonment costs provided for in this Section 2.18.

 

2.19       Deposit of Computer Program .  The base development plan described in Exhibits A and B hereto is based upon a model embodied in a computer program and related software (the “Computer Program”) developed jointly by the ARCO Parties and the SLC, which Computer Program is hereby incorporated by reference into this Agreement.  In order to protect and preserve the Computer Program in the form agreed upon by such Parties, an exact copy of the Computer Program shall be transferred to a disk or disks (or other media) and stored by a mutually acceptable independent third party in accordance with the procedures and provisions of a Depository Agreement substantially in the form attached hereto as Exhibit D, which shall be entered into concurrently with this Agreement.  No Party shall be permitted to have access to such disk or disks (or other media) except as provided in the Depository Agreement.

 

2.20       Termination of the Program .  The obligations of the Parties under this Article 2 shall terminate upon the first to occur of the following:

 

(a)           The written agreement of ALBI and the State to terminate such provisions.

 

(b)           The termination of the Unit Agreement in accordance with Section 15.1 thereof.

 

(c)           Upon 60 days’ prior written notice from ALBI to the State in the event that ALBI determines, in its discretion, that continuation of the Program is not in the economic interests of ALBI.

 

(d)           After the expiration of the period covered by Section 2.02(b), as it may be extended by Section 2.02(f), 60 days after the last day of any Fiscal Year for which there

 

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were no Incremental Costs but only if there were no Incremental Revenues for that Fiscal Year and for the immediately preceding Fiscal Year, upon written notice that the State elects to terminate delivered by the SLC to ALBI within such 60-day period.

 

(e)           A termination by the SLC pursuant to Section 2.02 hereof.

 

(f)            A termination by the ARCO Parties pursuant to Section 5.01 hereof.

 

2.21       Effect of Termination .

 

(a)           The termination of this Article 2 shall not affect the rights and liabilities of the Parties to one another with respect to the performance of this Article 2 during the period prior to such termination, which rights and liabilities shall survive such termination.  Any such termination shall have no effect on any provisions of this Agreement other than this Article 2 or on any provisions of any LBU Agreement.

 

(b)           Except as otherwise expressly set forth in section 2.02(g), it shall be a condition of any termination of this Article 2 by the State pursuant to Section 2.02 or Section 2.20(d) that the State shall pay to ALBI an amount equal to the Negative Incremental Net Profits Balance as of the effective date of the termination and after giving effect to the final accounting pursuant to Sections 2.10(a) and 2.14.  Any such payment shall be made within 35 days of the effective date of the termination, with an adjusted payment, if necessary, made by the appropriate Party within 30 days after the final accounting pursuant to Section 2.14.

 

2.22       Effect of this Agreement on Sell-Offs .  This Agreement shall not in any way affect the provisions of agreements relating to the sell-off of oil pursuant to Article 11(a) of the Contractors’ Agreement or the State’s right to take in-kind oil pursuant to Article 9 of the Tract No. 2 Agreement, including without limitation Article 5(d) of the Contractors’ Agreement,

 

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providing for payment of excess value, and Articles 9(b)(3) and (4) and Article 9(e) of the Contractors’ Agreement and Articles 7(b)(3) and (4) and Article 7(e) of the Tract No. 2 Agreement, providing for adjustments to the value of oil allocated.  The rights to sell off oil or to take in-kind oil shall continue to apply to all oil actually produced without regard to whether such oil is classified as base or incremental production for purposes of this Agreement.

 

ARTICLE 3
EXTENSION OF CONTRACTORS’ AND TRACT NO. 2 AGREEMENTS

 

3.01       Extension of Contractors’ Agreement .  If the provisions of Article 2 of this Agreement have not been terminated in accordance with the provisions of this Agreement by January 1, 1995, the term of the Contractors’ Agreement shall be extended as of June 30, 1995, from and after April 1, 2000, to be coterminous with the Unit Agreement, with respect to each Contractor whose interest has not otherwise terminated pursuant to Article 30 of the Contractors’ Agreement (the “CA Extended Term”).  If so extended, the extension of the Contractors’ Agreement shall be evidenced by an amendment thereto substantially in the form of Exhibit E attached hereto (the “CA Amendment”), with only such changes as shall be ministerial in nature or shall have been approved in writing by ARCO and the City.  During January 1995, the City shall send a written notice to each Person Comprising the Field Contractor or a Nonoperating Contractor as of that date (the “CA Offerees”), which notice shall offer to each CA Offeree the right to maintain its interest in the Contractors’ Agreement during the CA Extended Term.  Such offer shall inure to the benefit of the permitted successors and assigns of each CA Offeree.  Such offer shall state that it shall remain open and irrevocable by the City (subject to the continued effectiveness of the Contractors’ Agreement with respect to the applicable CA Offeree and the continued effectiveness of the Unit Agreement) until 4:30 p.m. on June 30, 1995.  The notice

 

33



 

shall provide an exclusive means by which the offer contained therein may be accepted in writing, which shall include the submission of a duly executed and notarized signature page to the CA Amendment.  ARCO hereby agrees that it shall be deemed automatically to have accepted the offer, if made, with respect to its entire interest as a Contractor or a Person Comprising a Contractor under the Contractors’ Agreement.  Accordingly, ARCO and the City hereby agree to dispense with any notice and acceptance of such offer to and by ARCO.  If one or more CA Offerees fail to accept the offer by the City as provided in the notice to be given by the City, then for the CA Extended Term, ARCO shall become, as provided in the CA Amendment, the Contractor or Person Comprising a Contractor with respect to any and all interests of all such CA Offerees (including their respective successors and assigns) under the Contractors’ Agreement.

 

3.02       Extension of Tract No. 2 Agreement .  If the provisions of Article 2 of this Agreement have not been terminated in accordance with the provisions of this Agreement by January 1, 1995, the term of the Tract No. 2 Agreement shall be extended, as of June 30, 1995, from and after April 1, 2000, to be coterminous with the Unit Agreement, unless sooner terminated in accordance with the provisions of Article 23 of the Tract No. 2 Agreement (the “T2 Extended Term”).  If so extended, the extension of the Tract No. 2 Agreement shall be evidenced by an amendment thereto substantially in the form of Exhibit F attached hereto (the “T2 Amendment”), with only such changes as shall be ministerial in nature or shall have been approved in writing by ARCO and the SLC.  During January 1995, the SLC shall send a written notice to each Person Comprising the Contractor as of that date (the “T2 Offerees”), which notice shall offer to each T2 Offeree the right to maintain its interest in the Tract No. 2 Agreement during the T2 Extended Term.  Such offer shall inure to the benefit of the permitted

 

34



 

successors and assigns of each T2 Offeree.  Such offer shall state that it shall remain open and irrevocable by the SLC (subject to the continued effectiveness of the Tract No. 2 Agreement and the Unit Agreement) until 4:30 p.m. on June 30, 1995.  The notice shall provide an exclusive means by which the offer contained therein may be accepted in writing, which shall include the submission of a duly executed and notarized signature page to the T2 Amendment.  If one or more T2 Offerees fail to accept the offer by the SLC as provided in the notice to be given by the SLC, then for the T2 Extended Term, ARCO shall become, as provided in the T2 Amendment, the Person Comprising the Contractor with respect to any and all interests of all such T2 Offerees (including their respective successors and assigns) under the Tract No. 2 Agreement.

 

ARTICLE 4
COAL OIL POINT SETTLEMENT

 

4.01       Dismissal and Releases .  Based on the consideration and provisions set forth in this Agreement, promptly after the effective date of this Agreement,

 

(a)           The parties to the action and the appeal entitled Atlantic Richfield Co., et al. v. State Lands Commission, et al. , No. C663010 (Los Angeles County Superior Court) and No. 2 Civil B054449 (California Court of Appeal) shall file with the court a dismissal with prejudice of all causes of action asserted in that action except for the Fifth Cause of Action, which is asserted only against the Santa Barbara County defendants, and with the Court of Appeal a dismissal of the appeal;

 

(b)           Each of the parties plaintiff to that action shall exchange with each of the parties defendant to that action releases in the form of Exhibit G hereto; and

 

(c)           ARCO shall deliver to the State a quitclaim of ARCO’s rights under State Oil and Gas Leases Nos. 308 and 309, P.R.C., dated March 4, 1947, as amended,

 

35



 

substantially in the form of Exhibit H hereto.  The quitclaim shall be determinable upon the termination of this Agreement pursuant to Section 5.01 during the time period specified in Section 5.01.  The quitclaim shall become void and shall have no further force or effect upon such a termination of this Agreement during such time period and the satisfaction by ARCO of the payment condition provided for by Section 5.01.

 

ARTICLE 5
ENABLING LEGISLATION AND
EFFECTIVENESS OF THIS AGREEMENT

 

5.01       Enabling Legislation .  The legislation attached hereto as Exhibit I (the “Enabling Legislation”) adopted by the California Legislature and approved by the Governor of the State of California authorizes the State to enter into this Agreement.  The Enabling Legislation shall be deemed to be a part of this Agreement and is hereby incorporated herein by reference.  The Parties agree not to challenge the validity of the Enabling Legislation at any time, which agreement shall survive any termination of this Agreement pursuant to any of subsections (a) through (e) of Section 2.20.  In the event that the Enabling Legislation is finally determined by the courts to be void or unconstitutional in any material respect, which determination has an adverse effect on the rights or obligations of either or both of the ARCO Parties provided for in or contemplated by this Agreement, the ARCO Parties shall have the right to terminate this Agreement by written notice given to the other Parties within 60 days after such final determination.  Any such termination shall not affect the rights and liabilities of the Parties to one another with respect to this Agreement during the period prior to such termination or pursuant to this Section, which rights and liabilities shall survive such termination; provided, however, that if the ARCO Parties terminate pursuant to this provision prior to the 15th

 

36



 

anniversary after the date of recordation of the quitclaim provided for by Article 4 (subject to extension as provided in the quitclaim) as a result of a determination of voidness or unconstitutionality, made at any time, in a lawsuit or other proceeding commenced prior to January 1, 1997, such quitclaim shall have no further force and effect as provided therein, and ARCO’s rights under Leases Nos. 308 and 309 then shall be in full force and effect notwithstanding anything in such leases or the SLC regulations to the contrary if and only if within 60 days after such termination ARCO makes a payment to the City, which shall receive and apply the payment in the same manner as provided in Section 2.11, equal to the sum of (i) 50% of the aggregate amount of the State’s Incremental Net Profits from the Program Commencement Date through the earlier of December 31, 1999 and the date of termination and (ii) 49% of the aggregate amount of the State’s Incremental Net Profits from January 1, 2000 through the date of termination (if the date of termination occurs after December 31, 1999), after adjusting for (by subtracting) ALBI’s allocable portion of abandonment costs for such period or periods provided for in Section 2.18.

 

5.02       Effectiveness of this Agreement .  Sections 5.01 and 6.04 of this Agreement shall become effective upon the date of this Agreement.  The remainder of this Agreement shall become effective on the latest of (i) the date of the last delivery required by Section 6.04, (ii) the date that each of the County of Santa Barbara, the Santa Barbara County Air Pollution Control District and the Sierra Club Legal Defense Fund give irrevocable written notice to ARCO and the State that they will participate in the dismissal of the lawsuit and the exchange of releases described in Section 4.01 and (iii) the date of this Agreement.

 

37


 

ARTICLE 6
REPRESENTATIONS AND WARRANTIES

 

6.01       Representations and Warranties of the State .  The State hereby represents and warrants to the ARCO Parties that:

 

(a)           It has the power and authority to enter into this Agreement and the Exhibits hereto to be executed and delivered by it hereunder and to perform its obligations hereunder and thereunder.

 

(b)           It has taken all action and has secured the consents of all persons necessary to authorize the execution, delivery and performance of this Agreement and the Exhibits hereto to be executed and delivered by it hereunder.

 

(c)           This Agreement has been duly executed and delivered by it and constitutes a valid and binding obligation of it, enforceable against it in accordance with its terms.

 

(d)           Each Exhibit hereto to be executed and delivered by it hereunder, when so delivered, will have been duly executed and delivered by it and will constitute a valid and binding obligation of it, enforceable against it in accordance with its terms.

 

(e)           This Agreement does not require the approval of the Governor of the State of California pursuant to Section 6107 of the California Public Resources Code.

 

6.02       Representations and Warranties of the City .  The City hereby represents and warrants to the ARCO Parties that:

 

(a)           It has the power and authority to enter into this Agreement and the Exhibits hereto to be executed and delivered by it hereunder and to perform its obligations hereunder and thereunder.

 

38



 

(b)           It has taken all action and has secured the consents of all persons necessary to authorize the execution, delivery and performance of this Agreement and the Exhibits hereto to be executed and delivered by it hereunder.

 

(c)           This Agreement has been duly executed and delivered by it and constitutes a valid and binding obligation of it, enforceable against it in accordance with its terms.

 

(d)           Each Exhibit hereto to be executed and delivered by it hereunder, when so delivered, will have been duly executed and delivered by it and will constitute a valid and binding obligation of it, enforceable against it in accordance with its terms.

 

(e)           The City is not a party to the lawsuit described in Section 4.01 and makes no representation, warranty or covenant with respect to such lawsuit or to Section 4.01.

 

6.03       Representations and Warranties of the ARCO Parties .  Each of the ARCO Parties hereby represents and warrants to the State and the City that:

 

(a)           It has the corporate power and authority to enter into this Agreement and the Exhibits hereto to be executed and delivered by it hereunder and to perform its obligations hereunder and thereunder.

 

(b)           It has taken all action and has secured the consents of all persons necessary to authorize the execution, delivery and performance of this Agreement and the Exhibits hereto to be executed and delivered by it hereunder.

 

(c)           This Agreement has been duly executed and delivered by it and constitutes a valid and binding obligation of it, enforceable against it in accordance with its terms.

 

39



 

(d)           Each Exhibit hereto to be executed and delivered by it hereunder, when so delivered, will have been duly executed and delivered by it and will constitute a valid and binding obligation of it, enforceable against it in accordance with its terms.

 

6.04       Deliveries Following Execution .

 

(a)           Upon the execution of this Agreement or as soon thereafter as practicable, each of the ARCO Parties shall deliver to the SLC and the City a duly executed certificate of resolutions adopted by their respective Boards of Directors substantially in the forms attached hereto as Exhibit J in the case of ARCO and Exhibit K in the case of ALBI.

 

(b)           Upon the execution of this Agreement or as soon thereafter as practicable, (i) the SLC shall deliver to the ARCO Parties and the City a duly certified copy of minutes of a meeting of the SLC reflecting the approval of this Agreement and (ii) the City shall deliver to the ARCO Parties and the SLC a duly certified copy of minutes of a meeting of the City Council of the City reflecting the approval of this Agreement.

 

ARTICLE 7
MISCELLANEOUS PROVISIONS

 

7.01       Expenses .  Except as set forth herein, each Party shall pay its costs and expenses, including without limitation the fees of counsel, incurred by it in connection with this Agreement and the transactions contemplated hereby.

 

7.02       Entire Agreement .  This Agreement, the Exhibits hereto and the other agreements, documents and instruments delivered or to be delivered pursuant hereto or contemplated hereby, set forth the entire understanding of the Parties with respect to the subject matter hereof, supersede any and all prior agreements, arrangements and understandings with respect to the subject matter hereof, and may be modified only by a written instrument duly

 

40



 

executed by each Party affected by any such modification.  The Exhibits attached to this Agreement shall be deemed to be a part of this Agreement and are hereby incorporated by this reference.

 

7.03       Waivers; Accord and Satisfaction .  No breach of any covenant, condition, agreement, warranty or representation made herein or in any Exhibit hereto or the other agreements, documents or instruments delivered pursuant hereto or contemplated hereby, shall be deemed waived unless expressly waived in writing by the Party who might assert such breach.  Any such waiver by or on behalf of either or both of the ARCO Parties shall be effective only if it is signed by the Vice President of the Western District of ARCO Oil and Gas Company.  Any such waiver by or on behalf of the State shall be effective only if it is signed by the executive officer or acting executive officer of the SLC.  Any such waiver by or on behalf of the City shall be effective only if it is signed by the city manager or the acting city manager of the City.  Any such waiver may be made in advance or after the right waived has arisen or the breach or default waived has occurred.  Any such waiver may be conditional.  No such waiver shall be deemed to be a waiver of any other matter, whenever occurring and whether identical, similar or dissimilar to the matter waived.  No receipt or acceptance by any Party of any payment of any amount made hereunder in respect of the payment obligations set forth herein which is less than the amount due shall be deemed to be other than on account of the amount due before such receipt, acceptance or payment, and no endorsement or statement accompanying or in respect of any receipt, acceptance or payment shall be deemed an accord and satisfaction.

 

7.04       Counterparts .  This Agreement may be executed in one or more counterparts, all of which shall be considered one and the same agreement and each of which shall be deemed to constitute an original.

 

41



 

7.05       Governing Law .  This Agreement shall be governed by and construed in accordance with the laws of the State of California without giving effect to conflicts-of-laws rules and laws.

 

7.06       Notices .  Any notice or other communication required or permitted to be given hereunder shall be in writing and shall be mailed by registered or certified mail, postage prepaid, return receipt requested, or delivered by commercial courier against receipt or in person, as follows:

 

If to the State:

 

Executive Officer

State Lands Commission

1807 - 13th Street

Sacramento, California 95814

 

with a copy to:

 

Chief, Mineral Resources Management

State Lands Commission

245 West Broadway, Suite 425

Long Beach, California 90802

 

If to the City:

 

City Manager

13th Floor, City Hall

333 West Ocean Boulevard

Long Beach, California 90802

 

with a copy to:

 

Director of Department of Oil Properties

2nd Floor, City Hall

333 West Ocean Boulevard

Long Beach, California 90802

 

If to ARCO:

 

ARCO Oil and Gas Company

P.O.  Box 147

Bakersfield, California 93302 (for mail delivery only)

 

42



 

or

4550 California Avenue

Bakersfield, California 93309

 

Attention: Vice President and General Manager

 

with a copy to:

 

Atlantic Richfield Company

515 South Flower Street

Los Angeles, California 90071

 

Attention: Senior Vice President and General Counsel

 

If to ALBI:

 

ARCO Long Beach, Inc.

300 Oceangate

Long Beach, California 90802

 

Attention: Business Unit Manager

 

with a copy to:

 

Atlantic Richfield Company

515 South Flower Street

Los Angeles, California 90071

 

Attention: Senior Vice President and General Counsel or to such other address as such Party shall have furnished in writing in accordance with the provisions of this Section.  Any notice or other communication mailed by registered or certified mail shall be deemed given at the earlier of the time of its receipt by the addressee or seven days after the time of mailing thereof.  Any notice given in any other fashion shall be deemed to have been given when actually received by the addressee.  Payments required to be made under Article 2 hereof shall be made by wire transfer of immediately available funds to the account of the proper Party as such Party shall from time to time specify by written notice or by such other means as shall be agreed upon from time to time between the paying and receiving Parties.

 

43



 

7.07       Successors and Assigns .  This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors, legal representatives and assigns.  Except as set forth in Section 7.17, the ARCO Parties shall be permitted to assign (i) to one or more wholly owned subsidiaries of ARCO any or all of their respective rights and obligations hereunder and/or (ii) to any one or more other persons ALBI’s rights to make or receive up to and including 45% of the remaining payments to ALBI called for by Article 2 of this Agreement; provided, however, that any such assignment and assumption shall not relieve the ARCO Parties from liability with respect to any obligations or payments.  Except as provided in the preceding sentence, the ARCO Parties shall not be permitted to assign, pledge, hypothecate, encumber or otherwise transfer to any other person any of their respective obligations under or in respect of Article 2 of this Agreement without the prior written consent of the SLC.  For purposes of this Section, the sale by an ARCO Party of any of the stock of a wholly owned subsidiary to which it has made an assignment pursuant to this Section shall constitute an assignment to another person, requiring the prior written consent of the SLC.

 

7.08       Headings .  The headings of the Sections herein are inserted for convenience of reference only and are not intended to be a part of, or to affect the meaning or interpretation of, this Agreement.

 

7.09       Severability; Waiver of Applicable Laws .  If any one or more of the provisions of this Agreement shall be held to be invalid, illegal or unenforceable, the validity, legality or enforceability of the remaining provisions of this Agreement shall not be affected thereby.  To the extent permitted by applicable law, each Party hereby waives any provision of law which renders any provision of this Agreement invalid, illegal or unenforceable in any respect.

 

44



 

7.10       Construction .  The language in all parts of this Agreement shall in all cases be construed according to its fair meaning and not strictly for or against any of the Parties.

 

7.11       Remedies Cumulative .  Except as otherwise specifically provided herein, the remedies provided herein are cumulative with one another and with any other remedies which any Party may have at law, in equity, under any agreements of any type or otherwise, and the exercise or failure to exercise any remedy shall not preclude the exercise of that remedy at another time or of any other remedy at any time.

 

7.12       Equitable Remedies .  In addition to legal remedies to the extent allowed under this Agreement or by law, in recognition of the fact that remedies at law may not be sufficient, the Parties shall be entitled to equitable remedies, including without limitation specific performance and injunction.

 

7.13       Agreement Not Admissible .  This Agreement is made, at least in part, in compromise of litigation.  In the event that this Agreement does not become effective, neither this Agreement nor the discussions and negotiations between the parties shall be admissible in the Coal Oil Point lawsuit referred to in Section 4.01 or any related litigation.

 

7.14       Time of the Essence .  Time is of the essence in the performance of this Agreement.

 

7.15       Attorneys’ Fees and Costs .  If any litigation, reference or other proceeding between or among the Parties is commenced in connection with or related to this Agreement, the losing Party or Parties shall pay the costs and expenses of the prevailing Party or Parties.  Each Party shall bear its own attorneys’ fees.

 

7.16       Relationship of Parties .  Nothing set forth herein shall ever be construed to create an association, trust or partnership or impose a trust or partnership duty, obligation or

 

45



 

liability on or with regard to any one or more of the Parties hereto.  Except for the quitclaim referenced in Article 4 hereof, nothing herein grants, conveys, gives, alienates or vests in any Party for any purpose whatsoever any title, interest or estate in or to any lands whatsoever, or any title, interest or estate in or to any oil, gas and/or other hydrocarbons and/or other minerals.

 

7.17       Guarantee of Performance .  ARCO hereby guarantees the full performance by ALBI and its successors and assigns of all the obligations of ALBI under this Agreement.  This guarantee by ARCO may not be assigned without the express written consent of the SLC and the City.

 

7.18       Further Assurances .  Each Party agrees promptly to execute and deliver such documents and to do such other acts as are requested by another Party and are in the reasonable judgment of the requesting Party necessary or appropriate to effectuate the purposes of this Agreement.

 

46



 

IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed as of the day and year first above written.

 

 

 

 

THE STATE OF CALIFORNIA

 

 

 

 

By:

The State Lands Commission

 

 

 

 

By:

/s/ Charles Warren

 

 

Charles Warren

 

 

Executive Officer

 

 

 

 

THE CITY OF LONG BEACH

 

 

 

 

By:

/s/ John F. Shirey

 

 

John F. Shirey

 

 

Assistant City Manager

 

 

 

 

ATLANTIC RICHFIELD COMPANY

 

 

 

 

By:

/s/ Paul B. Norgaard

 

 

Paul B. Norgaard

 

 

Vice President

 

 

 

 

ARCO LONG BEACH, INC.

 

 

 

 

By:

/s/ Paul B. Norgaard

 

 

Paul B. Norgaard

 

 

President

 

The foregoing Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit is hereby approved as to form this 5th day of November, 1991.

 

 

JOHN R. CALHOUN, City Attorney

 

 

 

 

 

By:

/s/ Signature Illegible

 

 

Deputy

 

47


 

Exhibit A

Determination of Base Development Plan

 

Section 1

Introduction

 

1.1                                Purpose .  The purpose of this Exhibit A is to set out the technical method to quantify Base Production for purposes of Section 1.02 of the Agreement. The methods, formulae and procedures set forth are based on a theoretical development plan, “Base Development Plan,” described in the Exhibit.

 

1.2                                Definitions .  Unless defined herein all initially capitalized terms shall have the meaning set forth in the Agreement.

 

(a)                                  Base Development Plan The Base Development Plan is the theoretical LBU development which would have occurred if this Agreement had not been executed. Inclusive in this plan is the Base Oil, Base Water, Base Production Wells and associated injection wells resulting from it.

 

(b)                                  Base Production Well is a theoretical producing well added in the Base Development Plan.

 

(c)                                   Base Oil is the theoretical gross oil production from the entire Long Beach Unit that would be produced by the Base Development Plan.

 

(d)                                  Base Water is the theoretical gross water production from the entire Long Beach Unit that would be produced by the Base Development Plan.

 

(e)                                   Base Production as the term is used herein means either or both Base Oil or Base Water as the context requires.

 

(f)                                    Base Gross Fluid is the sum of Base oil and Base Water.

 

(g)                                   Base Cumulative Oil is the theoretical cumulative oil production at any point in time for the entire Long Beach Unit that would be produced by the Base Development Plan as of that point in time.

 

(h)                                  Payout Time is the time in years or fraction thereof required for a Base Production Well to produce enough oil that when multiplied by the then current oil price would equal or exceed the total costs to drill, complete, equip, and operate the well.

 

(i)                                      Payout Criterion is the maximum Payout Time for which a new Base Production Well will be drilled in the Base Development Plan.

 

1.3                                Procedure .  Because it is impossible to physically measure Base Production and because it is necessary to identify that portion of the actual oil and water production in the Long Beach Unit that is Base Production, a means to determine Base oil and Base Water is required. Base oil

 

A-1



 

and Base Water will be determined in each quarter through the use of the calculation procedure defined in Section 3 of this Exhibit.

 

Section 2

Theoretical Basis for the Base Development Plan

 

2.1                                Background .  Oil and gas producing reservoirs exhibit statistically consistently behaved performance patterns which can be applied to the Long Beach Unit (“LBU”) for use in forecasting Base Production. Certain management practices in the LBU have controlled the timing and development of the LBU hydrocarbon reserves. The major premise of the Base Development Plan is that the LBU will continue previously established performance trends and management practices. A model which projects these performance trends and management practices in a statistically consistent manner has been developed to forecast the Base Development Plan.

 

2.2                                Waterflood Response .  Oil reservoirs producing under waterflood exhibit a semi-logarithmic relationship between the instantaneous water-oil ratio and cumulative oil production. Since oil recovery from the reservoir is finite, wells drilled later in the life of a reservoir will normally have a higher water-oil ratio and lower ultimate oil recovery than wells drilled earlier. Producing history indicates that the LBU reservoirs follow these trends. A key assumption in the Base Development Plan is that the LBU reservoirs will continue to perform according to their previously established trends.

 

2.3                                Oil Rate Performance .  Oil reservoirs are known to exhibit certain oil rate performance trends over time. Oil reservoirs usually follow a hyperbolic oil rate decline versus time relationship represented by the following equation:

 

Equation 1

-1/n

q t  = q i  (1 - nD i t)

 

where:

 

q t

=

oil production rate at any time (t)

 

 

 

q i

=

initial oil production rate at t=0

 

 

 

n

=

hyperbolic decline coefficient

 

 

 

D i

=

initial decline fraction. Note D i  is a negative number.

 

 

 

t

=

time since start of production

 

A special case of the hyperbolic oil rate decline is the exponential decline where n=0 and oil rate is represented by the following equation:

 

A-2



 

Equation 2

D i t

q t  = q i  e

 

where:

 

q t

=

as defined for Equation 1

 

 

 

q i

=

as defined for Equation 1

 

 

 

D i

=

as defined for Equation 1

 

 

 

t

=

as defined for Equation 1

 

 

 

e

=

Naperian constant equal to 2.71828183

 

LBU history shows that wells grouped by the year they were drilled initially exhibit an exponential oil rate relationship. It has been found that these same wells at high water/oil ratios have a hyperbolic performance. The model utilized to formulate the Base Development Plan incorporates these observations.

 

2.5                                Producing Wells - Existing and Future .  The model predicts the performance of all active producing wells in the LBU as of July 1, 1990 and forecasts the performance of such wells for every quarter in the future. The Base Development Plan also incorporates the continued development of the LBU reservoirs through the addition of new producing and associated injection wells. The rate and performance of these new wells are determined by extrapolations of historical reservoir performance data. The number of new wells drilled in the Base Development Plan is limited by the Payout Time of each new well. As the LBU reservoirs mature, the quality of new wells which can be drilled decreases. In the Base Development Plan the Payout Time is used to determine the number of new well opportunities. A drilling program results with decreasing numbers of new wells drilled over time.

 

2.6                                New Well Ouality .  In addition to decreasing development opportunities over time, there are also variations in the qualities of new wells which can be drilled at any single time. As the LBU has matured, the number of wells which met the Payout Criterion has decreased. In years when oil prices have been higher than the historical average, more wells were drilled with Payout Time within the Payout Criterion. In years when oil prices have been lower than the historical average, fewer wells were drilled such that the well with the longest Payout Time still paid out without exceeding the Payout Criterion.

 

2.7                                Performance - New Base Production Wells .  The performance characteristics of Base Production Wells in the future will be predicted from extrapolations of past LBU performance. The Payout Time for each Base Production Well will be represented by application of the then-current oil price averaged over the year prior to the addition of the new well combined with the predicted performance characteristics of the well. The number of Base Production Wells to be drilled is determined by finding the last well with a Payout Time less than or equal to the applicable Payout Criterion.

 

A-3



 

Section 3

Components of Base Development Plan

 

3.1                                Background .  Base Oil, Base Water, and Base Production Wells associated with the Base Development Plan will be determined as follows:

 

A.                                     Oil and water production for wells which existed prior to July 1, 1990 will be taken from Attachment 1 to this Exhibit.

 

B.                                     Production characteristics for and the number of new Base Production Wells to be added in each quarter will be determined as described in Section 3.2.B.

 

C.                                     Oil and water production in each quarter for all Base Production Wells added in the previous quarters will be determined as described in Section 3.2.C.

 

D.                                     All monetary values associated with the Computer Program are in terms of January 1, 1990 dollars.

 

3.2                                Calculation Methodology .  For each quarter, the Base Production Wells, Base Oil Production, Base Water Production, and Base Cumulative Oil will be calculated in the following manner:

 

A.                                     The oil and water Production for wells which existed prior to July 1, 1990 is listed in Attachment 1 for each quarter starting in July 1, 1990 through January 1, 2020. After January 1, 2020 the oil production for these wells for each quarter thereafter will be equal to their oil production for the preceding quarter multiplied by 0.97, and the water production for each quarter thereafter will be equal to their water production for the preceding quarter multiplied 0.98.

 

B.                                     At the beginning of each quarter, new Base Production Wells may be added into the Base Development Plan. All new Base Production Wells added in an individual quarter will be treated as a single group in all future calculations. The production characteristics for each of the new Base Production Wells will be determined as a function of the Base Cumulative Oil for the Long Beach Unit at the start of the quarter. The number of new Base Production Wells to be added in the quarter will be determined such that each well will meet the Payout Criterion for that quarter.  The production characteristics from each new Base Production Well will be appropriately combined to reflect the composite characteristics for all Base Production Wells added in the quarter.

 

(i)                                      The production characteristics to be determined for each new Base Production Well are the slope and intercept of the ln(water/oil ratio) versus cumulative oil and the slope and intercept of the ln(oil rate) versus time and will be determined as described below.

 

(a)                                  The relationship between water/oil ratio (“WOR”) and cumulative oil production for each new well (represented by the subscript x) will be determined from the following equations (Equations 3 through 9):

 

A-4



 

Equation 3

[ (WA) (x) + WB ]

WOR ix  = e

 

where:

 

WOR ix

=

initial water/oil ratio for the x ‘th well added in the quarter

 

 

 

X

=

the number of the well drilled in the quarter

 

 

 

WA

=

as defined in Equation 4

 

 

 

WB

=

as defined in Equation 5

 

Equation 4

 

WA = (3.9351x10 -10 ) (BCO) - (0.15094)

 

where:

 

BCO

=

Base Cumulative oil at the beginning of the quarter (in stock tank barrels)

 

Equation 5

 

WB = (1.6104x10 -9 ) (BCO) - (0.80521)

 

where:

 

BCO

=

as defined for Equation 4

 

Equation 6

 

( ln (25.0) – ln(WOR ix ) )

SWOR x  =                                                                                             Res25 x

 

where:

 

SWOR x

=

slope of the ln(instantaneous water/oil ratio) versus cumulative oil produced for the x th  well added in the quarter

 

 

 

Ln

=

natural logarithm function, base e

 

 

 

WOR ix

=

as defined by Equation 3

 

 

 

Res25 x

=

Cumulative oil production at an instantaneous water/oil ratio of 25 for the x th  well added in the quarter, stock tank barrels - defined by Equation 7

 

A-5



 

Equation 7

 

[ (RA) (x) + (RB) ]

 

Res25 x  = e

 

where:

 

RA

=

as defined in Equation 8

 

 

 

x

=

as defined for Equation 3

 

 

 

RB

=

as defined in Equation 9

 

 

 

Res25 x

=

as defined for Equation 6

 

Equation 8

 

RA = (-6.2312x10 -10 ) (BCO) + (0.24767)

 

where:

 

BCO

=

as defined for Equation 4

 

Equation 9

 

RB = (-2.7510x10 -9 ) (BCO) + (14.993)

 

where:

 

BCO

=

as defined for Equation 4

 

(b)                                  The relationship between oil rate and time for each new Base Production Well added in the quarter will be determined from the following equations (Equations 10 through 16):

 

Equation 10

 

(D ix ) (t)

 

q tx  q ix  e

 

where:

 

q tx

=

oil rate at time t for the x th  well added in the quarter, stock tank barrels per day

 

 

 

q ix

=

initial oil rate for the x th  well added in the quarter, stock tank barrels per day - obtained from Equation 11

 

A-6



 

D ix

=

initial decline fraction for the x th  well added in the quarter, year -1  - obtained from Equation 14

 

 

 

t

=

time since start of production for the x th  well, years

 

Equation 11

 

[ (QA) (x) + (QB) ]

 

q ix  = e

 

where:

 

QA

=

as defined by Equation 12

 

 

 

x

=

as defined for Equation 3

 

 

 

QB

=

as defined by Equation 13

 

Equation 12

 

QA = (-4.3810x10 -10 ) (BCO) + (0.097410)

 

where:

 

BCO

=

as defined for Equation 4

 

Equation 13

 

QB = (-2.0273x10 -9 ) (BCO) + (7.0175)

 

where:

 

BCO

=

as defined in Equation 4

 

Equation 14

 

D ix  = (-1.0) ABS [ (DA) (x) + (DB) ]

 

where:

 

ABS

=

absolute value function

 

 

 

DA

=

as defined in Equation 15

 

 

 

x

=

as defined in Equation 3

 

 

 

DB

=

as defined in Equation 16

 

A-7



 

Equation 15

 

DA = (1.2500x10 -12 ) (BCO) - (0.000375)

 

where:

 

BCO

=

as defined by Equation 4

 

Equation 16

 

DB = (1.7500x10 -10 ) (BC0) + (0.0575)

 

where:

 

BCO

=

as defined in Equation 4

 

 

(ii)                                   After the production characteristics for each new Base Production Well in a quarter have been calculated, the Payout Time for each new well is determined. The calculation procedure for determining the payout for each new Base Production Well is as follows: The oil production per well to payout for each new Base Production Well added in the quarter is calculated from Equation 17 by iteratively solving for N px . The tolerance allowed for solution of Equation 17 is 0.5%.

 

Equation 17

 

[ (SWOR x ) (N px ) ]

Inv x  = N px  (P-Cost o  - Cost gf ) - (Cost gf ) (WOR i ) [ e                                                                                                                                                                             -1 ]

SWOR x

 

where:

 

N px

=

the cumulative oil produced from the x th  well added in the quarter which will result in that well being paid out.

 

 

 

 

 

The arithmetic average oil price of the four preceding quarters, in dollars per stock tank barrel, adjusted for inflation to January 1, 1990 dollars. The oil price for each of the quarters, before adjusting for inflation, will be the total Unit revenues recognized for such quarter that constitute “credits” for purposes of Section 4(a)(1) of the Contractors’ Agreement and Section 4(a)(1) of the Tract No. 2 Agreement, divided by total production allocated to Tracts 1 and 2 of the Long Beach Unit for such quarter. Oil price shall not be adjusted for any adjustments that actually may occur pursuant to Article 9(b)(3) and (4) or Article 9(c) of the Contractors’ Agreement or Article 7(b)(3) or (4) or Article 7(c) of the Tract No. 2 Agreement. The average oil price will be calculated by first adjusting the price for each quarter from the

 

A-8



 

 

 

middle of the quarter to January 1, 1990 dollars using the GNP deflator as defined in Exhibit B, then adding the adjusted prices for the four quarters together and dividing by four. The GNP deflator index is published for the middle of each quarter; for example, the index for the middle of the first quarter is the February index value.

 

As specified in Attachment 5, the beginning date for base case calculations is July 1, 1990, and the time increment is one quarter of a year. Notwithstanding the price-averaging calculation described in the paragraph above, the average oil price for the first time increment is the oil price in the first time increment; the average oil price in the second time increment is the average of the oil prices in the first two time increments; and the average oil price in the third time increment is the average of the oil prices in the first three time increments.

 

Note: The oil price input to the Computer Program must be deflated to January 1, 1990 dollars because no cost inflation is included in the Computer Program.

 

 

 

Cost o

=

The variable base expense per barrel of Base Oil expressed in January 1, 1990 dollars. This value is $0.290560, to be adjusted by the Oil Price Adjustment Factor and Cost Reduction Factor as defined in Exhibit B.

 

 

 

Cost gf

=

The variable base expense per barrel of Base Gross Fluid expressed in January 1, 1990 dollars. This value is $0.293756 to be adjusted by the Oil Price Adjustment Factor and Cost Reduction Factor as defined in Exhibit B.

 

 

 

WOR ix

=

as defined in Equation 3

 

 

 

SWOR x

=

as defined in Equation 6

 

 

 

Inv x

=

The total investment cost for adding a new Base Production Well, expressed in January 1, 1990 dollars, including the associated cost of adding a proportionate injection well. This value is $900,000, adjusted using the Oil Price Adjustment Factor defined in Exhibit B.

 

(iii)                                After N px  has been calculated for each new Base Production Well, the Payout Time for each well will be determined as follows:

 

A-9



 

Equation 18

 

Payout Time x  = ln [ (N px  (D ix ) / [ (q ix ) (365.) ] +1 ]

D ix

 

where:

 

Payout Time x

=

Payout Time, years, for the x th  well added in the quarter

 

 

 

N px

=

as defined in Equation 17

 

 

 

D ix

=

as defined in Equation 14. Note D ix  is a negative number.

 

 

 

q ix

=

as defined in Equation 11

 

(iv)                               After the Payout Time has been calculated for each new Base Production Well in the quarter, the number of new Base Production Wells to be added in the quarter will be determined. These new wells will be added starting with the first well until the last well exceeds the Payout Criterion as defined below. If one well has a Payout Time less than the Payout Criterion and the next well has a Payout Time greater than the Payout Criterion, then a fractional well will be added as follows. The fractional portion of the well will be calculated by linearly interpolating between the payout of the last whole well which has a Payout Time less than the Payout Criterion and the next well’s payout such that the fractional well has a Payout Time exactly equal to the Payout Criterion. Notwithstanding the Payout Criterion set forth below, no more than 1.5 Base Production wells can be added in a quarter beyond the number of wells added in the previous quarter, not to exceed 18 total wells added in any quarter.

 

The Payout Criterion are:

 

(a)                                  Prior to January 1, 2000, the maximum Payout Time will be 3.5 years.

 

(b)                                  Beginning on January 1, 2000 and thereafter, the maximum Payout Time will be 2.5 years.

 

(c)                                   Notwithstanding the above, if in any quarter, the difference between the Base Revenue and the Base Operating Expense is less than or equal to $3,000,000 adjusted for inflation to January 1, 1990 dollars using the GNP deflator as defined in Exhibit B, then no new Base Production Wells will be added in the subsequent quarter.

 

(v)                                  After the total number of new Base Production Wells from each category have been determined, the composite production characteristics for all the new Base Wells added in the quarter will be calculated as follows:

 

A-10


 

Iratei

=

The sum of the initial Oil Rates for all new Base Production Wells, q ix , added in quarter i. If a fractional well has been added, the initial rate from that well will be multiplied by that well’s fraction before adding to the total.

 

 

 

Sratei

=

The arithmetic average slope of the ln(Oil Rate) versus Time function for new Base Production Wells, D ix , added in quarter i, weighted by initial oil rate, q ix , for each well. If a fractional well has been added, the initial rate from that well will be multiplied by that well’s fraction.

 

 

 

IWORi

=

The natural log of the average initial water/oil ratio for new Base Production Wells added in quarter i, WOR ix , weighted by initial oil rate for each well, q ix . If a fractional well has been added, the initial rate from that well will be multiplied by that well’s fraction.

 

 

 

SWORi

=

The composite slope of the ln(water/oil ratio) versus Cumulative Oil function, SWOR x , for new Base Production Wells added in this quarter. This is determined by first calculating both the instantaneous water/oil ratio for the sum of the new Base Production Wells added in quarter i and their corresponding cumulative aggregate oil production at a time of ten years after the start of the quarter in which they were added. This water/oil ratio and cumulative oil production is used with IWORi to determine SWORi.

 

C.                                     Once any new Base Production Wells have been added, their composite production will be accounted for in all future quarters as described as follows. At the beginning of each quarter, the oil production and water production for each group of Base Production Wells added through the end of that quarter will be determined for that quarter as set forth below. Base Oil Production for the quarter is the sum of the oil production from wells which existed prior to July 1, 1990, as described in Section 3.2.A, and the oil production from each Base Production Well group. Base Water will be calculated in the same manner. Oil and water production from each Base Production Well group will be calculated as follows.

 

(i)                                      If the ratio of water production divided by oil production for any Base Production Well group was less than 7.0 in the previous quarter, then the oil production for that group for the current quarter, OilBase ij  will be determined from Equations 19 - 21. This method is referred to as the “exponential calculation procedure.”

 

A-11



 

Equation 19

 

T2 = ln [(Cum ij-1 ) (Srate i ) / [ (Irate i ) (365) ] + 1.0] / (Srate i )

 

where:

 

T2

=

An equivalent time, in years, from the start of this group’s initial production.

 

 

 

Cum ij-1

=

cumulative oil produced for this group of wells at the end of the previous quarter.

 

 

 

Srate i

=

the average D i  for this group of wells, as defined in Section 3.2.B above.

 

 

 

Irate i

=

the average q i  group of wells, as defined in Section 3.2.B above.

 

 

 

i

=

the quarter in which the Base Production Well

 

 

 

j

=

the current quarter

 

Equation 20

 

Cum ij  = (Irate i (365)   [e  [(Srate i ) (T2=0.25)] -1.0]

(Srate i )

 

where:

 

Cum ij-1

=

cumulative oil produced for this group of wells at the end of the current quarter.

 

 

 

Irate i

=

as defined for Equation 19.

 

 

 

Srate i

=

as defined for Equation 19

 

 

 

T2

=

as defined by Equation 19

 

Equation 21

 

OilBase ij  = (Cum ij ) - (Cum ij-1 )

 

where:

 

OilBase ij

=

Base Oil Production in the j th  quarter for the group of wells initially added in the i th  quarter, stock tank barrels.

 

 

 

Cum ij

=

as defined by Equation 20

 

 

 

Cum ij-1

=

as defined for Equation 20

 

A-12



 

(ii)                                   If the ratio of water production divided by oil production for any Base Production Well group is equal to or greater than 7.0 in the current quarter and the same ratio for that group was less than 7.0 in the previous quarter, then for all future quarters that group of wells will be treated with the “hyperbolic calculation procedure” which follows in Equations 22 - 27, and 21 for determination of oil production, OilBas ij .  The last quarter in which the exponential calculation procedure was used for this group of wells will be recorded for future reference. In addition, the instantaneous oil production rate at the end of the last quarter in which the exponential calculation procedure was used, q ih , will be calculated using Equation 22.

 

Equation 22

 

q ih  = (Irate 1 ) (365)e [ (Srate i ) (T2+0.25)]

 

where:

 

Irate i

=

as defined for Equation 19

 

 

 

Srate i

=

as defined for Equation 19

 

 

 

T2

=

as defined by Equation 19

 

 

 

h

=

the last quarter in which the exponential calculation procedure was used for this group.

 

Equation 23

 

Cumh ij = (Cum ij-1 )-(Cum ij )

 

where:

 

Cumh ij

=

the cumulative oil production for this group of wells since changing to the hyperbolic calculation procedure.

 

 

 

Cum ij-1

=

as defined for Equation 20

 

 

 

Cum ih

=

the cumulative oil production, Cum ij  where j-h, for this group of wells at the end of the last quarter in which the exponential calculation procedure was used.

 

Equation 24

 

 

 

 

 

 

 

 

1

 

Q2  =

 

(g 1h )

 

- (Cum ih )

·

(1-n) (SRate 1 )(-1.0)

(1-n)

 

 

 

(n-1) (SRate 1 )

 

 

 

q 1h n

 

 

 

A-13



 

where:

 

Q2

=

the instantaneous oil rate at the end of the previous quarter for this group of wells, stock tank barrels per year

 

 

 

n

=

hyperbolic decline coefficient. Its value = 0.2

 

 

 

SRate i

=

as defined for Equation 19

 

 

 

Cum 1h

=

as defined in Equation 23

 

 

 

q in

=

as defined in Equation 22

 

Equation 25

 

[-1/(n)]

Q3 = q ih  [1-(n) (SRate i ) (t2+0.25)]

 

where:

 

Q3

=

the instantaneous oil rate at the end of the current quarter for this group of wells, stock tank barrels per year

 

 

 

q ih

=

as defined in Equation 22

 

 

 

n

=

as defined in Equation 24

 

 

 

SRate 1

=

as defined for Equation 19

 

 

 

t2

=

[1-(q ih /Q2 n )12] / [(n)(SRate i )]

 

 

 

Q2

=

as defined in Equation 24

 

Equation 26

 

DCUM =

 

g ih n

 

[Q2 (1-n) -Q3 (1-n) ]

 

 

(1-n) (-1) (SRate i )

 

 

 

where:

 

DCUM

=

the base oil production for this group of wells during the current quarter.

 

 

 

Q2

=

as defined in Equation 24

 

 

 

Q3

=

as defined in Equation 25

 

 

 

g ih ,

=

as defined in Equation 22

 

A-14



 

n

=

as defined in Equation 24

 

 

 

SRatei

=

as defined for Equation 19

 

Equation 27

 

Cum ij  = Cum ij-1  + DCUM

 

where:

 

Cum ij

=

Cumulative oil production by this group of wells at the end of the current quarter.

 

 

 

Cum ij-1

=

as defined for Equation 19

 

 

 

DCUM

=

as defined by Equation 26

 

Equation 21

 

OilBase ij  = (Cum ij )-(Cum ij-1 )

 

where:

 

OilBase ij

=

oil production in the j th  quarter for the group of wells initially added in the i th  quarter, stock tank barrels.

 

 

 

Cum ij

=

as defined by Equation 27

 

 

 

Cum ij-1

=

as defined for Equation 19

 

(iii)                                After the oil production has been calculated for each group of Base Production Wells in a quarter, the water production will be calculated for each group of Base Production Wells.  The water production, WtrBase ij , is calculated as follows:

 

Equation 28

 

[(SWOR i ) (Cum ij )+(IWOR i )]

WtrBase ij  = (OilBase ij )e

 

Where:

 

WtrBase ij

=

water production in the j th  quarter for the group of wells initially added in the i th quarter, barrels.

 

 

 

OilBas ij

=

as defined in Equation 21

 

 

 

SWOR i

=

the slope of the ln(water/oil ratio) vs. cumulative oil relationship for this group of wells as defined in Section 3.2.B.

 

A-15



 

IWOR i

=

the intercept of the ln (water/oil ratio) vs. cumulative oil relationship for this group of wells as defined in Section 3.2.B.

 

 

 

CUM ij

=

as defined in either Equation 20 or 27, whichever was used for this group of wells in this quarter.

 

(iv)                               For each group of wells in each quarter, the Variable Profitability, Prof ij , will be calculated as follows:

 

Equation 29

 

Prof ij                    = (OilBase ij ) (P) - [(WtrBase ij ) + (Oi1Base ij )] (Cost gf )

 

- (Oi1Base ij ) (Cost o )

 

where:

 

OilBase ij

=

as defined in Equation 21

 

 

 

P

=

as defined in Equation 17

 

 

 

WtrBas ij

=

as defined in Equation 27

 

 

 

Cost gf

=

as defined in Equation 17

 

 

 

Cost o

a as defined in Equation 17

 

(v)                                  If, for any group of wells in a quarter, the Variable Profitability, Pro ij , is less than or equal to zero, then the oil production, OilBase ij , and the water production, WtrBas ij , for that group of wells will be set equal to zero, and the cumulative oil production at the end of the quarter, Cum ij , for that group of wells will be set equal to the cumulative oil production at the end of the previous quarter, Cum ij-1 .

 

(vi)                               The total LBU Base Oil will be calculated by adding together the oil production in the current quarter from the wells existing prior to July 1, 1990 and all the oil production from Base Production Well groups added through the end of the quarter. The total LBU Base Water Production will be summed in the same manner.

 

The computer program listed in Attachment 2 includes the foregoing methodology, equations, and formulas.

 

Section 4

Adjustments at Program Commencement Date

 

4.1                                Section 4 controls Over Section 3 .  Notwithstanding the other provisions of this Exhibit A, Base Oil and Base Water Production shall be determined and calculated in accordance with the adjustment factors set forth in this Section 4, as and if applicable.

 

A-16



 

4.2                                Adjustment if Actual Production Exceeds Base Production (See Attachment 3) .  If the average daily actual oil production rate from the LBU for the three full calendar months prior to the Program Commencement Date (“Actual Production at Commencement”) exceeds the average daily Base Oil Production rate for the same period calculated pursuant to Section 3 of this Exhibit A (“Assumed Production at Commencement”), then for each of the first 24 months following the Program Commencement Date Base oil Production and Base Water Production for each such month shall be the respective amounts determined and calculated as provided in Section 3 of this Exhibit A multiplied by an adjustment factor. The adjustment factor for the first such month shall be the ratio of Actual Production at Commencement over Assumed Production at Commencement. The adjustment factor for each of the remaining 23 months shall be linearly decreased sufficient to result in an adjustment factor of 1.00 for the 24th month. Commencing with the 25th month following the Program Commencement Date, there shall be no adjustment made pursuant to this Section 4.2.

 

4.3                                Adjustment if Base Production exceeds Actual Production (See Attachment 4) .  If Assumed Production at Commencement exceeds Actual Production at Commencement, then Base Oil Production and Base Water Production shall remain constant at Actual Production at Commencement until Base Oil from the Computer Program for any full calendar month is equal to or less than Actual Production at Commencement multiplied by the number of days in the month, at which time there shall be no further adjustments made pursuant to this Section 4.3.

 

A-17



 

Attachment 1

Listing of Base Oil and Base Water

By Quarter Attributed to Wells Completed Prior to July 1, 1990

 

Quarter
Beginning

 

Quarter
Ending

 

Oil
(STB)

 

Water
(BBL)

1990.50

 

1990.75

 

4181112

 

38874070

1990.75

 

1991.00

 

4108339

 

39108240

1991.00

 

1991.25

 

4036404

 

39335430

1991.25

 

1991.50

 

4006223

 

39972120

1991.50

 

1991.75

 

3893702

 

39774140

1991.75

 

1992.00

 

3863638

 

40401980

1992.00

 

1992.25

 

3754517

 

40192610

1992.25

 

1992.50

 

3686437

 

40395640

1992.50

 

1992.75

 

3618651

 

40599220

1992.75

 

1993.00

 

3551683

 

40797490

1993.00

 

1993.25

 

3455855

 

40629810

1993.25

 

1993.50

 

3345725

 

40233900

1993.50

 

1993.75

 

3239788

 

39827990

1993.75

 

1994.00

 

3137854

 

39412610

1994.00

 

1994.25

 

3039372

 

38984850

1994.25

 

1994.50

 

2944214

 

38545090

1994.50

 

1994.75

 

2852223

 

38093840

1994.75

 

1995.00

 

2763306

 

37631490

1995.00

 

1995.25

 

2677353

 

37158590

1995.25

 

1995.50

 

2594224

 

36675800

1995.50

 

1995.75

 

2513865

 

36183600

1995.75

 

1996.00

 

2436130

 

35682800

1996.00

 

1996.25

 

2360973

 

35173860

1996.25

 

1996.50

 

2288246

 

34657660

1996.50

 

1996.75

 

2217902

 

34134810

1996.75

 

1997.00

 

2149853

 

33606000

1997.00

 

1997.25

 

2083989

 

33072010

1997.25

 

1997.50

 

2020250

 

32533490

1997.50

 

1997.75

 

1958596

 

31991120

1997.75

 

1998.00

 

1898904

 

31445700

1998.00

 

1998.25

 

1841108

 

30897880

1998.25

 

1998.50

 

1785197

 

30348260

1998.50

 

1998.75

 

1731034

 

29797580

1998.75

 

1999.00

 

1678627

 

29246460

1999.00

 

1999.25

 

1627862

 

28695530

1999.25

 

1999.50

 

1578713

 

28145380

1999.50

 

1999.75

 

1531104

 

27596580

1999.75

 

2000.00

 

1484999

 

27049670

2000.00

 

2000.25

 

1440367

 

26505160

2000.25

 

2000.50

 

1397120

 

25963640

2000.50

 

2000.75

 

1355241

 

25425490

 

1



 

2000.75

 

2001.00

 

1314654

 

24891230

2001.00

 

2001.25

 

1275349

 

24361180

2001.25

 

2001.50

 

1237263

 

23835860

2001.50

 

2001.75

 

1200353

 

23315560

2001.75

 

2002.00

 

1164586

 

22800640

2002.00

 

2002.25

 

1129948

 

22291410

2002.25

 

2002.50

 

1096369

 

21788150

2002.50

 

2002.75

 

1063838

 

21291100

2002.75

 

2003.00

 

1032282

 

20800670

2003.00

 

2003.25

 

1001713

 

20316850

2003.25

 

2003.50

 

972094

 

19839930

2003.50

 

2003.75

 

943388

 

19370140

2003.75

 

2004.00

 

915540

 

18907580

2004.00

 

2004.25

 

888551

 

18452400

2004.25

 

2004.50

 

862389

 

18004750

2004.50

 

2004.75

 

837011

 

17564680

2004.75

 

2005.00

 

812433

 

17132220

2005.00

 

2005.25

 

788569

 

16707570

2005.25

 

2005.50

 

765453

 

16290660

2005.50

 

2005.75

 

743039

 

15881600

2005.75

 

2006.00

 

721292

 

15480380

2006.00

 

2006.25

 

700204

 

15086980

2006.25

 

2006.50

 

679760

 

14701420

2006.50

 

2006.75

 

659922

 

14323750

2006.75

 

2007.00

 

640687

 

13953810

2007.00

 

2007.25

 

622040

 

13591660

2007.25

 

2007.50

 

603932

 

13237260

2007.50

 

2007.75

 

586399

 

12890470

2007.75

 

2008.00

 

569349

 

12551310

2008.00

 

2008.25

 

552841

 

12219720

2008.25

 

2008.50

 

536820

 

11895550

2008.50

 

2008.75

 

521275

 

11578780

2008.75

 

2009.00

 

506191

 

11269300

2009.00

 

2009.25

 

491552

 

10967020

2009.25

 

2009.50

 

477357

 

10671840

2009.50

 

2009.75

 

463597

 

10383670

2009.75

 

2010.00

 

450231

 

10102390

2010.00

 

2010.25

 

437256

 

9827943

2010.25

 

2010.50

 

424674

 

9560148

2010.50

 

2010.75

 

412459

 

9298935

2010.75

 

2011.00

 

400592

 

9044251

2011.00

 

2011.25

 

389089

 

8795897

2011.25

 

2011.50

 

377926

 

8553767

2011.50

 

2011.75

 

367099

 

8317746

2011.75

 

2012.00

 

356578

 

8087749

2012.00

 

2012.25

 

346379

 

7863660

 

2



 

2012.25

 

2012.50

 

336469

 

7645299

2012.50

 

2012.75

 

326850

 

7432619

2012.75

 

2013.00

 

317527

 

7225458

2013.00

 

2013.25

 

308472

 

7023741

2013.25

 

2013.50

 

299673

 

6827325

2013.50

 

2013.75

 

291122

 

6636120

2013.75

 

2014.00

 

282832

 

6449969

2014.00

 

2014.25

 

274785

 

6268762

2014.25

 

2014.50

 

266974

 

6092415

2014.50

 

2014.75

 

259409

 

5920810

2014.75

 

2015.00

 

252030

 

5753830

2015.00

 

2015.25

 

244894

 

5591409

2015.25

 

2015.50

 

237935

 

5433318

2015.50

 

2015.75

 

231214

 

5279554

2015.75

 

2016.00

 

224666

 

5129957

2016.00

 

2016.25

 

218300

 

4984537

2016.25

 

2016.50

 

212124

 

4843110

2016.50

 

2016.75

 

206143

 

4705522

2016.75

 

2017.00

 

200324

 

4571799

2017.00

 

2017.25

 

194665

 

4441733

2017.25

 

2017.50

 

189176

 

4315286

2017.50

 

2017.75

 

183864

 

4192371

2017.75

 

2018.00

 

178687

 

4072877

2018.00

 

2018.25

 

173654

 

3956704

2018.25

 

2018.50

 

168765

 

3843770

2018.50

 

2018.75

 

164026

 

3734079

2018.75

 

2019.00

 

159420

 

3627342

2019.00

 

2019.25

 

154951

 

3523691

2019.25

 

2019.50

 

150599

 

3422991

2019.50

 

2019.75

 

146372

 

3325086

2019.75

 

2020.00

 

142270

 

3229933

 

3


 

C****************************************************************************

C                                        CONFIDENTIAL: PRIVILEGED SETTLEMENT COMMUNICATION

C****************************************************************************

C                                        PROGRAM WRITTEN 6/1/90 — final changes 10/29/91 mle, awm, jal

C                                        J.B. JOHNSON ARCO OIL 8 GAS COMPANY

c

c

c

c

C****************************************************************************

C                                        THIS PROGRAM CALCULATES LBU BASE PRODUCTION

C

C                                        DIMENSION HERE

CHARACTER DNAME*45,OUTNAM*45,ALINE*80,AP*1

C

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN,HYPERWOR.QIHYPER(140),COSTGF(140),

&QISLPSLP,QIINTSLP,QISLPINT,QIINTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT,

&DCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140),

&WORSW(50),WORIW(50),RATESW(50),RATEIW(50),POWELL(50),POAVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&OILLBU(140),WIRLBU(140),CUMLBU(140),WORLBU(140),

&CUM(140,140),OIL(140, 140),WATER(140, 140),

&PAYTIME,WMAX,WMIN,WINCMX,WERACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

COMMON /READ/PAYSLOPE,PAYINT,COSTO15,COSTGF15,COSTF15,CSTGFF15

COMMON /READ2/ GFCAP(10),GFTIME(10),MGFCAP

COMMON /READ3/ PAYS(20),PAYI(20),PAYTIM(20),NPAYTIM

COMMON /READ4/ WCUM

DIMENSION TOTCOST(140),REV(140),PROFIT(140),WLBUCUM(140)

c

c***                      Initialize ihyper array

c

Do 1020 i=1,140

ihyper(i) = 0

1020                     continue

C

C==========================================================================

C                                        OPEN FILES HERE

OPEN(8,FILE=‘FORT1.DAT’,STATUS=10LD’)

OPEN(9,FILE=IFORECAST.DAT’,STATUWOLD’)

WRITE(*,10000)

10000              FORMAT(25(/).75,’INPUT FILE NAME ==>‘)

READ(8,10010) DNAME

10010              FORMAT(A)

OPEN(4,FILE=DNAME,STATUS=‘OLD’)

 

1



 

WRITE(*,10020)

10020              FORMAT(T5,’INPUT OUTPUT FILE NAME ==>‘)

READ(8,10010) OUTNAM

OPEN(7,FILE=OUTNAM,STATUS=‘UNKNOWN’)

WRITE(*,*) ‘ DO YOU WANT A FULL PRINTOUT? (Y OR N) ==>

READ(8,10010) AP

IF(AP.E0.1)0) AP=‘Y’

C==========================================================================

C

C                                        READ IN DATA

CALL READER

C

INCP=INT(1/TIMINC+.01)

C                                        LOOP BY TIME PERIOD:

DO 5000 17=1,NINC

IF(IT.E0.1) THEN

TIME(17)=SDATE+TIMINC

ELSE

TIME(IT)=TIME(IT-1)+TIMINC

ENDIF

C

APRICE(IT)=FAPRICE(IT,INCP)

C

COSTO(IT)=FCOST(APRICE(IT))*COST015*COSTRED(IT)

COSTGF(IT)=FCOST(APRICE(IT))*COSTGF15*COSTRED(IT)

COSTGFF(IT)=FCOST(APRICE(IT))*CSTGFF15*COSTRED(IT)

COSTF(IT)=FCOST(APRICE(IT))*COSTF15*COSTRED(IT)

C

CALL PAYT(TIME(IT),PAYSLOPE,PAYINT)

PAYTIME=PAYSLOPE*APRICE(IT)+PAYINT

IF(PAYTIME.GT.3.5) PAYTIME=3.5

IF(IT.GT.1.AND.(REV(IT-1)-TOTCOST(IT-1)+TOTCAP)(3E6) PAYTIME=0.0

C

CALL GFLIMIT(TIME(IT),GFCONST)

C

C

cumwx=srcum

IF(IT.GT.1) CUMWX=CUMLBU(IT-1)

C                                        CALCULATE BCUM(IT)

IF(IT.EO.1) BCUm(IT)=STCUM + BOIL(IT)

IF(IT.GT.1) BCUM(IT)=BCUM(17-1)+BOIL(IT)

C                                        LOOP BY GROUPING OF WELLS:

DO 4000 IS=1,17

C

C                                        ADD IN ALL THE NEW WELLS FOR THIS TIME PERIOD:

IF(IS.EO.IT) THEN

CALL NEWWELLS(IS,IT,CUMWK)

ENDIF

C

C                                        NOW WE WILL MOVE ON TO ACTUALLY CALCULATE THE OIL AND WATER

C                                        FOR THIS TIME PERIOD FROM THIS GROUP OF WELLS

 

2



 

CALL OWC(IS,IT)

C

4000                                       CONTINUE

C

ISWITCH=0

2500                                       CONTINUE

C                                        WE HAVE NOW CALCULATED ALL THE DATA FOR THIS TIME STEP.

C                                        WE SUM UP TO GET THE TOTAL LBU OIL AND WATER it, CUM b WOR

OILLBLI(IT)=BOIL(IT)

WTRLBU(IT)=BWTR(IT)

CUMLBU(IT)=BCUM(IT)

DO 4500 IS=1, IT

OILLBU(IT)=OILLBWIT)+OIL(IS, IT)

WTRLBU(IT)=WTRLBU(IT)+WATER(IS, IT)

4500                                       CUMLBWIT)=CUMLBU(IT)+CUM(IS, IT)

WORLBU(IT)=0.0

IF(OILLBU(17).GT.0.0) WORLBU(IT)=WTRLBU(IT)/OILLBU(IT)

C                                        WE NEED TO MAKE SURE WE HAVE NOT EXCEEDED THE GROSS FLUID

CALL CUTBACK(IT,ISWITCH)

IF(ISWITCH.GT.0) GO TO 2500

C                                        NOW WE ARE DONE WITH THIS TIME STEP

C                                        FIGURE THE CUM WATER:

WCUM=WCUM+WTRLBU(IT)

WLBUCUM(IT)=WCUM

XLBCUM=CUMLBU(IT)

XWOR=0.0

WELP=(OILLBU(IT)+WTRLBU(IT))/(TIMINC*365.)/775.

WELI=WELP*.432368

XINJ=(OILLBU(IT)+WTRLBU(IT))/(TIMINC*365.)*1.05

C                                        COSTS ARE TOTAL FOR THE TIME STEP

COST1=OILLBWIT)*COSTO(IT)

COST2=COKLBU(IT)+WTRLBU(IT))*COSTGF(IT)

FXCOST=COSTF(IT)*TIMINC

IF((OILLLBU(IT)+WTRLBLI(IT))/(365.*TIMINC).GT.165085.) THEN

C0ST3=COSTGFF(IT)*(OILLBU(IT)+WTRLBUCIT))

ELSE

COST3=COSTGFF(IT)*165085.*365.*TIMINC

ENDIF

TOTCOST(IT)=COST1+COST241XCOST+COST3

TOTCAP*(CAPSLP*WELLS(IT)+CAPINT)’FCOST(APRICE(IT))

TOTCOST(IT)=TOTCOST(IT)+TOTCAP

REV(IT)=OILLBU(IT)*PRICE(IT)

PROFIT(IT)’REV(IT)-TOTCOST(IT)

IF(OIL(IT,IT).GT.0.0) XWOR=WATER(IT,IT)/OIL(IT,IT)

5000                     CONTINUE

C

C                                        LET’S WRITE OUT TO THE FILE

WRITE(7,11000)

11000              FORMAT(T15,’LBU TOTAL’,/,

&15.1TIME’.T17, ‘OIL’, T30,WATER’,T44,’CUM’,T52,’ REV ‘,T62, COST’,

&T75,’CUMW)

 

3



 

DO 5501 1X=1,40

READ(9,*) TIME2,OILLBU2,WTRLBU2,CUMLBU2,REV2,TOTCOST2,WLBUCUM2

5501                     WRITE(7,11100) TIME2,OILLBU2,WTRLBU2,CUMLBU2,REV2,TOTCOST2,

&WLBUCUM2

DO 5500 IT=1,NINC

RATE=OILLBU(IT)/(TIMINC*365.)

XWOR=0.0

IF(OILLBU(IT).GT.0.0) XWOR=WTRLBU(IT)/OILLBU(IT)

GF=RATE*(XWOR+1)

5500                     WRITE(7,11100) TIME(IT),OILLBU(IT),WTRLBU(IT),CUMLBU(IT),

&REV(IT),TOTCOST(IT),WLBUCUM(IT)

11100              FORMAT(T2,F8.3.T12,E10.5,T24.E10.5.T36,E10.5,T48,E10.5,T60,

&E10.5.T72,E10.5)

WRITE(7,11150)

11150              FORMAT(T15,’FOR BASE GROUP ‘,/,

&T5,’TIME’,T17.’OIL’,T30,’WATER’,T44,’CUM’,T52,’ORATE’ T62,’WOR’,

&T75.’GF’)

DO 5502 IT=1,40

READ(9,*) TIME2,BOIL2,BWIR2,BCUM2,RATE2,XWOR2,GF2

5502                     WRITE(7,11100) TIME2,BOIL2,BWTR2,BCUM2,RATE2,XWOR2,GF2

DO 5505 IT=l,NINC

RATE=BOIL(IT)/(TIMINC*365.)

XWOR=0.0

IF(BOIL(IT).GT.0.0) XWOR=BWTR(IT)/BOIL(IT)

GF=RATE*(XWOR+1)

5505                     WRITE(7,11100) TIME(IT),BOIL(IT),BWTR(IT),BCUM(IT),RATE,XWOR,GF

DO 5503 IT=1,40

READ(9,’)IS=,TIME2,PAYOUT2,WELL2

5503                     WRITE(7,11200) IS2,TIME2,PAYOUT2,WELL2

DO 5520 ISzl.NINC

5520                     WRITE(7,11200) IS,TIME(S5),PATOUT(IS),WELLS(IS)

11200              FORMAT(‘ GROUP# ‘,14,’ TIME= ‘,F10.4,’ PAYOUT= ‘,F10.3,

&’WELLS= ‘,F10.3)

IF(AP.EQ.’Y’) THEN

DO 5530 IS=l,NINC

WRITE(7,11300) IS,TIME(IS),PAYOUT(IS),WELLS(IS)

11300              FORMAT(/,’ GROUP# ‘,I4,’ TIME= ‘,F10.4,’ PAYOUT= ‘,F10.3,

&’ WELLS’ ‘,F10.3,/,

&T5,’TIME’,T17, ‘OIL’,T30,WATER’,T44,’CUM,T52,’ORATE’,T62,’WOR’,

&T75,’GF’)

DO 5525 IT=1,NINC

RATEOIL(IS,IT)/(TIMINC*365.)

XWOR=0.0

IF(OIL(IS,IT).GT.0.0) XWOR=WATER(1S,1T)/OIL(IS,IT)

GF=RATE*(XWOR+1)

5525                     WRITE(7,11100) TIME(IT),OIL(IS,IT),WATER(IS,IT),CUM(IS.IT),

&RATE,XWOR,GF

5530                     CONTINUE

ENDIF

STOP

END

 

4



 

C***********************************************************************************

SUBROUTINE GFLIMIT(TIME,GFCONST)

COMMON /READ2/ GFCAP(10),GFTIME(10),NGFCAP

C                                        THIS SUBROUTINE FIGURES OUT WHAT THE GROSS FLUID LIMITATION

C                                        WILL BE FOR THIS TIME STEP.

GFCONST=9999999.

DO 10 I=1,(NGFCAP-1)

IF(TIME.GE.GFTIME(1).AND.TIME.LT.GFTIME(I+1)) THEN

C                                        THEN WE HAVE THE RIGHT TIME.

GFCONST=GFCAP(I)

RETURN

ENDIF

10                                                     CONTINUE

C                                        IF WE EVER GET HERE, WE HAVE A TIME > THE LAST GFTIME INPUT

IF(TIME.GE.GFTIME(NGFCAP))

&GFCONST=GFCAP(NGFCAP)

RETURN

END

C***********************************************************************************

SUBROUTINE PAYT(TIME,PAYSLOPE,PAYINT)

COMMON /READ3/ PAYS(20),PAYI(20),PAYTIM(20),NPAYTIM

C                                        THIS SUBROUTINE FIGURES OUT WHAT THE PAYOUT CRITERION VS OIL PRICE

C                                        WILL BE FOR THIS TIME STEP.

IF(TIME.LT.PAYTIM(1)) THEN

PAYSLOPE=PAYS(1)

PAYINT=PAYI(1)

RETURN

ENDIF

DO 10 I=1,(NPAYTIM-1)

IF(TIME.GE.PAYTIM(1).AND.TIME.LT.PAYTIM(I+1)) THEN

C                                        THEN WE HAVE THE RIGHT TIME.

PAYSLOPE=PAYS(I)

PAYINT=PAYI(I)

RETURN

ENDIF

10                                                     CONTINUE

C                                        IF WE EVER GET HERE, WE HAVE A TIME > THE LAST PAYTIM INPUT

IF(TIME.GE.PAYTIM(NPAYTIM)) THEN

PAYSLOPE=PAYS(NPAYTIM)

PAYINT=PAYI(NPAYTIM)

RETURN

ENDIF

END

C***********************************************************************************

C                                        THIS SUBROUTINE CALCULATES THE PROPER AVERAGE PRODUCTION

C                                        PARAMETERS FOR A GROUP OF WELLS. WE COME INTO THE SUBROUTINE

C                                        WITH PARAMETERS BY WELL, AND THIS ROUTINE CONSOLIDATES THEM

C                                        ALL TOGETHER.

SUBROUTINE AVGPROP(IS)

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140).

&HYPERN,HYPERWOR,QIHYPER(140),COSTGF(140).

 

5



 

&QISLPSLP,QIINTSLP,QISLPINT,QIINTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT,

WCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140).

&WORSW(50),WORIW(50),RATESW(50),RATEIW(50),POWELL(50),P0AVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&OILLBU(140),WTRLBU(140),CUMLBU(140),WORLBU(140).

&CUM(140,140),OIL(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),C0STGFF(140),COSTRED(140)

IF(WELLS(IS)-LE.0.0) THEN

RATINIT(IS)=0.0

RATSLOPE(IS)=-1.0

WORINIT(IS)=-1.0

WORSLOPE(IS)=0.0

RETURN

ENDIF

IWELLS=INT(WELLS(IS))

WFRACT=WELLS(IS)-1WELLS

IF(WFRACT.GT.0.001) IWELLS=IWELLS+1

IND=0

IF(WFRACT.GT.0.001) IND=1

C

C                                        FIRST, WE WILL FIND THE INITIAL OIL RATE

RATINIT(IS)=0.0

DO 100 IW=1,IWELLS

IF(IW.EQ.IWELLS.AND.IND.EQ.1) THEN

RATINIT(IS)=RATINIT(IS)+RATEIW(IW)*       WFRACT

ELSE

RATINIT(IS)=RATINIT(IS)+RATEIW(IW)

ENDIF

100                            CONTINUE

C

C                                        NEXT WE FIND THE INITIAL WOR

WTR=0.0

DO 200 IW=1,IWELLS

IF(WORIW(IW).LT.88.) THEN

WORC=EXP(WORIW(IW))

ELSE

WORC=EXP(85.)

write (7,110)

110          format (2, ‘WOR set to large value’)

ENDIF

IF(IW.EQ.IWELLS.AND.IND.EQ.1) THEN

WTR=WTR+WORC*RATEIW(IW)*WFRACT

ELSE

WTR=WTR+WORC*RATEIW(IW)

ENDIF

 

6



 

200                                              CONTINUE

WORTEMP=0.0

IF(RATINIT(IS).GT.0.0) WORTEMP=WTR/RATINIT(1S)

WORINIT(IS)=0.0

IF(WORTEMP.GT.0.0) WORINIT(IS)=ALOG(WORTEMP)

C

C                                        NOW DETERMINE THE AVERAGE SLOPE OF THE OIL RATE CURVE.

C                                        THIS IS WEIGHTED BY INITIAL OIL RATE.

DIRAT=0.0

DO 300 1W=1,IWELLS

IF(IW.EQ.IWELLS.AND.IND.EQ.1) THEN

DIRAT=DIRAT+RATESW(IW) · RATEIW(IW)’WFRACT

ELSE

DIRAT=DIRAT+RATESW(IW) · RATEIW(IW)

ENDIF

300                                              CONTINUE

RATSLOPE(IS)=0.0

IF(RATINIT(IS).GT.0.0) RATSLOPE(IS)=DIRAT/RATINIT(IS)

C

C                                        NOW FOR THE AVERAGE SLOPE OF THE ln(WOR) VS CUM PLOT

C                                        WE FIRST FIND THE CUMULATIVE OIL (OCUM), INSTANTANEOUS

C                                                          OIL & WATER RATES (OILINST, WTRINST) FOR ALL THE WELLS

C                                                          AT TEN YEARS (ARBITRARY TIME).

C                                        THIS GIVES US A POINT ON THE ln(WOR) VS CUM CURVE.

C                                        WE THEN HAVE THE OTHER POINT (AT WORINIT) FROM WHICH WE CAN

C                                        DRAW A STRAIGHT SEMI-LOG LINE.

OCUM=0.0

OILINST=0.0

WTRINST=0.0

DO 400 1W=1,IWELLS

IF(IW.EQ.1WELLS.AND.IND.EQ.1) THEN

OCUM1=RATEIW(IW)*365.*WFRACT*(EXP(RATESW(IW)*10.0)-1.)

&                                       /RATESW(IW)

OCUM=OCUM+OCUM1

OILINST=OILINST+RATEW(IW)*EXP(RATESW(IW*10.0)*WFRACT

WORW=EXP(WORSW(IW)*OCUM1/WFRACT+WORIW(IW))

WTRINST=WTRINST+RATEIW(IW)*EXP(RATESW(IW)*10.0)*WFRACT*WORW

ELSE

OCUM1=RATEIW(IW)*365.*(EXP(RATESW(IW)*10.0)-1.)

&                                       /RATESW(IW)

OCUM=OCUM4+OCUM1

OILINST=OILINST+RATEIW(IW)*EXP(RATESW(IW)*10.0)

WORW=EXP(WORSW(IW)*OCUM1+WORIW(IW))

WTRINST=WTRINST+RATEIWOWEXP(RATESW(IW)*10.0)*WORW

ENDIF

400                                              CONTINUE

WORINST=0.01

IF(OILINST.GT.0.0) WORINST=WTRINST/OILINST

C                                        NOW WE HAVE X1,Y1,X2, Y2:

X1=0.0

Y1=WORINIT(IS)

 

7



 

X2=OCUM

Y2=ALOG(WORINST)

IF(OCUM.GT.0.0) THEN

WORSLOPE(IS)=(Y2-Y1)/(X2-X1)

ELSE

WORSLOPE(IS)=0.0

ENDIF

C

RETURN

END

c***********************************************************************************

c

C                                        THIS SUBROUTINE CUTS BACK PRODUCTION FROM ALL WELLS IN ORDER

C                                        TO MEET THE GROSS FLUID CONSTRAINT

SUBROUTINE CUTBACK(IT,ISWITCH)

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN,HYPERWOR,QIHYPER(140),COSTGF(140),

&QISLPSLP,QIINTSLP, QISLPINT,QIINTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT,

&DCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140),

&WORSW(50),WORIW(50),RATESW(50),RATEIW(50),POWELL(50),POAVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&OILLBU(140),ORLBU(140),CUMLBU(140),WORLBU(140).

&CUM(140,140),OIL(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

GFCUT(OILLBU(IT)+WTRLBU(IT))-GFCONST*(365.*TIMINC)

IF(GFCUT.LE.0.0.OR.ISWITCH.GT.0) THEN

ISWITCH=0

RETURN

ENDIF

IF(GFCUT.GT.0.0) THEN

ISWITCH=1

C                                        THEN WE NEED TO LOOP BY WELL AND CUT BACK THE HIGHEST WOR

C                                        GROUPS UNTIL WE HAVE REDUCED THE LBU GF BY GFCUT AMOUNT.

100                                              CONTINUE

WORMAX=0.0

ISMAX=0

DO 200 IS=1,17

WOR=0.0

IF(OIL(IS,IT).GT.0.0) WOR=WATER(IS,IT)/OIL(IS,IT)

IF(WOR.GT.WORMAX) THEN

ISMAX=IS

WORMAX=WOR

ENDIF

200                                              CONTINUE

C                                        IF WE GET HERE, AND ISMAX=0, THEN WE BLEW IT

 

8



 

if (ismax .eq. 0) write (7, 201)

201                                              format (2x, 8 ismax is zero, see subroutine cutback ‘)

IF(ISMAX.EQ.0) RETURN

C                                        NOW BY HERE, WE HAVE FOUND THE WORST CULPRIT. WE WILL TAKE

C                                        CARE OF IT NOW.

GFMAX=OIL(ISMAX,IT)+WATER(ISMAX,IT)

IF(GFMAX.LT.GFCUT) THEN

C                                        THEN WE WILL COMPLETELY TAKE THIS GROUP OUT FOR NOW

OIL(ISMAX,IT)=0.0

WATER(ISMAX,IT)=0.0

IF(IT.GT.1) THEN

CUM(ISMAX,IT)=CUM(ISMAX,(17-1))

ELSE

CUM(ISMAX,IT)=0.0

ENDIF

GFCUT=GFCUT-GFMAX

ELSE

C                                        ELSE, WE WILL SIMPLY REDUCE THE GF FROM THIS GROUP

C                                        THE CUT IS BY GFCUT/GFMAX

OIL(ISKAX,IT)=(1.-GFCUT/GFMAX)*OIL(ISMAX,IT)

WATER(ISMAX,IT)=(1.-GFCUT/GFMAX)*WATER(ISMAX,IT)

IF(IT.GT.1) THEN

CUM(ISMAX,IT)=CUM(ISMAX,(17-1))+OIL(ISMAX,IT)

ELSE

CUM(ISMAX,IT)=OIL(ISMAX,IT)

ENDIF

GFCUT=0.0

RETURN

ENDIF

GO TO 100

ENDIF

END

c************************************************************************************

C                                        THIS FUNCTION CALCULATES THE RUNNING AVERAGE OIL PRICE

FUNCTION FAPRICE(IT,INCP)

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN,HYPERWOR,QIHYPER(140),COSTGF(140),

&QISLPSLP,QIINTSLP,QISLPINT,QIINTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT,

&DCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140),

&WORSW(50),WORIW(50),RATESW(50),RATEIW(50),POWELL(50),POAVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPEC140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&OILLBU(140),WTRLBU(140),CUMLBU(140),WORLBU(140),

&CUM(140,140),OIL(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

IF(IT.LT.INCP) THEN

 

9



 

FAPRICE=0.0

DO 300 II=1,IT

300                                                                                  FAPRICE=FAPRICE+PRICE(II)/FLOAT(IT)

ELSE

FAPRICE=0.0

IISTRIT-INCP+1

DO 350 11=IIST,IT

350                                                          FAPRICE=FAPRICE+PRICE(IT)/FLOAT(INCP)

ENDIF

RETURN

END

c************************************************************************************

FUNCTION FCOST(P)

C                                        THIS FUNCTION CALCULATES THE COST/GF BBL AS A FUNCTION OF PRICE

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN,HYPERWOR,QIHYPER(140),COSTGF(140),

&QISLPSLP,QIINTSLP,QISLPINT,QIINTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT.

&DCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140).

&WORSW(50),WORIW(50),RATESW(50),RATEIW(50),POWELL(50),P0AVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYDUT(140),

&OILLBU(140),WTRLBU(140),CUMLBU(140),WORLBU(140),

CUM(140,140),OIL(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

FCOST=COSTSLP*P+COST INT

RETURN

END

C***********************************************************************************

C                                        SUB. TO CALCULATE THE SLOPE & INT OF THE 1n(RATE) VS TIME LINE

SUBROUTINE FRATE(IW,CUMWK)

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN,HYPERWOR,0IHYPER(140),COSTGF(140),

&OISLPSLP,01INTSLP,OISLPINT,OIINTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT,

&DCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140),

&WORSW(50),WORIW(50),RATESW(50),RATEIW(50),POWELL(50),POAVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&OILLBU(140),WTRLBU(140),CUMLBU(140),WORLBU(140),

&CUM(140,140),O1L(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

C                                        FIRST, WE USE THE INPUT DATA TO CALCULATE THE 1n(INITIAL RATE)

 

10


 

SLOPE=QISLPSLP*CUMWK+O1INTSLP

XINT =QISLPINT*CUMWK+QIINTINT

Q1 =(SLOPE*FLOAT(IW)+XINT)

C                                        BUT HERE, Q1 IS THE NATURAL LOG OF INIT RATE, SO WE GET THE ACTUAL

IF(Q1.LT.85.) THEN

Q1=EXP(Q1)

ELSE

Q1=EXP(85.)

write (7,101)

101                                              format (2x, ‘ qi set to large value, subroutine FRATE’)

ENDIF

C                                        NOW WE GET THE DECLINE COEFFICIENT (SLOPE OF 1n(RATE) VS TIME)

SLOPE=DCSLPSLP*CUMWK+DCINTSLP

XINT =DCSLPINT*CUMWK+DCINTINT

DC =SLOPE*FLOAT(IW)+XINT

C                                        ALWAYS WORK WITH A DI THAT IS NEGATIVE.

c

IF(DC.GT.0.0) DC=DC*(-1.0)

C                                        SO WE CAN NOW CALCULATE THE SLOPE OF THE 1n(RATE) VS TIME LINE

RATESW(IW)=DC

RATEIW(IW)=Q1

RETURN

END

C***********************************************************************************

C                                        SUB. TO CALCULATE THE SLOPE & INT OF THE 1n(WOR) VS CUM CURVE

SUBROUTINE FWOR(IW,CUMWK)

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN,HYPERWOR,Q1HYPER(140),COSTGF(140),

&QISLPSLP,Q1INTSLP,QISLPINI,Q11NTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT,

&DCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140),

&WORSW(50),WOR1W(50),RATESW(50),RATEIW(50),POWELL(50),P0AVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&OILLBU(140),WTRLBU(140),CUMLBU(140),WORLBU(140),

&CUM(140,140),OIL(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

C                                        FIRST, WE USE THE INPUT DATA TO CALCULATE THE RESERVES AT A

C                                        WOR OF 25 FOR THIS WELL:

SLOPE=RSSLPSLP*CUMWK+RSINTSLP

XINT =RSSLPINT*CUMWK+RSINTINT

R25 =SLOPE*FLOAT(IW)+XINT

C                                        BUT HERE, R25 IS THE NATURAL LOG OF RESERVES, SO WE GET THE ACTUAL

IF(R25.LT.85.) THEN

R25=EXP(R25)

ELSE

 

11



 

R25=EXP(85.)

write (7,101)

101                                              format (2x, ‘R25 set to large value, SUB FWOR’)

ENDIF

C                                        NOW WE GET THE INITIAL ln(WOR)

SLOPE=(WOSLPSLP*CUMWK+WOINTSLP)

XINT =WOSLPINT*CUMWK+WOINTINT

WORI =(SLOPE*FLOAT(IW)+XINT)

C                                        WE NEVER ALLOW INITIAL WOR TO BE GREATER THAN 25, OR ELSE

C                                        THE SYSTEM COULD BOMB.

IF(WORI.GT.3.21887) WORI=3.21887

if (wori .gt. 3.21887) write (7,102)

102                                              format (2x, ‘WORI is greater than 25, SUB FWOR’ )

C                                        SO WE CAN NOW CALCULATE THE SLOPE OF THE ln(WOR) VS CUM LINE

WORSW(IW)=(ALOG(25.)-WORI)/(R25)

IF(WORSW(IW).LT.0.0) THEN

WRITE(*,*) ‘ WARNING: WORSW(IW)<0. SETTING TO 0’

WORSW(IW)=0.0

ENDIF

WORIW(IW)=WORI

RETURN

END

c************************************************************************************

SUBROUTINE NEWWELLS(IS,IT,CUMWK)

C                                        ADD IN ALL THE NEW WELLS FOR THIS TIME PERIOD:

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN,HYPERWOR,QIHYPER(140),COSTGF(140),

&QISLPSLP,QIINTSLP,QISLPINT,Q1INTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT,

&DCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCOWST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140).

&WORSW(50),WORIW(50),RATESW(50),RATEIW(50),POWELL(50),POAVG(50).

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&QILLBU(140),WTRLBU(140),CUMLBU(140),WORLBU(140),

&CUM(140,140),OIL(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

C                                        HERE, IS=IT

WWWM=WMAX

C                                        BUT IT CANNOT EXCEED THE LAST TIME’S WELLS + WINCMX

IF(IT.GT.1) WELLST=WELLS(IT-1)

IF(WWWM.GT.(WELLST+WINCMX)) WWWM=WELLST+WINCMX

NWMAX=(WWM+.95)

WFRACT=WWWM-FLOAT(NWMAX-1)

IF(WFRACT.LE.0.0) WFRACT=0.0

ISWITCH=0

DO 1000 IW=1,NWMAX

C                                        DETERMINE THE WORSLOPE, WORINT, RATESLOP, & RATEINT

 

12



 

C                                        FOR EACH OF THE NEW WELLS, THEN CALCULATE THE PAYOUT TIME

POAVG(IW)=0.0

CALL FWOR(IW,CUMWK)

CALL FRATE(IW,CUMWK)

WELLCOST=FCOST(APRICE(IT))*CAPSLP

CALL POSUB(WORSW(IW),WORIW(IW),

& RATESW(IW),RATEIW(IW),APRICE(IT),WELLCOST,COSTO(IT),COSTGF(IT),

&POWELL(IW))

C                                        NOW CHECK TO SEE IF THIS WELL WILL PAYOUT

IF(POWELL(IW).LE.PAYTIME) THEN

C                                        THEN WE ADD IT. DON’T WORRY HERE ABOUT WMAX OR WMIN. WE’LL

C                                        HANDLE THAT BELOW.

WELLS(IS)=FLOAT(IW)

GO TO 1000

ELSE

C                                        THEN WE HAVE A WELL THAT DOESN’T MEET OUR PAYOUT CRITERION.

C                                        CALCULATE A FRACTIONAL WELL THAT WILL GIVE US A PAYOUT TIME

C                                        EQUAL TO PAYTIME.

C                                        WE KNOW THE PAYOUT TIME FROM THE PREVIOUS WELL. USE IT.

IF(ISWITCH.GE.1) GO TO 1000

IF(IW.GT.1) THEN

WELLS(IS)=(PAYTIME-POWELL(IW-1))/(POWELL(1W)-POWELL(IW-1))

&+FLOAT(IW-1)

ISWITCH=1

ELSE

WELLS(IS)=(PAYTIME)/(POWELL(1W))

ENDIF

ISWITCH=1

ENDIF

1000                                       CONTINUE

1010                                       CONTINUE

C                                        HERE, WE NEED TO ACCOUNT FOR WWWM AND WMIN

IF(WELLS(IS).LT.WMIN) THEN

WELLS(IS)=WMIN

ENDIF

IF(WELLS(IS).GT.WWWM) THEN

WELLS(IS)=WWWM

ENDIF

C

C                                        NOW WE FIGURE OUT THE AVERAGE PROPERTIES FOR THE GROUP OF

C                                        NEW WELLS.

IW=INT(WELLS(IS)-.001+1.0)

c

c                                           *** test if iw = 0, set to 1

c

if (iw .eq. 0) then iw = 1

PAYOUT(IS)=POWELL(IW)

IF(WELLS(IS).LT.FLOAT(IW)) THEN

IF(IW.GT.1) THEN

PAYOUT(IS)=(POWELL(IW)-POWELL(IW-1))*(WELLS(IS) - FLOAT(IW-1))

&                                       +POWELL(IW-1)

 

13



 

ELSE

PAYOUT(IS)=POWELL(IW)*WELLS(IS)

ENDIF

ENDIF

CALL AVGPROP(IS)

C                                        SO WE HAVE NOW CALCULATED ALL THE INITIALIZATION DATA FOR THE

C                                        NEW GROUP OF WELLS

RETURN

END

c************************************************************************************

SUBROUTINE OWC(IS,IT)

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN, HYPPRWOR,QIHYPER(140),COSTGF(140),

&QISLPSLP,QIINTSLP,QISLPINT,QIINTINT,

&RSSLPSLP,RSIWTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOIWTSLP,WOSLPINT,WOINTINT,

&DCSLPSLP,DCINTSLP,DCSLPINT,DCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140),

&WORSW(50),WORIO(50),RATESW(50),RATEIW(50),POWELL(50),POAVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&OILLBU(140),WTRLBU(140),CUMLBU(140),WORLBU(140),

&CUM(140,140),O1L(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

C                                        HERE, WE MUST BE CAREFUL TO USE EQUIVALENT NON-SHUT-IN TIMES.

C                                        IF A WELL HAS BEEN SHUT IN FOR ANY LENGTH OF TIME, THE

C                                        TIME VALUE USED IN THE DECLINE EQUATION SHOULD BE THE EQUIVALENT

C                                        TIME AS THOUGH THE WELL HAD BEEN PRODUCING CONTINUOUSLY.

C                                        CHECK TO SEE IF WE ARE HYPERBOLIC YET OR NOT:

IF(IT.GT.IHYPER(IS).AND.IHYPER(IS).GT.O.AND.HYPERN.GT.0.0) THEN

C                                        THEN WE ARE ON THE HYPERBOLIC CURVE

C                                        THE FIRST THING WE MUST DO IS CALCULATE THE OIL RATE AT THE

C                                        LAST PRODUCING CUM.

C                                        BUT THIS MUST BE THE INCREMENTAL CUM SINCE GOING HYPERBOLIC

CUMH=CUM(IS,(IT-1))-CUM(IS,IHYPER(IS))

Q2=( (Q1HYPER(IS)/((1-HYPERN)*(-1.)*RATSLOPE(IS)) - CUMH )

&*(1.-HYPERN)*(-1.*RATSLOPE(IS))/Q1HYPER(1S)**HYPERN)

&**(1./(1.-HYPERN))

C                                        NOW CALCULATE THE EQUIVALENT TIME SINCE WE WENT HYPERBOLIC THAT

C                                        CORRESPONDS TO THIS RATE

c

T2 = (1.00 - (Q1HYPER(IS)/Q2)** HYPERN)/(HYPERN*RATSLOPE(IS))

C

Q3 = Q1HYPER(IS) * (1.00 - HYPERN * RATSLOPE(IS)*(T2+TIMINC))

1                                                                                                                  ** (-1.0/HYPERN)

C

DCUM*Q1HYPER(IS)**HYPERN/(1.-HYPERN)/(-1.*RATSLOPE(IS))*

&(Q2**(1.-HYPERN)-Q3**(1.-HYPERN))

CUM(IS,IT)=CUM(IS,(IT-1))+DCUM

 

14



 

C                                        SO WE HAVE DONE HYPERBOLIC DECLINE AFTER TIME=TIME(IHYPER(IS))

ELSE

C                                        HERE, WE DO EXPONENTIAL DECLINE

C                                        WE HAVE TO BACK CALCULATE T2, THE TIME TO THE END OF THE

C                                        LAST TIME STEP, SINCE WE MAY HAVE HAD SOME SHUT IN TIMES.

C

IF(RATSLOPE(IS).NE.0.0.AND.RATINIT(IS).GT.0.0) THEN

IF(IT.GT.1) THEN

T2=ALOG(CUM(IS.(IT-1))*RATSLOPE(IS)/(RATINIT(IS)*365.)+1.0)

&/RATSLOPE(IS)

T3=T2+.TIMINC

ELSE

T3=TIMINC

ENDIF

CUM(IS,IT)=RATINIT(IS)*365./RATSLOPE(IS)*

&(EXP(RATSLOPE(IS)*T3)-1.0)

ELSE

T3=TIMINC

CUM(IS,IT)=0.0

ENDIF

C

ENDIF

C

C                                        NOW FIND OIL FOR THIS TIME STEP

IF(IT.EQ.1) THEN

OIL(IS,IT)=CUM(IS,IT)

ELSE

OIL(IS,IT)=CUM(IS,IT)-CUM(IS,(IT-1))

ENDIF

C

C                                        NOW CALCULATE THE WATER FOR THIS TIME STEP

CUM0=0.0

IF(WELLS(IS).GT.0.0) CUMO=CUM(IS,IT)

WATER(IS,IT)=OIL(IS,IT)*EXP(WORSLOPE(IS)*CUMO+WORINIT(IS))

C

C                                        CALCULATE WOR

WORWK=0.0

IF(OIL(IS,IT).GT.0.0) WORWK=WATER(IS,IT)/OIL(IS,IT)

C                                        CHECK FOR PROFITABILITY:

PROF=OIL(IS,IT)*PRICE(IT)-(WATER(IS,IT)+OIL(IS,IT))*COSTGF(IT)

&-OIL(IS,IT)*COSTO(IT)

IF(PROF.LE.0.0) THEN

OIL(IS,IT)=0.0

WATER(IS,IT)=0.0

CUM(IS,IT)=CUM(IS,(IT-1))

ENDIF

C                                        HERE WE CHECK TO SEE IF THE WOR FOR THIS GROUP OF WELLS IS

C                                        HIGH ENOUGH TO START GOING HYPERBOLIC IN THE NEXT TIME

C                                        STEP.

IF(HYPER(IS).EQ.O.AND.HYPERN.GT.O.O.AND.WORWK.GT.HYPERWOR

&.AND.RATINIT(IS).GT.0.0) THEN

 

15



 

IHYPER(IS)=IT

C                                        Q1HYPER=THE OIL RATE CALCULATED FROM THE EXPONENTIAL DECLINE

C                                                                                        AT THE END OF THE EXPONENTIAL PERIOD (T2)

C                                                                                        THIS NEEDS TO BE IN BBL/YEAR

Q1HYPER(IS)=RATINIT(IS)*365.*EXP(RATSLOPE(IS)*T3)

C                                        CUMEXP IS THE CUM FOR THIS GROUP OF WELLS AT THE TIME THEY

C                                                                                        STARTED GOING HYPERBOLIC (LAST EXPONENTIAL CUM)

ENDIF

RETURN

END

c************************************************************************************

C                                        CALCULATE PAYOUT HERE: ITERATIVE SOLUTION

SUBROUTINE POSUB(WORSLP,WORINT,01,PI,P,XINV,COSTO,COSTGF,

&PAYOUT)

C                                                                FIRST, ASSUME CAPITAL PER WELL = SLOPE OF CAP VS # WELLS

C                                                                NOW WE HAVE TO ITERATIVELY CALCULATE OIL TO PAYOUT:

C                                                                START WITH AN ASSUMPTION THAT WOR DURING PAYOUT = INITIAL WOR

C                                                                THE NEXT GUESS IS THAT WOR=INITIAL WOR+1.

C                                                                KEEP ITERATING UNTIL XLHS=XRHS

IF(WORINT.GT.3.2188) WORINT=3.21888

IF(WORINT.LT.-10.) WORINT=-10.

IF(WORSLP.LE.0.0) THEN

C                                        THEN PAYOUT IS FAIRLY SIMPLE

OILPO3=XINV/(P-COSTO-COSTGF-COSTGF*(EXP(WORINT)))

GO TO 510

ENDIF

C

XLHS=XINV

IF(XLHS.LE.0.0) THEN

OILPO3=9.999E+06

GO TO 510

ENDIF

OILPO1=XINV/(P-COSTO-COSTGF-COSTGF · (EXP(WORINT)))

OILPO2=XINV/(P-COSTO-COSTGF-COSTGF’(EXP(WORINT)+2))

IF((OILPO1*WORSLP).GT.85.) OILPO1=70./WORSLP

IF((OILPO2*WORSLP).GT.85.) OILPO2=85./WORSLP

IF(OILPO1.LT.0.0) OILPO1=0.0

IF(OILPO2.LT.0.0) OIL,02=1000.

C

NITER=0

410                            CONTINUE

IF(WORSLP*OILPO1.LT.85.O.AND.WORSLP*OILPO2.LT.85.0) THEN

XRHS=OILPO1*(P-COSTO-COSTGF)-COSTGF · EXP(WORINT)*

&(EXP(WORSLP*OILPO1)-1.0)/WORSLP

ERROR1=(XRHS-XLHS)/XLHS

XRHS=OILPO2*(P-COSTO-COSTGF)-COSTGF*EXP(WORINT)*

&(EXP(WORSLP*OILPO2)-1.0)/WORSLP

ERROR2=(XRHS-XLHS)/XLHS

ELSE

OILPO3=9.999E+06

GO TO 510

 

16



 

ENDIF

C

C                                        THE NEXT GUESS ASSUMES LINEAR RELATIONSHIP BETWEEN ERROR& ERROR2

C                                        SOLVE FOR ERROR3=0

IF(ERROR1.NE.ERROR2) THEN

OILPO3=OILPO1-ERROR1*(OILPO1-OILPO2)/(ERROR1-ERROR2)

ELSE

OILPO3 =9.999E+06

GO TO 510

ENDIF

IF(OILPO3.LT.9.999E+06.AND.OILPO3.GT.0.0) THEN

C                                        THIS COVERS THE CASE WHERE THE WELL WILL NEVER PAYOUT:

IF(OILPO3.LE.0.0.OR.(OILPO3*WORSLP).GT.85.) THEN

OILPO3=9.999E+06

GO TO 510

ENDIF

XRHS=OILPO3*(P-COSTO-COSTGF)-COSTGF*EXP(WORINT)*

&(EXP(WORSLP*OILPO3)-1.0)/WORSLP

ERROR3=(XRHS-XLHS)/XLHS

C                                        IF ERROR3 IS LESS THAN .5%, THEN STOP AND USE OILPO3 AS THE OIL

IF(ABS(ERROR3).LE.0.005) THEN

GO TO 510

ENDIF

IF(NITER.GT.10) THEN

OILPO3=9.99E+06

GO TO 510

ENDIF

C                                        NOW REPLACE EITHER OILPO1 OR OILPO2 WITH OILPO3, DEPENDING ON

C                                        WHICH ONE HAS THE SMALLEST ERROR.

IF(ABS(ERROR1).GE.ABS(ERROR2)) THEN

OILPO1=OILPO3

ELSE

OILPO2=OILPO3

ENDIF

NITER=NITER+1

GO TO 410

C

ELSE

OILPO3=9.999E+06

GO TO 510

ENDIF

C                                        NOW WE HAVE AN OIL TO PAYOUT. WE SIMPLY HAVE TO CALCULATE THE

C                                        TIME TO PAYOUT BASED ON THE DECLINE CURVE EQUATION

510                                                    CONTINUE

PO=OILPO3

C

C**                          Note that Di is negative…

C

XNUM = PO * DI /(PI * 365.00)

C

IF(PO.LT.9.99E+06.AND.PO.GT.0.0.AND.PI.GT.0.0 .AND.

 

17



 

1                                          XNUM .GT. -1.00) THEN

PAYOUT = ALOG(XNUM+1.00) / DI

C

ELSE

PAYOUT=99.99

ENDIF

C

RETURN

END

C***********************************************************************************

C                                        READER SUBROUTINE FOR LBU FORECASTING MODEL

SUBROUTINE READER

C                                        COMMON GOES HERE

COMMON TIME(140),PRICE(140),APRICE(140),COSTO(140),

&HYPERN,HYPERWOR,QIHYPER(140),COSTGF(140),

&QISLPSLP,QIINTSLP,QISLPINT,QIINTINT,

&RSSLPSLP,RSINTSLP,RSSLPINT,RSINTINT,

&WOSLPSLP,WOINTSLP,WOSLPINT,WOINTINT,

&DCSLPSLP,DCINTSLP,DCSLPINT,OCINTINT,

&CAPSLP,CAPINT,COSTSLP,COSTINT,GFCONST,TIMGFCUT,

&BOIL(140),BCUM(140),BWTR(140),

&WORSW(50),WORIW(50),RATESW(50),RATEIW(50),POWELL(50),POAVG(50),

&RATSLOPE(140),RATINIT(140),WORSLOPE(140),WORINIT(140),

&WELLS(140),PAYOUT(140),

&OILLBU(140),WTRLBU(140),CUMLBU(140),WORLBU(140),

&CUM(140,140),OIL(140,140),WATER(140,140),

&PAYTIME,WMAX,WMIN,WINCMX,WFRACT,SDATE,TIMINC,STCUM,WELLST,NINC,

&IHYPER(140),COSTF(140),COSTGFF(140),COSTRED(140)

COMMON /READ/ PAYSLOPE,PAYINT,COST015,COSTGF15,COSTF15,CSTGFF15

COMMON /READ2/ GFCAP(10),GFTIME(10),NGFCAP

COMMON /READ3/ PAYS(20),PAYI(20),PAYTIM(20),NPAYTIM

COMMON /READ4/ WCUM

C                                        LN(INITIAL OIL RATE PER WELL) VS LBU CUM DATA AS FUNCTION OF TOTAL

C                                        NUMBER OF WELLS DRILLED IN A TIME STEP

C                                                                THE FINAL DATA WE NEED LOOKS LIKE THIS:

C                                                                                        |\

C                                        In (IP)              |                                                                                                                                                                                                                                              Increasing LBU CUM

C                                        PER                         |                                              \

C                                        WELL             |\                                                                                                                                                                                                                                          /                                             this way

C                                                                                        |                                              \                                             \                                                                                             /

C                                                                                        |                                                                                                                                                    /

C                                                                                        |\                                                                                          \                                             \

C                                                                                        |                                              \

C                                                                                        |\                                                                                          \                                             \                                             \

C                                                                                        |--------------------------------------------------

# OF WELLS DRILLED

IN TIME STEP

C

C                                        TO BUILD THIS, WE ONLY NEED THE FOLLOWING TWO GRAPHS:

C

 

18



 

C                                        SLOPE          |                                                                                                                                              INTERCEPT                          |\

C                                        OF                                 |                                                                                                                                              OF                                                                                 |      \

C                                        THESE        |---------------------          THESE                                                                    |          \

C                                        LINES            |                                                                                                                                              LINES                                                            |               \

C                                                                                        |                                                                                                                                                                                                                                              |                    \

C                                                                                        |---------------------                                                                                                                       |---------------------

C                                                                                        LBU CUM                                                                                                                                      LBU CUM

C

C                                        SO WE READ IN THESE TWO FUNCTIONS ABOVE WITH A SLOPE AND

C                                                                INTERCEPT OF THEIR OWN.

C                                        SLOPE OF THE (SLOPE VS LBU CUM) PLOT

C                                                                INTERCEPT OF THE (SLOPE VS LBU CUM) PLOT

C                                                                SLOPE OF THE (INTERCEPT VS LBU CUM) PLOT

C                                                                INTERCEPT OF THE (INTERCEPT VS LBU CUM) PLOT

C

READ(4,*) QISLPSLP,Q1INTSLP

READ(4,*) QISLPINT,QIINTINT

C

C                                        NOW DO THE SAME THING FOR In(RESERVES @ WOR=25) VS # WELLS

C

READ(4,*) RSSLPSLP,RSINTSLP

READ(4,*) RSSLPINT,RSINTINT

C

C                                        NOW DO THE SAME THING FOR INITIAL 1n(WOR) VS # WELLS

C                                                                THAT IS:

Cin(WOR)=#WELLS)*(WOSLPSLP*LBUCUM+WOINTSLP)+(WOSLPINT*LBUCUM+WOINTINT)

C

READ(4,*) WOSLPSLP,WOINTSLP

READ(4,*) WOSLPINT,WOINTINT

C

C                                        NOW DO THE SAME THING FOR EXPONENTIAL DECLINE RATE VS # WELLS

C

READ(4,*) DCSLPSLP,DCINTSLP

READ(4,*) DCSLPINT,DCINTINT

C

C

C                                        SWITCH TO HYPERBOLIC DECLINE AFTER A WOR VALUE

READ(4,*) HYPERN,HYPERWOR

C

C

C                                        NOW READ IN THE PAYOUT CRITERION

C                                        THIS IS THE SLOPE & INTERCEPT OF PAYOUT CRITERION VS OIL PRICE

READ(4,*) NPAYTIM

DO 8 I=1,NPAYTIM

8                                                                  READ(4,*) PAYS(I),PAYI(I),PAYTIM(I)

C                                        MAX & MIN # OF WELLS TO DRILL IN THE TIME STEP

READ(4,*) WMAX

READ(4,*) WMIN

C                                        MAXIMUM INCREASE IN NUMBER OF WELLS FROM THE PREVIOUS TIME STEP

READ(4,*) WINCMX

C

 

19



 

C                                        CAPITAL SPENDING VS # OF WELLS DRILLED PER YEAR

READ(4,*) CAPSLP,CAPINT

C

C                                        COSTS FOR OIL, GF, AND FIXED AT $15/BBL OIL PRICE

READ(4,*) COSTO15,COSTGF15,CSTGFF15,COSTF15

C

C                                        ADJUSTMENT FACTOR FOR COST AS FUNCTION OF OIL PRICE

READ(4,*) COSTSLP,COSTINT

C

C                                        READ IN THE GROSS FLUID FIELD CONSTRAINTS:

C                                                                READ(4,*) GFCONST,TIMGFCUT

READ(4,*) NGFCAP

DO 12 I=1,NGFCAP

12                                                           READ(4,*) GFCAP(I),GFTIME(I)

C

C                                        NOW READ IN THE START DATA:

READ(4,*) SDATE,TIMINC,NINC,STCUM,WELLST,WCUM

C                                        WHERE:

C                                                                SDATE IS START DATE

C                                                                TIMINC IS TIME INCREMENT

C                                                                NINC                                         IS NUMBER OF TIME INCREMENTS TO RUN THIS TIME

C                                                                STCUM IS THE LBU CUM OIL PRODUCTION AT THE START OF THE RUN

C                                                                WELLST IS THE # OF WELLS DRILLED IN THE TIME INCREMENT

C                                                                                                                                        PRECEEDING THE START OF THIS RUN

C

C                                        NOW READ IN THE RUN TIME DATA INPUT FOR EACH TIME STEP

DO 15 I=1,NINC

15                                                           READ(4,*) BOIL(I),BWTR(I),PRICE(I),COSTRED(I)

C                                        WHERE

C                                                                BOIL(I) IS THE BASE OIL PRODUCTION FOR WELLS DRILLED PRIOR

C                                                                                                                                        TO 7/1/90

C                                                                BWTR(I) ID THE BASE WATER PRODUCTION FOR WELLS DRILLED PRIOR

C                                                                                                                                        TO 7/1/90

C                                                                PRICE(I) IS THE INFLATION-ADJUSTED OIL PRICE FOR EACH TIME STEP

C                                                                COSTRED(I) IS THE ADDITIONAL COST REDUCTION FACTOR FOR THIS

C                                                                                                                                        TIME PERIOD.

RETURN

END

 

20


 

ATTACHMENT 3

 

 

TABLE OF VALUES TOR GRAPH

 

MONTH

 

ASSUMED BASE OIL 
PRODUCTION

 

CORRECTION
FACTOR

 

ADJUSTED BASE 
OIL PRODUCTION

1

 

46000

 

47,000 / 46,000 = 1.0217

 

47000

2

 

45967

 

1.0217 - (.0217/23)

 

46923

3

 

45935

 

1.0208 - (.0217/23)

 

46847

4

 

45902

 

1.0198 - (.0217/23)

 

46770

5

 

45870

 

1.0189 - (.0217/23)

 

46693

6

 

45837

 

1.0179 - (.0217/23)

 

46617

7

 

45804

 

1.0170 - (.0217/23)

 

46540

8

 

45772

 

1.0161 - (.0217/23)

 

46464

9

 

45739

 

1.0151 - (.0217/23)

 

46388

10

 

45707

 

1.0142 - (.0217/23)

 

46311

11

 

45674

 

1.0132 - (.0217/23)

 

46235

12

 

45641

 

1.0123 - (.0217/23)

 

46159

13

 

45609

 

1.0113 - (.0217/23)

 

46083

14

 

45576

 

1.0104 - (.0217/23)

 

46007

15

 

45544

 

1.0095 - (.0217/23)

 

45931

16

 

45511

 

1.0085 - (.0217/23)

 

45855

17

 

45478

 

1.0076 - (.0217/23)

 

45779

18

 

45446

 

1.0066 - (.0217/23)

 

45704

19

 

45413

 

1.0057 - (.0217/23)

 

45628

20

 

45381

 

1.0047 - (.0217/23)

 

45552

 

1



 

21

 

45348

 

1.0038 - (.0217/23)

 

45477

22

 

45315

 

1.0028 - (.0217/23)

 

45401

23

 

45283

 

1.0019 - (.0217/23)

 

45326

24

 

45250

 

1.0009 - (.0217/23)

 

45250

 

THE SAME CORRECTION FACTORS WILL BE USED TO ADJUST BASE WATER PRODUCTION

 

2



 

ATTACHMENT 4

 

 

1



 

Attachment 5

 

This attachment lists the input file “foreaa.dat” for the Computer Program.  The oil price input (in dollars per barrel), which is enclosed in the box in the printout below, is the only input data which will change.  The oil prices in the box are the inputted average prices for each quarter, deflated to January 1, 1990.  The computer program calculates the four-quarter trailing average for each quarter.  The oil prices below are for example only.  The procedure for calculating input price is specified in Equation 17 of Appendix A.

 

-4.3810E-10

 

9.7410E-02

 

 

 

 

 

SLOPE & INT OF SLOPE FOR Q1 VS # WELLS/QTR

-2.0273E-09

 

7.0175E+00

 

 

 

 

 

SLOPE & INT OF INT FOR QI VS # WELLS

-6.2312E-10

 

2.4767E-01

 

 

 

 

 

SLOPE & INT OF SLOPE FOR RES VS # WELLS

-2.7510E-09

 

1.4993E+01

 

 

 

 

 

SLOPE & INT OF INT FOR RES VS # WELLS

3.9351E-10

 

-1.5094E-01

 

 

 

 

 

SLOPE & INT OF SLOPE FOR WORI VS # WELLS

1.6104E-09

 

-8.0521E-01

 

 

 

 

 

SLOPE & INT OF INT FOR WORI VS # WELLS

1.2500E-12

 

-3.7500E-04

 

 

 

 

 

SLOPE & INT OF SLOPE FOR DI VS # WELLS

1.7500E-10

 

5.7500E-02

 

 

 

 

 

SLOPE & INT OF INT FOR DI VS # WELLS

0.2

 

7

 

0.14

 

 

 

HYPERN, HYPERWOR, HYPERDI

5

 

 

 

 

 

 

 

# OF PAYOUT VS PRICE CRITERIA

0

 

3.5

 

1980

 

 

 

PAYSLOPE PAYINT AT YEAR SHOWN

0

 

3.5

 

1982

 

 

 

PAYSLOPE PAYINT AT YEAR SHOWN

0

 

3.5

 

1986

 

 

 

PAYSLOPE PAYINT AT YEAR SHOWN

0

 

3.5

 

1991

 

 

 

PAYSLOPE PAYINT AT YEAR SHOWN

0

 

2.5

 

2000

 

 

 

PAYSLOPE PAYINT AT YEAR SHOWN

18

 

 

 

 

 

 

 

MAX # OF WELLS IN TIME STEP

0

 

 

 

 

 

 

 

MIN # OF WELLS IN TIME STEP

1.5

 

 

 

 

 

 

 

MAX INCREASE IN # WELLS IN TIME STEP

900000

 

0

 

 

 

 

 

SLOPE & INT OF CAP VS # WELLS

 

 

 

 

 

 

 

 

 

0.29056

 

0.293756

 

0.137118

 

26897277

 

$/BO, $/GFvar, $/GFfix, and Other Fixed Cost/Yr

0.0123615

 

0.8145769

 

 

 

 

 

SLOPE & INT OF COST vs oil Price

10

 

 

 

 

 

 

 

# OF GF LIMITS TO FOLLOW

650000

 

1980

 

 

 

 

 

GFCAP, GFTIME

475000

 

1986.75

 

 

 

 

 

GFCAP, GFTIME

900000

 

1991

 

 

 

 

 

GFCAP, GFTIME

900000

 

1991.25

 

 

 

 

 

GFCAP, GFTIME

900000

 

1991.5

 

 

 

 

 

GFCAP, GFTIME

900000

 

1992

 

 

 

 

 

GFCAP, GFTIME

900000

 

1992.5

 

 

 

 

 

GFCAP, GFTIME

900000

 

1992.75

 

 

 

 

 

GFCAP, GFTIME

900000

 

1993

 

 

 

 

 

GFCAP, GFTIME

900000

 

1993.25

 

 

 

 

 

GFCAP, GFTIME

1990.5

 

0.25

 

118   718620000

5.5 2745600000 SDATE,TIMINC,NINC,STCUM,WELLST

4181112

 

38874070

 

12.55

 

1

 

1990.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

4108339

 

39108240

 

12.55

 

1

 

1990.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

4036404

 

39335430

 

12.55

 

1

 

1991.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

4006223

 

39972120

 

12.55

 

1

 

1991.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3893702

 

39774140

 

12.55

 

1

 

1991.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3863638

 

40401980

 

12.55

 

1

 

1991.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3754517

 

40192610

 

12.55

 

0.943327

 

1992.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3686437

 

40395640

 

12.55

 

0.950411

 

1992.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3618651

 

40599220

 

12.55

 

0.957495

 

1992.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3551683

 

40797490

 

12.55

 

0.964579

 

1992.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3455855

 

40629810

 

12.55

 

0.971663

 

1993.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3345725

 

40233900

 

12.55

 

0.978747

 

1993.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3239788

 

39827990

 

12.55

 

0.985832

 

1993.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3137854

 

39412610

 

12.55

 

0.992916

 

1993.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

3039372

 

38984850

 

12.55

 

1

 

1994.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2944214

 

38545090

 

12.55

 

1

 

1994.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2852223

 

38093840

 

12.55

 

1

 

1994.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2763306

 

37631490

 

12.55

 

1

 

1994.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2677353

 

37158590

 

12.55

 

1

 

1995.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2594224

 

36675800

 

12.55

 

1

 

1995.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2513865

 

36183600

 

12.55

 

1

 

1995.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2436130

 

35682800

 

12.55

 

1

 

1995.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2360973

 

35173860

 

12.55

 

1

 

1996.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2288246

 

34657660

 

12.55

 

1

 

1996.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2217902

 

34134810.

 

12.55

 

1

 

1996.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2149853

 

33606000

 

12.55

 

1

 

1996.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

 

1



 

2083989

 

33072010

 

12.55

 

1

 

1997.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

2020250

 

32533490

 

12.55

 

1

 

1997.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1958596

 

31991120

 

12.55

 

1

 

1997.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1898904

 

31445700

 

12.55

 

1

 

1997.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1841108

 

30897880

 

12.55

 

1

 

1998.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1785197

 

30348260

 

12.55

 

1

 

1998.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1731034

 

29797580

 

12.55

 

1

 

1998.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1678627

 

29246460

 

12.55

 

1

 

1998.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1627862

 

28695530

 

12.55

 

1

 

1999.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1578713

 

28145380

 

12.55

 

1

 

1999.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1531104

 

27596580

 

12.55

 

1

 

1999.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1484999

 

27049670

 

12.55

 

1

 

1999.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1440367

 

26505160

 

12.55

 

1

 

2000.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1397120

 

25963640

 

12.55

 

1

 

2000.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1355241

 

25425490

 

12.55

 

1

 

2000.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1314654

 

24891230

 

12.55

 

1

 

2000.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1275349

 

24361180

 

12.55

 

1

 

2001.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1237263

 

23835860

 

12.55

 

1

 

2001.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1200353

 

23315560

 

12.55

 

1

 

2001.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1164586

 

22800640

 

12.55

 

1

 

2001.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1129948

 

22291410

 

12.55

 

1

 

2002.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1096369

 

21788150

 

12.55

 

1

 

2002.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1063838

 

21291100

 

12.55

 

1

 

2002.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1032282

 

20800670

 

12.55

 

1

 

2002.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

1001713

 

20316850

 

12.55

 

1

 

2003.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

972094.4

 

19839930

 

12.55

 

1

 

2003.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

943388.2

 

19370140

 

12.55

 

1

 

2003.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

915539.7

 

18907580

 

12.55

 

1

 

2003.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

888551.1

 

18452400

 

12.55

 

1

 

2004.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

862388.6

 

18004750

 

12.55

 

1

 

2004.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

837011.1

 

17564680

 

12.55

 

1

 

2004.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

812433.2

 

17132220

 

12.55

 

1

 

2004.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

788569.0

 

16707570

 

12.55

 

1

 

2005.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

765452.6

 

16290660

 

12.55

 

1

 

2005.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

743039.4

 

15881600

 

12.55

 

1

 

2005.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

721292.3

 

15480380

 

12.55

 

1

 

2005.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

700204.1

 

15086980

 

12.55

 

1

 

2006.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

679760.4

 

14701420

 

12.55

 

1

 

2006.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

659922.0

 

14323750

 

12.55

 

1

 

2006.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

640687.4

 

13953810

 

12.55

 

1

 

2006.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

622039.5

 

13591660

 

12.55

 

1

 

2007.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

603931.9

 

13237260

 

12.55

 

1

 

2007.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

586399.2

 

12890470

 

12.55

 

1

 

2007.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

569349.1

 

12551310

 

12.55

 

1

 

2007.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

552840.9

 

12219720

 

12.55

 

1

 

2008.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

536819.9

 

11895550

 

12.55

 

1

 

2008.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

521274.7

 

11578780

 

12.55

 

1

 

2008.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

506190.7

 

11269300

 

12.55

 

1

 

2008.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

491551.6

 

10967020

 

12.55

 

1

 

2009.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

477356.9

 

10671840

 

12.55

 

1

 

2009.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

463597.3

 

10383670

 

12.55

 

1

 

2009.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

450230.6

 

10102390

 

12.55

 

1

 

2009.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

437255.9

 

9827943

 

12.55

 

1

 

2010.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

424673.9

 

9560148

 

12.55

 

1

 

2010.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

412459.1

 

9298935

 

12.55

 

1

 

2010.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

400592.1

 

9044251

 

12.55

 

1

 

2010.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

389088.7

 

8795897

 

12.55

 

1

 

2011.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

377926.1

 

8553767

 

12.55

 

1

 

2011.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

367098.8

 

8317746

 

12.55

 

1

 

2011.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

356577.6

 

8087749

 

12.55

 

1

 

2011.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

346378.5

 

7863660

 

12.55

 

1

 

2012.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

336469.2

 

7645299

 

12.55

 

1

 

2012.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

326849.9

 

7432619

 

12.55

 

1

 

2012.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

317527.4

 

7225458

 

12.55

 

1

 

2012.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

308471.6

 

7023741

 

12.55

 

1

 

2013.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

299672.6

 

6827325

 

12.55

 

1

 

2013.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

291122.1

 

6636120

 

12.55

 

1

 

2013.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

282831.6

 

6449969

 

12.55

 

1

 

2013.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

274785.1

 

6268762

 

12.55

 

1

 

2014.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

266973.7

 

6092415

 

12.55

 

I

 

2014.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

 

2



 

259409.3

 

5920810

 

12.55

 

1

 

2014.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

252029.7

 

5753830

 

12.55

 

1

 

2014.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

244893.6

 

5591409

 

12.55

 

1

 

2015.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

237934.9

 

5433318

 

12.55

 

1

 

2015.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

231213.6

 

5279554

 

12.55

 

1

 

2015.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

224665.6

 

5129957

 

12.55

 

1

 

2015.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

218299.6

 

4984537

 

12.55

 

1

 

2016.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

212124.1

 

4843110

 

12.55

 

1

 

2016.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

206142.5

 

4705522

 

12.55

 

1

 

2016.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

200324.0

 

4571799

 

12.55

 

1

 

2016.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

194664.6

 

4441733

 

12.55

 

1

 

2017.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

189176.3

 

4315286

 

12.55

 

1

 

2017.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

183864.1

 

4192371

 

12.55

 

1

 

2017.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

178686.5

 

4072877

 

12.55

 

1

 

2017.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

173653.6

 

3956704

 

12.55

 

1

 

2018.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

168764.5

 

3843770

 

12.55

 

1

 

2018.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

164026.2

 

3734079

 

12.55

 

1

 

2018.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

159420.0

 

3627342

 

12.55

 

1

 

2018.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

154950.9

 

3523691

 

12.55

 

1

 

2019.00 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

150599.2

 

3422991

 

12.55

 

1

 

2019.25 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

146372.4

 

3325086

 

12.55

 

1

 

2019.50 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

142269.9

 

3229933

 

12.55

 

1

 

2019.75 PRE-80 GF/QTR, OIL PRICE (1/1/90 $)

 

3



 

Attachment 6

 

Attachment 6 lists the input file “forecast.dat” for the Computer Program.  This file lists the production history from July 1980 through June 1990 and never changes.

 

1980.75

 

5770100

 

35501000

 

5.01E+08

 

2.22E+08

 

41909000

 

1.21E+09

1981

 

6044300

 

37255000

 

5.07E+08

 

2.28E+08

 

44715000

 

1.24E+09

1981.25

 

5533300

 

33844000

 

5.13E+08

 

2.08E+08

 

44013000

 

1.28E+09

1981.5

 

5877600

 

36003000

 

5.19E+08

 

2.2E+08

 

47056000

 

1.31E+09

1981.75

 

6179900

 

38007000

 

5.25E+08

 

2.26E+08

 

49751000

 

1.35E+09

1982

 

6366100

 

39328000

 

5.31E+08

 

2.27E+08

 

51832000

 

1.39E+09

1982.25

 

6062000

 

37189000

 

5.37E+08

 

2.09E+08

 

51504000

 

1.43E+09

1982.5

 

6193700

 

38172000

 

5.44E+08

 

1.99E+08

 

52574000

 

1.47E+09

1982.75

 

6159300

 

38005000

 

5.5E+08

 

1.95E+08

 

52724000

 

1.51E+09

1983

 

6029200

 

37139000

 

5.56E+08

 

1.89E+08

 

51995000

 

1.54E+09

1983.25

 

5981500

 

36917000

 

5.62E+08

 

1.78E+08

 

51002000

 

1.58E+09

1983.5

 

6038700

 

37565000

 

5.68E+08

 

1.72E+08

 

50687000

 

1.62E+09

1983.75

 

6032300

 

37777000

 

5.74E+08

 

1.71E+08

 

50519000

 

1.65E+09

1984

 

5955800

 

37465000

 

5.8E+08

 

1.67E+08

 

49674000

 

1.69E+09

1984.25

 

6106900

 

39083000

 

5.86E+08

 

1.68E+08

 

49930000

 

1.73E+09

1984.5

 

6413800

 

42142000

 

5.92E+08

 

1.76E+08

 

51186000

 

1.77E+09

1984.75

 

6507500

 

43542000

 

5.99E+08

 

1.78E+08

 

51561000

 

1.82E+09

1985

 

6550900

 

44594000

 

6.05E+08

 

1.79E+08

 

51684000

 

1.86E+09

1985.25

 

6466600

 

44574000

 

6.12E+08

 

1.75E+08

 

51054000

 

1.91E+09

1985.5

 

6423900

 

44946000

 

6.18E+08

 

1.72E+08

 

50593000

 

1.95E+09

1985.75

 

6525100

 

46681000

 

6.25E+08

 

1.7E+08

 

50662000

 

2E+09

1986

 

6551400

 

47804000

 

6.31E+08

 

1.67E+08

 

50515000

 

2.05E+09

1986.25

 

6328000

 

46608000

 

6.38E+08

 

1.29E+08

 

45748000

 

2.09E+09

1986.5

 

5494500

 

39492000

 

6.43E+08

 

66721000

 

35185000

 

2.13E+09

1986.75

 

5086300

 

36294000

 

6.48E+08

 

54695000

 

32202000

 

2.17E+09

1987

 

5108800

 

37235000

 

6.53E+08

 

59551000

 

33227000

 

2.21E+09

1987.25

 

5025000

 

37117000

 

6.58E+08

 

71958000

 

35109000

 

2.24E+09

1987.5

 

5066500

 

38277000

 

6.63E+08

 

81148000

 

35249000

 

2.28E+09

1987.75

 

4958500

 

38385000

 

6.68E+08

 

85434000

 

35903000

 

2.32E+09

1988

 

4890800

 

38453000

 

6.73E+08

 

72628000

 

34043000

 

2.36E+09

1988.25

 

4825500

 

38518000

 

6.78E+08

 

58180000

 

31742000

 

2.4E+09

1988.5

 

4746200

 

38598000

 

6.83E+08

 

61606000

 

32326000

 

2.43E+09

1988.75

 

4661800

 

38682000

 

6.88E+08

 

55398000

 

31312000

 

2.47E+09

1989

 

4600600

 

38743000

 

6.92E+08

 

47831000

 

29914000

 

2.51E+09

1989.25

 

4569700

 

38774000

 

6.97E+08

 

58294000

 

31704000

 

2.55E+09

1989.5

 

4486400

 

38857000

 

7.01E+08

 

70153000

 

33644000

 

2.59E+09

1989.75

 

4425100

 

38919000

 

7.06E+08

 

62557000

 

32425000

 

2.63E+09

1990

 

4382000

 

38962000

 

7.1E+08

 

65730000

 

32905000

 

2.67E+09

1990.25

 

4342000

 

39002000

 

7.14E+08

 

65129000

 

32772000

 

2.71E+09

1990.5

 

4302300

 

39041000

 

7.19E+08

 

64535000

 

32646000

 

2.75E+09

1980.75

 

5606700

 

35288000

 

5.01E+08

 

61443

 

6.294

 

448170

1981

 

5707000

 

36783000

 

5.07E+08

 

62543

 

6.4451

 

465640

1981.25

 

5016400

 

33066000

 

5.12E+08

 

54974

 

6.5917

 

417340

1981.5

 

5179300

 

34878000

 

5.17E+08

 

56759

 

6.7341

 

438980

1981.75

 

5301600

 

36495000

 

5.22E+08

 

58099

 

6.8837

 

458040

1982

 

5312000

 

37389000

 

5.28E+08

 

58214

 

7.0386

 

467960

1982.25

 

4838400

 

34788000

 

5.33E+08

 

53023

 

7.19

 

434260

1982.5

 

4808000

 

35276000

 

5.37E+08

 

52691

 

7.337

 

439280

1982.75

 

4622400

 

34592000

 

5.42E+08

 

50657

 

7.4835

 

429740

1983

 

4352600

 

33191000

 

5.46E+08

 

47699

 

7.6256

 

411440

1983.25

 

4176000

 

32419000

 

5.5E+08

 

45764

 

7.7632

 

401040

 

1



 

1983.5

 

4114500

 

32501000

 

5.55E+08

 

45090

 

7.8993

 

401270

1983.75

 

3999700

 

32137000

 

5.59E+08

 

43833

 

8.0348

 

396020

1984

 

3824900

 

31241000

 

5.62E+08

 

41916

 

8.1677

 

384280

1984.25

 

3887200

 

32267000

 

5.66E+08

 

42599

 

8.3009

 

396210

1984.5

 

4114300

 

34730000

 

5.7E+08

 

45088

 

8.4413

 

425690

1984.75

 

4136800

 

35530000

 

5.75E+08

 

45335

 

8.5887

 

434700

1985

 

4117400

 

35980000

 

5.79E+08

 

45122

 

8.7386

 

439420

1985.25

 

3978000

 

35357000

 

5.83E+08

 

43594

 

8.8882

 

431070

1985.5

 

3887600

 

35128000

 

5.87E+08

 

42603

 

9.036

 

427570

1985.75

 

3948000

 

36265000

 

5.9E+08

 

43266

 

9.1857

 

440700

1986

 

3940100

 

36796000

 

5.94E+08

 

43179

 

9.3389

 

446420

1986.25

 

3690900

 

35025000

 

5.98E+08

 

40448

 

9.4895

 

424280

1986.5

 

2846000

 

27380000

 

6.01E+08

 

31189

 

9.6205

 

331240

1986.75

 

2433600

 

23673000

 

6.03E+08

 

26670

 

9.7275

 

286100

1987

 

2452500

 

24103000

 

6.06E+08

 

26877

 

9.8277

 

291010

1987.25

 

2363400

 

23463000

 

6.08E+08

 

25900

 

9.9274

 

283020

1987.5

 

2422300

 

24290000

 

6.11E+08

 

26546

 

10.028

 

292740

1987.75

 

2568500

 

26027000

 

6.13E+08

 

28148

 

10.133

 

313370

1988

 

2523800

 

25848000

 

6.16E+08

 

27658

 

10.242

 

310930

1988.25

 

2473300

 

25598000

 

6.18E+08

 

27104

 

10.35

 

307630

1988.5

 

2482900

 

25966000

 

6.21E+08

 

27210

 

10.458

 

311770

1988.75

 

2522300

 

26656000

 

6.23E+08

 

27641

 

10.568

 

319760

1989

 

2480700

 

26493000

 

6.26E+08

 

27186

 

10.68

 

317520

1989.25

 

2338000

 

25222000

 

6.28E+08

 

25622

 

10.788

 

302030

1989.5

 

2411600

 

26277000

 

6.3E+08

 

26428

 

10.896

 

314390

1989.75

 

2408600

 

26511000

 

6.33E+08

 

26396

 

11.007

 

316930

1990

 

2339900

 

26012000

 

6.35E+08

 

25642

 

11.117

 

310710

1990.25

 

2261300

 

25382000

 

6.37E+08

 

24781

 

11.225

 

302940

1990.5

 

2185900

 

24766000

 

6.4E+08

 

23955

 

11.33

 

295360

1

 

1980.75

 

0.468

 

7

 

 

 

 

 

 

2

 

1981

 

0.58

 

8.5

 

 

 

 

 

 

3

 

1981.25

 

0.718

 

10

 

 

 

 

 

 

4

 

1981.5

 

0.899

 

11.5

 

 

 

 

 

 

5

 

1981.75

 

1.135

 

13

 

 

 

 

 

 

6

 

1982

 

1.451

 

14.5

 

 

 

 

 

 

7

 

1982.25

 

1.861

 

16

 

 

 

 

 

 

8

 

1982.5

 

2.44

 

17.5

 

 

 

 

 

 

9

 

1982.75

 

2.746

 

18

 

 

 

 

 

 

10

 

1983

 

2.907

 

18

 

 

 

 

 

 

11

 

1983.25

 

3.15

 

18

 

 

 

 

 

 

12

 

1983.5

 

3.397

 

18

 

 

 

 

 

 

13

 

1983.75

 

3.5

 

17.814

 

 

 

 

 

 

14

 

1984

 

3.5

 

17.367

 

 

 

 

 

 

15

 

1984.25

 

3.5

 

16.929

 

 

 

 

 

 

16

 

1984.5

 

3.5

 

16.52

 

 

 

 

 

 

17

 

1984.75

 

3.5

 

16.148

 

 

 

 

 

 

18

 

1985

 

3.5

 

15.767

 

 

 

 

 

 

19

 

1985.25

 

3.5

 

15.365

 

 

 

 

 

 

20

 

1985.5

 

3.5

 

14.973

 

 

 

 

 

 

21

 

1985.75

 

3.5

 

14.51

 

 

 

 

 

 

22

 

1986

 

3.5

 

14.103

 

 

 

 

 

 

23

 

1986.25

 

3.5

 

12.764

 

 

 

 

 

 

24

 

1986.5

 

3.5

 

9.743

 

 

 

 

 

 

25

 

1986.75

 

3.5

 

8.838

 

 

 

 

 

 

26

 

1987

 

3.5

 

9.118

 

 

 

 

 

 

27

 

1987.25

 

3.5

 

10.072

 

 

 

 

 

 

 

2



 

28

 

1987.5

 

3.5

 

10.514

 

 

 

 

 

 

29

 

1987.75

 

3.5

 

10.689

 

 

 

 

 

 

30

 

1988

 

3.5

 

9.784

 

 

 

 

 

 

31

 

1988.25

 

3.5

 

8.508

 

 

 

 

 

 

32

 

1988.5

 

3.5

 

8.77

 

 

 

 

 

 

33

 

1988.75

 

3.5

 

8.143

 

 

 

 

 

 

34

 

1989

 

3.5

 

7.22

 

 

 

 

 

 

35

 

1989.25

 

3.5

 

8.217

 

 

 

 

 

 

36

 

1989.5

 

3.5

 

9.101

 

 

 

 

 

 

37

 

1989.75

 

3.5

 

8.447

 

 

 

 

 

 

38

 

1990

 

3.5

 

8.604

 

 

 

 

 

 

39

 

1990.25

 

3.5

 

8.468

 

 

 

 

 

 

40

 

1990.5

 

3.5

 

8.341

 

 

 

 

 

 

 

3



 

Attachment 7

 

Attachment 7 lists output file “forea.out” from the Computer Program, which results from the example input files included as Attachments 5 and 6. This output file is not based on actual oil prices, and is included for illustrative purposes only.

 

TIME

 

LBU TOTAL 
OIL

 

WATER

 

CUM

 

REV

 

COST

 

CUMw

1980.750

 

.57701E+07

 

.35501E+08

 

.50100E+09

 

.22200E+09

 

.41909E+08

 

.12100E+10

1981.000

 

.60443E+07

 

.37255E+08

 

.50700E+09

 

.22800E+09

 

.44715E+08

 

.12400E+10

1981.250

 

.55333E+07

 

.33844E+08

 

.51300E+09

 

.20800E+09

 

.44013E+08

 

.12800E+10

1981.500

 

.58776E+07

 

.36003E+08

 

.51900E+09

 

.22000E+09

 

.47056E+08

 

.13100E+10

1981.750

 

.61799E+07

 

.38007E+08

 

.52500E+09

 

.22600E+09

 

.49751E+08

 

.13500E+10

1982.000

 

.63661E+07

 

.39328E+08

 

.53100E+09

 

.22700E+09

 

.51832E+08

 

.13900E+10

1982.250

 

.60620E+07

 

.37189E+08

 

.53700E+09

 

.20900E+09

 

.51504E+08

 

.14300E+10

1982.500

 

.61937E+07

 

.38172E+08

 

.54400E+09

 

.19900E+09

 

.52574E+08

 

.14700E+10

1982.750

 

.61593E+07

 

.38005E+08

 

.55000E+09

 

.19500E+09

 

.52724E+08

 

.15100E+10

1983.000

 

.60292E+07

 

.37139E+08

 

.55600E+09

 

.18900E+09

 

.51995E+08

 

.15400E+10

1983.250

 

.59815E+07

 

.36917E+08

 

.56200E+09

 

.17800E+09

 

.51002E+08

 

.15800E+10

1983.500

 

.60387E+07

 

.37565E+08

 

.56800E+09

 

.17200E+09

 

.50687E+08

 

.16200E+10

1983.750

 

.60323E+07

 

.37777E+08

 

.57400E+09

 

.17100E+09

 

.50519E+08

 

.16500E+10

1984.000

 

.59558E+07

 

.37465E+08

 

.58000E+09

 

.16700E+09

 

.49674E+08

 

.16900E+10

1984.250

 

.61069E+07

 

.39083E+08

 

.58600E+09

 

.16800E+09

 

.49930E+08

 

.17300E+10

1984.500

 

.64138E+07

 

.42142E+08

 

.59200E+09

 

.17600E+09

 

.51186E+08

 

.17700E+10

1984.750

 

.65075E+07

 

.43542E+08

 

.59900E+09

 

.17800E+09

 

.51561E+08

 

.18200E+10

1985.000

 

.65509E+07

 

.44594E+08

 

.60500E+09

 

.17900E+09

 

.51684E+08

 

.18600E+10

1985.250

 

.64666E+07

 

.44574E+08

 

.61200E+09

 

.17500E+09

 

.51054E+08

 

.19100E+10

1985.500

 

.64239E+07

 

.44946E+08

 

.61800E+09

 

.17200E+09

 

.50593E+08

 

.19500E+10

1985.750

 

.65251E+07

 

.46681E+08

 

.62500E+09

 

.17000E+09

 

.50662E+08

 

.20000E+10

1986.000

 

.65514E+07

 

.47804E+08

 

.63100E+09

 

.16700E+09

 

.50515E+08

 

.20500E+10

1986.250

 

.63280E+07

 

.46608E+08

 

.63800E+69

 

.12900E+09

 

.45748E+08

 

.20900E+10

1986.500

 

.54945E+07

 

.39492E+08

 

.64300E+09

 

.66721E+08

 

.35185E+08

 

.21300E+10

1986.750

 

.50863E+07

 

.36294E+08

 

.64800E+09

 

.54695E+08

 

.32202E+08

 

.21700E+10

1987.000

 

.51088E+07

 

.37235E+08

 

.65300E+09

 

.59551E+08

 

.33227E+08

 

.22100E+10

1987.250

 

.50250E+07

 

.37117E+08

 

.65800E+09

 

.71958E+08

 

.35109E+08

 

.22400E+10

1987.500

 

.50665E+07

 

.38277E+08

 

.66300E+09

 

.81148E+08

 

.35249E+08

 

.22800E+10

1987.750

 

.49585E+07

 

.38385E+08

 

.66800E+09

 

.85434E+08

 

.35903E+08

 

.23200E+10

1988.000

 

.48908E+07

 

.38453E+08

 

.67300E+09

 

.72628E+08

 

.34043E+08

 

.23600E+10

1988.250

 

.48255E+07

 

.38518E+08

 

.67800E+09

 

.58180E+08

 

.31742E+08

 

.24000E+10

1988.500

 

.47462E+07

 

.38598E+08

 

.68300E+09

 

.61606E+08

 

.32326E+08

 

.24300E+10

1988.750

 

.46618E+07

 

.38682E+08

 

.68800E+09

 

.55398E+08

 

.31312E+08

 

.24700E+10

1989.000

 

.46006E+07

 

.38743E+08

 

.69200E+09

 

.47831E+08

 

.29914E+08

 

.25100E+10

1989.250

 

.45697E+07

 

.38774E+08

 

.69700E+09

 

.58294E+08

 

.31704E+08

 

.25500E+10

1989.500

 

.44844E+07

 

.38857E+08

 

.70100E+09

 

.70153E+08

 

.33644E+08

 

.25900E+10

1989.750

 

.44251E+07

 

.38919E+08

 

.70600E+09

 

.62557E+08

 

.32425E+08

 

.26300E+10

1990.000

 

.43820E+07

 

.38962E+08

 

.71000E+09

 

.65730E+08

 

.32905E+08

 

.26700E+10

1990.250

 

.43420E+07

 

.39002E+08

 

.71400E+09

 

.65129E+08

 

.32772E+08

 

.27100E+10

1990.500

 

.43023E+07

 

.39041E+08

 

.71900E+09

 

.64535E+08

 

.32646E+08

 

.27500E+10

1990.750

 

.42442E+07

 

.39019E+08

 

.72286E+09

 

.53265E+08

 

.30137E+08

 

.27846E+10

1991.000

 

.42300E+07

 

.39406E+08

 

.72709E+09

 

.53086E+08

 

.30191E+08

 

.28240E+10

1991.250

 

.42123E+07

 

.39794E+08

 

.73131E+09

 

.52865E+08

 

.30248E+08

 

.28638E+10

1991.500

 

.42324E+07

 

.40598E+08

 

.73554E+09

 

.53117E+08

 

.30511E+08

 

.29044E+10

1991.750

 

.41664E+07

 

.40576E+08

 

.73971E+09

 

.52289E+08

 

.30372E+08

 

.29450E+10

1992.000

 

.41794E+07

 

.41386E+08

 

.74388E+09

 

.52452E+08

 

.30642E+08

 

.29864E+10

1992.250

 

.41104E+07

 

.41366E+08

 

.74800E+09

 

.51585E+08

 

.29041E+08

 

.30277E+10

1992.500

 

.40792E+07

 

.41765E+08

 

.75207E+09

 

.51194E+08

 

.29294E+08

 

.30695E+10

 

1


 

1992.750

 

.40454E+07

 

.42170E+08

 

.75612E+09

 

.50770E+08

 

.29554E+08

 

.31117E+10

1993.000

 

.40098E+07

 

.42575E+08

 

.76013E+09

 

.50323E+08

 

.29821E+08

 

.31543E+10

1993.250

 

.39427E+07

 

.42618E+08

 

.76407E+09

 

.49481E+08

 

.29926E+08

 

.31969E+10

1993.500

 

.38590E+07

 

.42436E+08

 

.76793E+09

 

.48430E+08

 

.29934E+08

 

.32393E+10

1993.750

 

.37773E+07

 

.42248E+08

 

.77171E+09

 

.47405E+08

 

.29944E+08

 

.32816E+10

1994.000

 

.36973E+07

 

.42052E+08

 

.77541E+09

 

.46401E+08

 

.29930E+08

 

.33236E+10

1994.250

 

.36185E+07

 

.41845E+08

 

.77902E+09

 

.45413E+08

 

.29900E+08

 

.33655E+10

1994.500

 

.35411E+07

 

.41626E+08

 

.78257E+09

 

.44440E+08

 

.29687E+08

 

.34071E+10

1994.750

 

.34649E+07

 

.41395E+08

 

.78603E+09

 

.43484E+08

 

.29475E+08

 

.34485E+10

1995.000

 

.33901E+07

 

.41152E+08

 

.78942E+09

 

.42546E+08

 

.29262E+08

 

.34896E+10

1995.250

 

.33167E+07

 

.40898E+08

 

.79274E+09

 

.41625E+08

 

.29049E+08

 

.35305E+10

1995.500

 

.32447E+07

 

.40632E+08

 

.79598E+09

 

.40721E+08

 

.28836E+08

 

.35712E+10

1995.750

 

.31742E+07

 

.40355E+08

 

.79916E+09

 

.39836E+08

 

.28622E+08

 

.36115E+10

1996.000

 

.31051E+07

 

.40067E+08

 

.80226E+09

 

.38969E+08

 

.28407E+08

 

.36516E+10

1996.250

 

.30375E+07

 

.39767E+08

 

.80530E+09

 

.38121E+08

 

.28193E+08

 

.36913E+10

1996.500

 

.29714E+0/

 

.39458E+08

 

.43827E+09

 

.37291E+08

 

.27977E+08

 

.37308E+10

1996.750

 

.29067E+07

 

.39138E+08

 

.81118E+09

 

.36479E+08

 

.27761E+08

 

.37699E+10

1997.000

 

.28435E+07

 

.38808E+08

 

.81402E+09

 

.35687E+08

 

.27544E+08

 

.38088E+10

1997.250

 

.27818E+07

 

.38470E+08

 

.81680E+09

 

.34912E+08

 

.27327E+08

 

.38472E+10

1997.500

 

.27215E+07

 

.38122E+08

 

.81952E+09

 

.34155E+08

 

.27110E+08

 

.38853E+10

1997.750

 

.26627E+07

 

.37766E+08

 

.82219E+09

 

.33416E+08

 

.26892E+08

 

.39231E+10

1998.000

 

.26052E+07

 

.37403E+08

 

.82479E+09

 

.32696E+08

 

.26675E+08

 

.39605E+10

1998.250

 

.25492E+07

 

.37033E+08

 

.82734E+09

 

.31992E+08

 

.26457E+08

 

.39975E+10

1998.500

 

.24945E+07

 

.36656E+08

 

.82984E+09

 

.31307E+08

 

.26239E+08

 

.40342E+10

1998.750

 

.24413E+07

 

.36273E+08

 

.83228E+09

 

.30638E+08-

 

.26022E+08

 

.40705E+10

1999.000

 

.23893E+07

 

.35885E+08

 

.83467E+09

 

.29986E+08

 

.25805E+08

 

.41064E+10

1999.250

 

.23385E+07

 

.35491E+08

 

.83700E+09

 

.29348E+08

 

.25567E+08

 

.41418E+10

1999.500

 

.22888E+07

 

.35092E+08

 

.83929E+09

 

.28724E+08

 

.25327E+08

 

.41769E+10

1999.750

 

.22401E+07

 

.34689E+08

 

.84153E+09

 

.28113E+08

 

.25088E+08

 

.42116E+10

2000.000

 

.21865E+07

 

.34262E+08

 

.84372E+09

 

.27440E+08

 

.24183E+08

 

.42459E+10

2000.250

 

.21344E+07

 

.33831E+08

 

.84585E+09

 

.26787E+08

 

.23949E+08

 

.42797E+10

2000.500

 

.20839E+07

 

.33395E+08

 

.84794E+09

 

.26152E+08

 

.23715E+08

 

.43131E+10

2000.750

 

.20348E+07

 

.32957E+08

 

.84997E+09

 

.25536E+08

 

.23482E+08

 

.43461E+10

2001.000

 

.19871E+07

 

.32516E+08

 

.85196E+09

 

.24938E+08

 

.23250E+08

 

.43786E+10

2001.250

 

.19408E+07

 

.32073E+08

 

.85390E+09

 

.24357E+08

 

.23013E+08

 

.44107E+10

2001.500

 

.18956E+07

 

.31629E+08

 

.85580E+09

 

.23790E+08

 

.22770E+08

 

.44423E+10

2001.750

 

.18290E+07

 

.31122E+08

 

.85763E+09

 

.22954E+08

 

.20804E+08

 

.44734E+10

2002.000

 

.17650E+07

 

.30611E+08

 

.85939E+09

 

.22151E+08

 

.20546E+08

 

.45040E+10

2002.250

 

.17036E+07

 

.30096E+08

 

.86109E+09

 

.21380E+08

 

.20287E+08

 

.45341E+10

2002.500

 

.16447E+07

 

.29577E+08

 

.86274E+09

 

.20640E+08

 

.20029E+08

 

.45637E+10

2002.750

 

.15880E+07

 

.29055E+08

 

.86433E+09

 

.19930E+08

 

.19772E+08

 

.45928E+10

2003.000

 

.15336E+07

 

.28531E+08

 

.86586E+09

 

.19247E+08

 

.19514E+08

 

.46213E+10

2003.250

 

.14813E+07

 

.28005E+08

 

.85734E+09

 

.18591E+08

 

.19258E+08

 

.46493E+10

2003.500

 

.14311E+07

 

.27478E+08

 

.86877E+09

 

.17960E+08

 

.19003E+08

 

.46768E+10

2003.750

 

.13829E+07

 

.26951E+08

 

.87016E+09

 

.17355E+08

 

.18749E+08

 

.47037E+10

2004.000

 

.13364E+07

 

.26424E+08

 

.87149E+09

 

.16772E+08

 

.18496E+08

 

.47301E+10

2004.250

 

.12918E+07

 

.25898E+08

 

.87278E+09

 

.16212E+08

 

.18245E+08

 

.47560E+10

2004.500

 

.12489E+07

 

.25374E+08

 

.87403E+09

 

.15674E+08

 

.17996E+08

 

.47814E+10

2004.750

 

.12077E+07

 

.24852E+08

 

.87524E+09

 

.15156E+08

 

.17749E+08

 

.48063E+10

2005.000

 

.11680E+07

 

.24333E+08

 

.87641E+09

 

.14658E+08

 

.17505E+08

 

.48306E+10

2005.250

 

.11298E+07

 

.23817E+08

 

.87754E+09

 

.14179E+08

 

.17262E+08

 

.48544E+10

2005.500

 

.10930E+07

 

.23305E+08

 

.87863E+09

 

.13717E+08

 

.17023E+08

 

.48777E+10

2005.750

 

.10576E+07

 

.22798E+08

 

.87969E+09

 

.13273E+08

 

.16786E+08

 

.49005E+10

2006.000

 

.10235E+07

 

.22296E+08

 

.88071E+09

 

.12844E+08

 

.16552E+08

 

.49228E+10

2006.250

 

.99057E+06

 

.21798E · 08

 

.88170E+09

 

.12432E+08

 

.16321E+08

 

.49446E+10

2006.500

 

.95890E+06

 

.21306E+08

 

.88266E+09

 

.12034E+08

 

.16094E+08

 

.49659E+10

 

2



 

2006.750

 

.92835E+06

 

.20820E+08

 

.88359E+09

 

.11651E+08

 

.15869E+08

 

.49867E+10

2007.000

 

.89890E+06

 

.20341E+08

 

.88449E+09

 

.11281E+08

 

.15648E+08

 

.50071E+10

2007.250

 

.87051E+06

 

.19868E+08

 

.88536E+09

 

.10925E+08

 

.15431E+08

 

.50270E+10

2007.500

 

.84310E+06

 

.19401E+08

 

.88620E+09

 

.10581E+08

 

.15217E+08

 

.50464E+10

2007.750

 

.81669E+06

 

.18942E+08

 

.88702E+09

 

.10249E+08

 

.15006E+08

 

.50653E+10

2008.000

 

.79115E+06

 

.18490E+08

 

.88781E+09

 

.99290E+07

 

.14800E+08

 

.50838E+10

2008.250

 

.76654E+06

 

.18045E+08

 

.88858E+09

 

.96200E+07

 

.14597E+08

 

.51018E+10

2008.500

 

.74277E+06

 

.17608E+08

 

.88932E+09

 

.93217E+07

 

.14397E+08

 

.51194E+10

2008.750

 

.71981E+06

 

.17178E+08

 

.89004E+09

 

.90336E+07

 

.14202E+08

 

.51366E+10

2009.000

 

.69764E+06

 

.16757E+08

 

.89074E+09

 

.87554E+07

 

.14010E+08

 

.51534E+10

2009.250

 

.67622E+06

 

.16343E+08

 

.89141E+09

 

.84865E+07

 

.13822E+08

 

.51697E+10

2009.500

 

.65553E+06

 

.15937E+08

 

.89207E+09

 

.82269E+07

 

.13638E+08

 

.51857E+10

2009.750

 

.63555E+06

 

.15538E+08

 

.89270E+09

 

.79761E+07

 

.13458E+08

 

.52012E+10

2010.000

 

.61622E+06

 

.15148E+08

 

.89332E+09

 

.77336E+07

 

.13281E+08

 

.52163E+10

2010.250

 

.59754E+06

 

.14766E+08

 

.89392E+09

 

.74991E+07

 

.13108E+08

 

.52311E+10

2010.500

 

.57949E+06

 

.14392E+08

 

.89450E+09

 

.72726E+07

 

.12952E+08

 

.52455E+10

2010.750

 

.56202E+06

 

.14025E+08

 

.89506E+09

 

.70534E+07

 

.12837E+08

 

.52595E+10

2011.000

 

.54512E+06

 

.13667E+08

 

.89560E+09

 

.68413E+07

 

.12726E+08

 

.52732E+10

2011.250

 

.52879E+06

 

.13317E+08

 

.89613E+09

 

.66363E+07

 

.12617E+08

 

.52865E+10

2011.500

 

.51299E+06

 

.12974E+08

 

.89665E+09

 

.64381E+07

 

.12510E+08

 

.52995E+10

2011.750

 

.49772E+06

 

.12639E+08

 

.89714E+09

 

.62464E+07

 

.12306E+08

 

.53121E+10

2012.000

 

.48292E+06

 

.12311E+08

 

.89763E+09

 

.60607E+07

 

.12304E+08

 

.53244E+10

2012.250

 

.46862E+06

 

.11992E+08

 

.89810E+09

 

.58812E+07

 

.12205E+08

 

.53364E+10

2012.500

 

.45477E+081

 

.11679E+08

 

.89855E+09

 

.57819E+07

 

.12108E+08

 

.53481E+10

2012.750

 

.44136E+06

 

.11375E+08

 

.89899E+09

 

.55390E+07

 

.12014E+08

 

.53595E+10

2013.000

 

.42839E+06

 

.11077E+08

 

.89942E+09

 

.53763E+07

 

.11922E+08

 

.53706E+10

2013.250

 

.41583E+06

 

.10787E+08

 

.89984E+09

 

.52186E+07

 

.11832E+08

 

.53813E+10

2013.500

 

.40366E+06

 

.10503E+08

 

.90024E+09

 

.50659E+07

 

.11744E+08

 

.53918E+10

2013.750

 

.39186E+06

 

.10227E+08

 

.90063E+09

 

.49179E+07

 

.11659E+08

 

.54021E+10

2014.000

 

.38045E+06

 

.99574E+07

 

.90101E+09

 

.47747E+07

 

.11576E+08

 

.54120E+10

2014.250

 

.36940E+06

 

.96945E+07

 

.90138E+09

 

.46359E+07

 

.11495E+08

 

.54217E+10

2014.500

 

.35869E+06

 

.94383E+07

 

.90174E+09

 

.45016E+07

 

.11415E+08

 

.54312E+10

2014.750

 

.34834E+06

 

.91886E+07

 

.90209E+09

 

.43717E+07

 

.11338E+08

 

.54403E+10

2015.000

 

.33827E+06

 

.89453E+07

 

.90243E+09

 

.42453E+07

 

.11263E+08

 

.54493E+10

2015.250

 

.32855E+06

 

.87082E+07

 

.90276E+09

 

.41233E+07

 

.11190E+08

 

.54580E+10

2015.500

 

.31910E+06

 

.84771E+07

 

.90307E+09

 

.40047E+07

 

.11119E+08

 

.54665E+10

2015.750

 

.30997E+06

 

.82520E+07

 

.90338E+09

 

.38901E+07

 

.11050E+08

 

.54747E+10

2016.000

 

.30110E+06

 

.80327E+07

 

.90369E+09

 

.37788E+07

 

.10982E+08

 

.54828E+10

2016.250

 

.29250E+06

 

.78193E+07

 

.90398E+09

 

.36708E+07

 

.10917E+08

 

.54906E+10

2016.500

 

.28416E+06

 

.76114E+07

 

.90426E+09

 

.35663E+07

 

.10853E+08

 

.54982E+10

2016.750

 

.27610E+06

 

.74089E+07

 

.90454E+09

 

.34650E+07

 

.10791E+08

 

.55056E+10

2017.000

 

.26827E+06

 

.72119E+07

 

.90481E+09

 

.33668E+07

 

.10730E+08

 

.55128E+10

2017.250

 

.26067E+06

 

.70200E+07

 

.90507E+09

 

.32714E+07

 

.10671E+08

 

.55198E+10

2017.500

 

.25331E+06

 

.68332E+07

 

.90532E+09

 

.31790E+07

 

.10614E+08

 

.55267E+10

2017.750

 

.24618E+06

 

.66514E+07

 

.90557E+09

 

.30896E+07

 

.10558E+08

 

.55333E+10

2018.000

 

.23926E+06

 

.64745E+07

 

.90581E+09

 

.30027E+07

 

.10504E+08

 

.55398E+10

2018.250

 

.23253E+06

 

.63023E+07

 

.90604E+09

 

.29183E+07

 

.10451E+08

 

.55461E+10

2018.500

 

.22601E+06

 

.61347E+07

 

.90626E+09

 

.28364E+07

 

.10399E+08

 

.55522E+10

2018.750

 

.21969E+06

 

.59717E+07

 

.90648E+09

 

.27572E+07

 

.10349E+08

 

.55582E+10

2019.000

 

.21356E+06

 

.58130E+07

 

.90670E+09

 

.26802E+07

 

.10301E+08

 

.55640E+10

2019.250

 

.20762E+06

 

.56586E+07

 

.90690E+09

 

.26056E+07

 

.10253E+08

 

.55697E+10

2019.500

 

.20184E+06

 

.55085E+07

 

.90711E+09

 

.25330E+07

 

.10207E+08

 

.55752E+10

2019.750

 

.19623E+06

 

.53623E+07

 

.90730E+09

 

.24627E+07

 

.10162E+08

 

.55805E+10

2020.000

 

.19079E+06

 

.52202E+07

 

.90749E+09

 

.23944E+07

 

.10119E+08

 

.55858E+10

 

3



 

FOR BASE GROUP

 

TIME

 

OIL

 

WATER

 

CUM

 

ORATE

 

WOR

 

GF

1980.750

 

.56067E+07

 

.35288E+08

 

.50100E+09

 

.61443E+05

 

.62940E+01

 

.44817E+06

1981.000

 

.57070E+07

 

.36783E+08

 

.50700E+09

 

.62543E+05

 

.64451E+01

 

.46564E+06

1981.250

 

.50164E+07

 

.33066E+08

 

.51200E+09

 

.54974E+05

 

.65917E+01

 

.41734E+06

1981.500

 

.51793E+07

 

.34878E+08

 

.51700E+09

 

.56759E+05

 

.67341E+01

 

.43898E+06

1981.750

 

.53016E+07

 

.36495E+08

 

.52200E+09

 

.58099E+05

 

.68837E+01

 

.45804E+06

1982.000

 

.53120E+07

 

.37389E+08

 

.52800E+09

 

.58214E+05

 

.70386E+01

 

.46796E+06

1982.250

 

.48384E+07

 

.34788E+08

 

.53300E+09

 

.53023E+05

 

.71900E+01

 

.43426E+06

1982.500

 

.48080E+07

 

.35276E+08

 

.53700E+09

 

.52691E+05

 

.73370E+01

 

.43928E+06

1982.750

 

.46224E+07

 

.34592E+08

 

.54200E+09

 

.50657E+05

 

.74835E+01

 

.42974E+06

1983.000

 

.43526E+07

 

.33191E+08

 

.54600E+09

 

.47699E+05

 

.76256E+01

 

.41144E+06

1983.250

 

.41760E+07

 

.32419E+08

 

.55000E+09

 

.45764E+05

 

.77632E+01

 

.40104E+06

1983.500

 

.41145E+07

 

.32501E+08

 

.55500E+09

 

.45090E+05

 

.78993E+01

 

.40127E+06

1983.750

 

.37997E+07

 

.32137E+08

 

.55900E+09

 

.43833E+05

 

.80348E+01

 

.39602E+06

1984.000

 

.38249E+07

 

.31241E+08

 

.56200E+09

 

.41916E+05

 

.81677E+01

 

.18428E+06

1984.250

 

.38872E+07

 

.32267E+08

 

.56600E+09

 

.42599E+05

 

.83009E+01

 

.39621E+06

1984.500

 

.41143E+07

 

.34730E+08

 

.57000E+09

 

.45088E+05

 

.84413E+01

 

.42569E+06

1984.750

 

.41368E+07

 

.35530E+08

 

.57500E+09

 

.45335E+05

 

.85887E+01

 

.43470E+06

1985.000

 

.41174E+07

 

.35980E+08

 

.57900E+09

 

.45122E+05

 

.87386E+01

 

.43942E+06

1985.250

 

.39780E+07

 

.35357E+08

 

.58300E+09

 

.43594E+05

 

.88882E+01

 

.43107E+06

1985.500

 

.38876E+07

 

.35128E+08

 

.58700E+09

 

.42603E+05

 

.90360E+01

 

.42757E+06

1985.750

 

.39480E+07

 

.36265E+08

 

.59000E+09

 

.43266E+05

 

.91857E+01

 

.44070E+06

1986.000

 

.39401E+07

 

.36796E+08

 

.59400E+09

 

.43179E+05

 

.93389E+01

 

.44642E+06

1986.250

 

.36909E+07

 

.35025E+08

 

.59800E+09

 

.40448E+05

 

.94895E+01

 

.42428E+06

1986.500

 

.28460E+07

 

.27380E+08

 

.60100E+09

 

.31189E+05

 

.96205E+01

 

.33124E+06

1986.750

 

.24336E+07

 

.23673E+08

 

.60300E+09

 

.26670E+05

 

.97275E+01

 

.28610E+06

1987.000

 

.24525E+07

 

.24103E+08

 

.60600E+09

 

.26877E+05

 

.98277E+01

 

.29101E+06

1987.250

 

.23634E+07

 

.23463E+08

 

.60800E+09

 

.25900E+05

 

.99274E+01

 

.28302E+06

1987.500

 

.24223E+07

 

.24290E+08

 

.61100E+09

 

.26546E+05

 

.10028E+02

 

.29274E+06

1987.750

 

.25685E+07

 

.26027E+08

 

.61300E+09

 

.28148E+05

 

.10133E+02

 

.31337E+06

1988.000

 

.25238E+07

 

.25848E+08

 

.61600E+09

 

.27658E+05

 

.10242E+02

 

.31093E+06

1988.250

 

.24733E+07

 

.25598E+08

 

.61800E+09

 

.27104E+05

 

.10350E+02

 

.30763E+06

1988.500

 

.24829E+07

 

.25966E+08

 

.62100E+09

 

.27210E+05

 

.10458E+02

 

.31177E+06

1988.750

 

.25223E+07

 

.26656E+08

 

.62300E+09

 

.27641E+05

 

.10568E+02

 

.31976E+06

1989.000

 

.24807E+07

 

.26493E+08

 

.62600E+09

 

.27186E+05

 

.10680E+02

 

.31752E+06

1989.250

 

.23380E+07

 

.25222E+08

 

.62800E+09

 

.25622E+05

 

.10788E+02

 

.30203E+06

1989.500

 

.24116E+07

 

.26277E+08

 

.63000E+09

 

.26428E+05

 

.10896E+02

 

.31439E+06

1989.750

 

.24086E+07

 

.26511E+08

 

.63300E+09

 

.26396E+05

 

.11007E+02

 

.31693E+06

1990.000

 

.23399E+07

 

.26012E+08

 

.63500E+09

 

.25642E+05

 

.11117E+02

 

.31071E+06

1990.250

 

.22613E+07

 

.25382E+08

 

.63700E+09

 

.24781E+05

 

.11225E+02

 

.30294E+06

1990.500

 

.21859E+07

 

.24766E+08

 

.64000E+09

 

.23955E+05

 

.11330E+02

 

.29536E+06

1990.750

 

.41811E+07

 

.38874E+08

 

.72280E+09

 

.45820E+05

 

.92975E+01

 

.47184E+06

1991.000

 

.41083E+07

 

.39108E+08

 

.72691E · 09

 

.45023E+05

 

.95192E+01

 

.47361E+06

1991.250

 

.40364E+07

 

.39335E+08

 

.73095E+09

 

.44235E+05

 

.97452E+01

 

.47531E+06

1991.500

 

.40062E+07

 

.39972E+08

 

.73495E+09

 

.43904E+05

 

.99775E+01

 

.48195E+06

1991.750

 

.38937E+07

 

.39774E+08

 

.73885E+09

 

.42671E+05

 

.10215E+02

 

.47855E+06

1992.000

 

.38636E+07

 

.40402E+08

 

.74271E+09

 

.42341E+05

 

.10457E+02

 

.48510E+06

1992.250

 

.37545E+07

 

.40193E+08

 

.74646E+09

 

.41145E+05

 

.10705E+02

 

.48161E+06

1992.500

 

.36864E+07

 

.40396E+08

 

.75015E+09

 

.40399E+05

 

.10958E+02

 

.48309E+06

1992.750

 

.36187E+07

 

.40599E+08

 

.75377E+09

 

.39656E+05

 

.11219E+02

 

.48458E+06

1993.000

 

.35517E+07

 

.40797E+08

 

.75732E+09

 

.38923E+05

 

.11487E+02

 

.48602E+06

1993.250

 

.34559E+07

 

.40630E+08

 

.76078E+09

 

.37872E+05

 

.11757E+02

 

.48313E+06

1993.500

 

.33457E+07

 

.40234E+08

 

.76412E+09

 

.36665E+05

 

.12025E+02

 

.47758E+06

1993.750

 

.32398E+07

 

.39828E+08

 

.76736E+09

 

.35505E+05

 

.12293E+02

 

.47198E+06

 

4



 

1994.000

 

.31379E+07

 

.39413E+08

 

.77050E+09

 

.34387E+05

 

.12560E+02

 

.46631E+06

1994.250

 

.30394E+07

 

.38985E+08

 

.77354E+09

 

.33308E+05

 

.12827E+02

 

.46054E+06

1994.500

 

.29442E+07

 

.38545E+08

 

.77648E+09

 

.32265E+05

 

.13092E+02

 

.45468E+06

1994.750

 

.28522E+07

 

.38094E+08

 

.77934E+09

 

.31257E+05

 

.13356E+02

 

.44872E+06

1995.000

 

.27633E+07

 

.37631E+08

 

.78210E+09

 

.30283E+05

 

.13618E+02

 

.44268E+06

1995.250

 

.26774E+07

 

.37159E+08

 

.78478E+09

 

.29341E+05

 

.13879E+02

 

.43656E+06

1995.500

 

.25942E+07

 

.36676E+08

 

.78737E+09

 

.28430E+05

 

.14137E+02

 

.43036E+06

1995.750

 

.25139E+07

 

.36184E+08

 

.78988E+09

 

.27549E+05

 

.14394E+02

 

.42408E+06

1996.000

 

.24361E+07

 

.35683E+08

 

.79232E+09

 

.26697E+05

 

.14647E+02

 

.41774E+06

1996.250

 

.23610E+07

 

.35174E+08

 

.79468E+09

 

.25874E+05

 

.14898E+02

 

.41134E+06

1996.500

 

.22882E+07

 

.34658E+08

 

.79697E+09

 

.25077E+05

 

.15146E+02

 

.40489E+06

1996.750

 

.22179E+07

 

.34135E+08

 

.79919E+09

 

.24306E+05

 

.15391E+02

 

.39839E+06

1997.000

 

.21499E+07

 

.33606E+08

 

.80134E+09

 

.23560E+05

 

.15632E+02

 

.39184E+06

1997.250

 

.20840E+07

 

.33072E+08

 

.80342E+09

 

.22838E+05

 

.15870E+02

 

.38527E+06

1997.500

 

.20202E+07

 

.32533E+08

 

.80544E+09

 

.22140E+05

 

.16104E+02

 

.37867E+06

1997.750

 

.19586E+07

 

.31991E+08

 

.80740E+09

 

.21464E+05

 

.16334E+02

 

.37205E+06

1998.000

 

.18989E+07

 

.31446E+08

 

.80930E+09

 

.20810E+05

 

.16560E+02

 

.36542E+06

1998.250

 

.18411E+07

 

.30898E+08

 

.81114E+09

 

.20177E+05

 

.16782E+02

 

.35878E+06

1998.500

 

.17852E+07

 

.30348E+08

 

.81293E+09

 

.19564E+05

 

.17000E+02

 

.35215E+06

1998.750

 

.17310E+07

 

.29798E+08

 

.81466E+09

 

.18970E+05

 

.17214E+02

 

.34552E+06

1999.000

 

.16786E+07

 

.29246E+08

 

.81634E+09

 

.18396E+05

 

.17423E+02

 

.31891E+06

1999.250

 

.16279E+07

 

.28696E+08

 

.81796E+09

 

.17840E+05

 

.17628E+02

 

.33231E+06

1999.500

 

.15787E+07

 

.28145E+08

 

.81954E+09

 

.17301E+05

 

.17828E+02

 

.32574E+06

1999.750

 

.15311E+07

 

.27597E+08

 

.82107E+09

 

.16779E+05

 

.18024E+02

 

.31921E+06

2000.000

 

.14850E+07

 

.27050E+08

 

.82256E+09

 

.16274E+05

 

.18215E+02

 

.31271E+06

2000.250

 

.14404E+07

 

.26505E+08

 

.82400E+09

 

.15785E+05

 

.18402E+02

 

.30625E+06

2000.500

 

.13971E+07

 

.25964E+08

 

.82540E+09

 

.15311E+05

 

.18584E+02

 

.29984E+06

2000.750

 

.13552E+07

 

.25425E+08

 

.82675E+09

 

.14852E+05

 

.18761E+02

 

.29349E+06

2001,000

 

.13147E+07

 

.24891E+08

 

.82807E+09

 

.14407E+05

 

.18934E+02

 

.28719E+06

2001.250

 

.12753E+07

 

.24361E+08

 

.82934E+09

 

.13976E+05

 

.19102E+02

 

.28095E+06

2001.500

 

.12373E+07

 

.23836E+08

 

.83058E+09

 

.13559E+05

 

.19265E+02

 

.27477E+06

2001.750

 

.12004E+07

 

.23316E+08

 

.83178E+09

 

.13155E+05

 

.19424E+02

 

.26867E+06

2002.000

 

.11646E+07

 

.22801E+08

 

.83294E+09

 

.12763E+05

 

.19578E+02

 

.26263E+06

2002.250

 

.11299E+07

 

.22291E+08

 

.83407E+09

 

.12383E+05

 

.19728E+02

 

.25667E+06

2002.500

 

.10964E+07

 

.21788E+08

 

.83517E+09

 

.12015E+05

 

.19873E+02

 

.25079E+06

2002.750

 

.10638E+07

 

.21291E+08

 

.83623E+09

 

.11658E+05

 

.20013E+02

 

.24499E+06

2003.000

 

.10323E+07

 

.20801E+08

 

.83727E+09

 

.11313E+05

 

.20150E+02

 

.23927E+06

2003.250

 

.10017E+07

 

.20317E+08

 

.83827E+09

 

.10978E+05

 

.20282E+02

 

.23363E+06

2003.500

 

.97209E+06

 

.19840E+08

 

.83924E+09

 

.10653E+05

 

.20409E+02

 

.22808E+06

2003.750

 

.94339E+06

 

.19370E+08

 

.84018E+09

 

.10339E+05

 

.20533E+02

 

.22261E+06

2004.000

 

.91554E+06

 

.18908E+08

 

.84110E+09

 

.10033E+05

 

.20652E+02

 

.21724E+06

2004.250

 

.88855E+06

 

.18452E+08

 

.84199E+09

 

.97375E+04

 

.20767E+02

 

.21196E+06

2004.500

 

.86239E+06

 

.18005E+08

 

.84285E+09

 

.94508E+04

 

.20878E+02

 

.20676E+06

2004.750

 

.83701E+06

 

.17565E+08

 

.84369E+09

 

.91727E+04

 

.20985E+02

 

.20166E+06

2005.000

 

.81243E+06

 

.17132E+08

 

.84450E+09

 

.89034E+04

 

.21088E+02

 

.19665E+06

2005.250

 

.78857E+06

 

.16708E+08

 

.84529E+09

 

.86419E+04

 

.21187E+02

 

.19174E+06

2005.500

 

 

 

 

 

.84605E+09

 

.83885E+04

 

.21282E+02

 

.18692E+06

2005.750

 

.74304E+06

 

 

 

.84680E+09

 

.81429E+04

 

.21374E+02

 

.18219E+06

2006.000

 

.72129E+06

 

.35480E+08

 

.84752E+09

 

.79046E+04

 

.21462E+02

 

.17755E+86

2006.250

 

.70020E+06

 

.15087E+08

 

.84822E+09

 

.76735E+04

 

.21547E+02

 

.17301E+06

2006.500

 

.67976E+06

 

.14701E+08

 

.84890E+09

 

.74494E+04

 

.21627E+02

 

.16856E+06

2006.750

 

.65992E+06

 

.14324E+08

 

.84956E+09

 

.72320E+04

 

.21705E+02

 

.16420E+06

2007.000

 

.64069E+06

 

.13954E+08

 

.85020E+09

 

.70212E+04

 

.21779E+02

 

.15994E+06

2007.250

 

.62204E+06

 

.13592E+08

 

.85082E+09

 

.68169E+04

 

.21850E+02

 

.15577E+06

2007.500

 

.60393E+06

 

.13237E+08

 

.85142E+09

 

.66184E+04

 

.21918E+02

 

.15168E+06

2007.750

 

.58640E+06

 

.12890E+08

 

.85201E+09

 

.64263E+04

 

.21982E+02

 

.14769E+06

 

5



 

2008.000

 

.56935E+06

 

.12551E+08

 

.85258E+09

 

.62394E+04

 

.22045E+02

 

.14379E+06

2008.250

 

.55284E+06

 

.12220E+08

 

.85313E+09

 

.60585E+04

 

.22104E+02

 

.13997E+06

2008.500

 

.53682E+06

 

.11896E+08

 

.85367E+09

 

.58830E+04

 

.22159E+02

 

.13625E+06

2008.750

 

.52127E+06

 

.11579E+08

 

.85419E+09

 

.57126E+04

 

.22212E+02

 

.13260E+06

2009.000

 

.50619E+06

 

.11269E+08

 

.85470E+09

 

.55473E+04

 

.22263E+02

 

.12905E+06

2009.250

 

.49155E+06

 

.10967E+08

 

.85519E+09

 

.53869E+04

 

.22311E+02

 

.12557E+06

2009.500

 

.47736E+06

 

.10672E+08

 

.85566E+09

 

.52313E+04

 

.22356E+02

 

.12218E+06

2009.750

 

.46360E+06

 

.10384E+08

 

.85613E+09

 

.50805E+04

 

.22398E+02

 

.11887E+06

2010.000

 

.45023E+06

 

.10102E+08

 

.85658E+09

 

.49340E+04

 

.22438E+02

 

.11565E+06

2010.250

 

.43726E+06

 

.98279E+07

 

.85702E+09

 

.47918E+04

 

.22476E+02

 

.11250E+06

2010.500

 

.42467E+06

 

.95601E+07

 

.85744E+09

 

.46540E+04

 

.22512E+02

 

.10942E+06

2010.750

 

.41246E+06

 

.92989E+07

 

.85785E+09

 

.45201E+04

 

.22545E+02

 

.10643E+06

2011.000

 

.40059E+06

 

.90443E+07

 

.85825E+09

 

.43901E+04

 

.22577E+02

 

.10351E+06

2011.250

 

.38909E+06

 

.87959E+07

 

.85864E+09

 

.42640E+04

 

.22606E+02

 

.10066E+06

2011.500

 

.37793E+06

 

.85538E+07

 

.85902E+09

 

.41417E+04

 

.22633E+02

 

.97882E+05

2011.750

 

.36710E+06

 

.83177E+07

 

.85939E+09

 

.40230E+04

 

.22658E+02

 

.95176E+05

2012.000

 

.35658E+06

 

.80877E+07

 

.85974E+09

 

.39077E+04

 

.22682E+02

 

.92541E+05

2012.250

 

.34638E+06

 

.78637E+07

 

.86009E+09

 

.37959E+04

 

.22703E+02

 

.89973E+05

2012.500

 

.33647E+06

 

.76453E+07

 

.86043E+09

 

.36873E+04

 

.22722E+02

 

.87471E+05

2012.750

 

.32685E+06

 

.74326E+07

 

.86075E+09

 

.35819E+04

 

.22740E+02

 

.85035E+05

2013.000

 

.31753E+06

 

.72255E+07

 

.86107E+09

 

.34798E+04

 

.22755E+02

 

.82663E+05

2013.250

 

.30847E+06

 

.70237E+07

 

.86138E+09

 

.33805E+04

 

.22769E+02

 

.80353E+05

2013.500

 

.29967E+06

 

.68273E+07

 

.86168E+09

 

.32841E+04

 

.22783E+02

 

.78104E+05

2013.750

 

.29112E+06

 

.66361E+07

 

.86197E+09

 

.31904E+04

 

.22795E+02

 

.75915E+05

2014.000

 

.28283E+06

 

.64500E+07

 

.86225E+09

 

.30995E+04

 

.22805E+02

 

.73784E+05

2014.250

 

.27479E+06

 

.62688E+07

 

.86253E+09

 

.30113E+04

 

.22813E+02

 

.71710E+05

2014.500

 

.26697E+06

 

.60924E+07

 

.86280E+09

 

.29257E+04

 

.22820E+02

 

.69692E+05

2014.750

 

.25941E+06

 

.59208E+07

 

.86305E+09

 

.28428E+04

 

.22824E+02

 

.67728E+05

2015.000

 

.25203E+06

 

.57538E+07

 

.86331E+09

 

.27620E+04

 

.22830E+02

 

.65818E+05

2015.250

 

.24489E+06

 

.55914E+07

 

.86355E+09

 

.26838E+04

 

.22832E+02

 

.63959E+05

2015.500

 

.23793E+06

 

.54333E+07

 

.86379E+09

 

.26075E+04

 

.22835E+02

 

.62151E+05

2015.750

 

.23121E+06

 

.52796E+07

 

.86402E+09

 

.25338E+04

 

.22834E+02

 

.60392E+05

2016.000

 

.22467E+06

 

.51300E+07

 

.86425E+09

 

.24621E+04

 

.22834E+02

 

.58681E+05

2016.250

 

.21830E+06

 

.49845E+07

 

.86446E+09

 

.23923E+04

 

.22833E+02

 

.57017E+05

2016.500

 

.21212E+06

 

.48431E+07

 

.86468E+09

 

.23246E+04

 

.22831E+02

 

.55400E+05

2016.750

 

.20614E+06

 

.47055E+07

 

.86488E+09

 

.22591E+04

 

.22827E+02

 

.53826E+05

2017.000

 

.20032E+06

 

.45718E+07

 

.86508E+09

 

.21953E+04

 

.22822E+02

 

.52297E+05

2017.250

 

.19466E+06

 

.44417E+07

 

.86528E+09

 

.21333E+04

 

.22817E+02

 

.50810E+05

2017.500

 

.18918E+06

 

.43153E+07

 

.86547E+09

 

.20732E+04

 

.22811E+02

 

.49364E+05

2017.750

 

.18386E+06

 

.41924E+07

 

.86565E+09

 

.20149E+04

 

.22801E+02

 

.47959E+05

2018.000

 

.17869E+06

 

.40729E+07

 

.86583E+09

 

.19582E+04

 

.22793E+02

 

.46592E+05

2018.250

 

.17365E+06

 

.39567E+07

 

.86600E+09

 

.19031E+04

 

.22785E+02

 

.45264E+05

2018.500

 

.16876E+06

 

.38438E+07

 

.86617E+09

 

.18495E+04

 

.22776E+02

 

.43973E+05

2018.750

 

.16403E+06

 

.37341E+07

 

.86634E+09

 

.17975E+04

 

.22765E+02

 

.42719E+05

2019.000

 

.15942E+06

 

.36273E+07

 

.86649E+09

 

.17471E+04

 

.22753E+02

 

.41499E+05

2019.250

 

.15495E+06

 

.35237E+07

 

.86665E+09

 

.16981E+04

 

.22741E+02

 

.40314E+05

2019.500

 

.15060E+06

 

.34230E+07

 

.86680E+09

 

.16504E+04

 

.22729E+02

 

.39163E+05

2019.750

 

.14637E+06

 

.33251E+07

 

.86695E+09

 

.16041E+04

 

.22717E+02

 

.38043E+05

2020.000

 

.14227E+06

 

.32299E+07

 

.86709E+09

 

.15591E+04

 

.22703E+02

 

.36956E+05

 

GROUP#

 

1 TIME=

 

1980.7500 PAYOUT=

 

0.468 WELLS=

 

7.000

 

 

GROUP#

 

2 TIME=

 

1981.0000 PAYOUT=

 

0.580 WELLS=

 

8.500

 

 

GROUP#

 

3 TIME=

 

1981.2500 PAYOUT=

 

0.718 WELLS=

 

10.000

 

 

GROUP#

 

4 TIME=

 

1981.5000 PAYOUT=

 

0.899 WELLS=

 

11.500

 

 

GROUP#

 

5 TIME=

 

1981.7500 PAYOUT=

 

1.135 WELLS=

 

13.000

 

 

GROUP#

 

6 TIME=

 

1982.0000 PAYOUT=

 

1.451 WELLS=

 

14.500

 

 

 

6



 

GROUP#

 

7 TIME=

 

1982.2500 PAYOUT=

 

1.861 WELLS=

 

16.000

 

 

GROUP#

 

8 TIME=

 

1982.5000 PAYOUT=

 

2.440 WELLS=

 

17.500

 

 

GROUP#

 

9 TIME=

 

1982.7500 PAYOUT=

 

2.746 WELLS=

 

18.000

 

 

GROUP#

 

10 TIME=

 

1983.0000 PAYOUT=

 

2.907 WELLS=

 

18.000

 

 

GROUP#

 

11 TIME=

 

1983.2500 PAYOUT=

 

3.150 WELLS=

 

18.000

 

 

GROUP#

 

12 TIME=

 

1983.5000 PAYOUT=

 

3.397 WELLS=

 

18.000

 

 

GROUP#

 

13 TIME=

 

1983.7500 PAYOUT=

 

3.500 WELLS=

 

17.814

 

 

GROUP#

 

14 TIME=

 

1984.0000 PAYOUT=

 

3.500 WELLS=

 

17.367

 

 

GROUP#

 

15 TIME=

 

1984.2500 PAYOUT=

 

3.500 WELLS=

 

16.929

 

 

GROUP#

 

16 TIME=

 

1984.5000 PAYOUT=

 

3.500 WELLS=

 

16.520

 

 

GROUP#

 

17 TIME=

 

1984.7500 PAYOUT=

 

3.500 WELLS=

 

16.148

 

 

GROUP#

 

18 TIME=

 

1985.0000 PAYOUT=

 

3.500 WELLS=

 

15.767

 

 

GROUP#

 

19 TIME=

 

1985.2500 PAYOUT=

 

3.500 WELLS=

 

15.365

 

 

GROUP#

 

20 TIME=

 

1985.5000 PAYOUT=

 

3.500 WELLS=

 

14.973

 

 

GROUP#

 

21 TIME=

 

1985.7500 PAYOUT=

 

3.500 WELLS=

 

14.510

 

 

GROUP#

 

22 TIME=

 

1986.0000 PAYOUT=

 

3.500 WELLS=

 

14.103

 

 

GROUP#

 

23 TIME=

 

1986.2500 PAYOUT=

 

3.500 WELLS=

 

12.764

 

 

GROUP#

 

24 TIME=

 

1986.5000 PAYOUT=

 

3.500 WELLS=

 

9.743

 

 

GROUP#

 

25 TIME=

 

1986.7500 PAYOUT=

 

3.500 WELLS=

 

8.838

 

 

GROUP#

 

26 TIME=

 

1987.0000 PAYOUT=

 

3.500 WELLS=

 

9.118

 

 

GROUP#

 

27 TIME=

 

1987.2500 PAYOUT=

 

3.500 WELLS=

 

10.072

 

 

GROUP#

 

28 TIME=

 

1987.5000 PAYOUT=

 

3.500 WELLS=

 

10.514

 

 

GROUP#

 

29 TIME=

 

1987.7500 PAYOUT=

 

3.500 WELLS=

 

10.689

 

 

GROUP#

 

30 TIME=

 

1988.0000 PAYOUT=

 

3.500 WELLS=

 

9.784

 

 

GROUP#

 

31 TIME=

 

1988.2500 PAYOUT=

 

3.500 WELLS=

 

8.508

 

 

GROUP#

 

32 TIME=

 

1988.5000 PAYOUT=

 

3.500 WELLS=

 

8.770

 

 

GROUP#

 

33 TIME=

 

1988.7500 PAYOUT=

 

3.500 WELLS=

 

8.143

 

 

GROUP#

 

34 TIME=

 

1989.0000 PAYOUT=

 

3.500 WELLS=

 

7.220

 

 

GROUP#

 

35 TIME=

 

1989.2500 PAYOUT=

 

3.500 WELLS=

 

8.217

 

 

GROUP#

 

36 TIME=

 

1989.5000 PAYOUT=

 

3.500 WELLS=

 

9.101

 

 

GROUP#

 

37 TIME=

 

1989.7500 PAYOUT=

 

3.500 WELLS=

 

8.447

 

 

GROUP#

 

38 TIME=

 

1990.0000 PAYOUT=

 

3.500 WELLS=

 

8.604

 

 

GROUP#

 

39 TIME=

 

1990.2500 PAYCUT=

 

3.500 WELLS=

 

8.468

 

 

GROUP#

 

40 TIME=

 

1990.5000 PAYOUT=

 

3.500 WELLS=

 

8.341

 

 

GROUP#

 

1 TIME=

 

1990.7500 PAYOUT=

 

3.500 WELLS=

 

4.978

 

 

GROUP#

 

2 TIME=

 

1991.0000 PAYOUT=

 

3.500 WELLS=

 

4.865

 

 

GROUP#

 

3 TIME=

 

1991.2500 PAYOUT=

 

3.500 WELLS=

 

4.759

 

 

GROUP#

 

4 TIME=

 

1991.5000 PAYOUT=

 

3.500 WELLS=

 

4.659

 

 

GROUP#

 

5 TIME=

 

1991.7500 PAYOUT=

 

3.500 WELLS=

 

4.563

 

 

GROUP#

 

6 TIME=

 

1992.0000 PAYOUT=

 

3.500 WELLS=

 

4.475

 

 

GROUP#

 

7 TIME=

 

1992.2500 PAYOUT=

 

3.500 WELLS=

 

4.438

 

 

GROUP#

 

8 TIME=

 

1992.5000 PAYOUT=

 

3.500 WELLS=

 

4.353

 

 

GROUP#

 

9 TIME=

 

1992.7500 PAYOUT=

 

3.500 WELLS=

 

4.274

 

 

GROUP#

 

10 TIME=

 

1993.0000 PAYOUT=

 

3.500 WELLS=

 

4.201

 

 

GROUP#

 

11 TIME=

 

1993.2500 PAYCUT=

 

3.500 WELLS=

 

4.134

 

 

GROUP#

 

12 TIME=

 

1993.5000 PAYOUT=

 

3.500 WELLS=

 

4.074

 

 

GROUP#

 

13 TIME=

 

1993.7500 PAYOUT=

 

3.500 WELLS=

 

4.019

 

 

GROUP#

 

14 TIME=

 

1994.0000 PAYOUT=

 

3.500 WELLS=

 

3.943

 

 

GROUP#

 

15 TIME=

 

1994.2500 PAYOUT=

 

3.500 WELLS=

 

3.854

 

 

GROUP#

 

16 TIME=

 

1994.5000 PAYOUT=

 

3.500 WELLS=

 

3.778

 

 

GROUP#

 

17 TIME=

 

1994.7500 PAYOUT=

 

3.500 WELLS=

 

3.706

 

 

GROUP#

 

18 TIME=

 

1995.0000 PAYOUT=

 

3.500 WELLS=

 

3.638

 

 

GROUP#

 

19 TIME=

 

1995.2500 PAYOUT=

 

3.500 WELLS=

 

3.575

 

 

GROUP#

 

20 TIME=

 

1995.5000 PAYOUT=

 

3.500 WELLS=

 

3.515

 

 

GROUP#

 

21 TIME=

 

1995.7500 PAYOUT=

 

3.500 WELLS=

 

3.460

 

 

GROUP#

 

22 TIME=

 

1996.0000 PAYOUT=

 

3.500 WELLS=

 

3.407

 

 

 

7



 

GROUP#

 

23 TIME=

 

1996.2500 PAYOUT=

 

3.500 WELLS=

 

3.358

 

 

GROUP#

 

24 TIME=

 

1996.5000 PAYOUT=

 

3.500 WELLS=

 

3.313

 

 

GROUP#

 

25 TIME=

 

1996.7500 PAYOUT=

 

3.500 WELLS=

 

3.270

 

 

GROUP#

 

26 TIME=

 

1997.0000 PAYOUT=

 

3.500 WELLS=

 

3.230

 

 

GROUP#

 

27 TIME=

 

1997.2500 PAYOUT=

 

3.500 WELLS=

 

3.193

 

 

GROUP#

 

28 TIME=

 

1997.5000 PAYOUT=

 

3.500 WELLS=

 

3.159

 

 

GROUP#

 

29 TIME=

 

1997.7500 PAYOUT=

 

3.500 WELLS=

 

3.127

 

 

GROUP#

 

30 TIME=

 

1998.0000 PAYOUT=

 

3.500 WELLS=

 

3.098

 

 

GROUP#

 

31 TIME=

 

1998.2500 PAYOUT=

 

3.500 WELLS=

 

3.070

 

 

GROUP#

 

32 TIME=

 

1998.5000 PAYOUT=

 

3.500 WELLS=

 

3.045

 

 

GROUP#

 

33 TIME=

 

1998.7500 PAYOUT=

 

3.500 WELLS=

 

3.022

 

 

GROUP#

 

34 TIME=

 

1999.0000 PAYOUT=

 

3.500 WELLS=

 

3.001

 

 

GROUP#

 

35 TIME=

 

1999.2500 PAYOUT=

 

3.500 WELLS=

 

2.957

 

 

GROUP#

 

36 TIME=

 

1999.5000 PAYOUT=

 

3.500 WELLS=

 

2.914

 

 

GROUP#

 

37 TIME=

 

1999.7500 PAYOUT=

 

3.500 WELLS=

 

2.872

 

 

GROUP#

 

38 TIME=

 

2000.0000 PAYOUT=

 

2.500 WELLS=

 

2.082

 

 

GROUP#

 

39 TIME=

 

2000.2500 PAYOUT=

 

2.500 WELLS=

 

2.062

 

 

GROUP#

 

40 TIME=

 

2000.5000 PAYOUT=

 

2.500 WELLS=

 

2.043

 

 

GROUP#

 

41 TIME=

 

2000.7500 PAYOUT=

 

2.500 WELLS=

 

2.025

 

 

GROUP#

 

42 TIME=

 

2001.0000 PAYOUT=

 

2.500 WELLS=

 

2.009

 

 

GROUP#

 

43 TIME=

 

2001.2500 PAYOUT=

 

2.500 WELLS=

 

1.986

 

 

GROUP#

 

44 TIME=

 

2001.5000 PAYOUT=

 

2.500 WELLS=

 

1.957

 

 

GROUP#

 

45 TIME=

 

2001.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

46 TIME=

 

2002.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

47 TIME=

 

2002.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

48 TIME=

 

2002.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

49 TIME=

 

2002.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

50 TIME=

 

2003.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

51 TIME=

 

2003.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

52 TIME=

 

2003.5000 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

53 TIME=

 

2003.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

54 T1ME=

 

2004.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

55 TIME=

 

2004.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

56 TIME=

 

2004.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

57 TIME=

 

2004.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

58 TIME=

 

2005.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

59 TIME=

 

2005.2500 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

60 TIME=

 

2005.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

61 TIME=

 

2005.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

62 TIME=

 

2006.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

63 TIME=

 

2006.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

64 TIME=

 

2006.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

65 TIME=

 

2006.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

66 TIME=

 

2007.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

67 TIME=

 

2007.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

68 TIME=

 

2007.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

69 TIME=

 

2007.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

70 TIME=

 

2008.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

71 TIME=

 

2008.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

72 TIME=

 

2008.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

73 TIME=

 

2008.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

74 TIME=

 

2009.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

75 TIME=

 

2009.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

76 TIME=

 

2009.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

77 TIME=

 

2009.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

78 TIME=

 

2010.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

 

8



 

GROUP#

 

79 TIME=

 

2010.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

80 TIME=

 

2010.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

81 TIME=

 

2010.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

82 TIME=

 

2011.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

83 TIME=

 

2011.2500 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

84 TIME=

 

2011.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

85 TIME=

 

2011.7500 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

86 TIME=

 

2012.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

87 TIME=

 

2012.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

88 TIME=

 

2012.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

89 TIME=

 

2012.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

90 TIME=

 

2013.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

91 TIME=

 

2013.2500 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

92 TIME=

 

2013.5000 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

93 TIME=

 

2013.7500 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

94 TIME=

 

2014.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

95 TIME=

 

2014.2500 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

96 TIME=

 

2014.5000 PAYCUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

97 TIME=

 

2014.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

98 TIME=

 

2015.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

99 TIME=

 

2015.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

100 TIME=

 

2015.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

101 TIME=

 

2015.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

102 TIME=

 

2016.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

103 TIME=

 

2016.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

104 TIME=

 

2016.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

105 TIME=

 

2016.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

106 TIME=

 

2017.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

107 TIME=

 

2017.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

108 TIME=

 

2017.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

109 TIME=

 

2017.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

110 TIME=

 

2018.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

111 TIME=

 

2018.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

112 TIME=

 

2018.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

113 TIME=

 

2018.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

114 TIME=

 

2019.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

115 TIME=

 

2019.2500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

116 TIME=

 

2019.5000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

117 TIME=

 

2019.7500 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

GROUP#

 

118 TIME=

 

2020.0000 PAYOUT=

 

0.000 WELLS=

 

0.000

 

 

 

9



 

Exhibit B
Base Costs

 

Section 1
Introduction

 

1.1                                Purpose .  The purpose of this Exhibit B is to provide the methods, formulae and procedures to calculate Base Costs and its components.  This Exhibit was formulated in conjunction with Exhibit A and is designed to reflect the total Base Costs for the entire Long Beach Unit associated with the Base Development Plan.

 

1.2                                Definitions .  Unless defined herein or in Exhibit A, all initially capitalized terms shall have the meaning set forth in the Agreement.

 

(a)                                  Base Operating Expense is the operating expense under the Base Development Plan.

 

(b)                                  Base Drilling Capital are the capital costs of drilling new Base Production Wells and their associated injection wells under the Base Development Plan.

 

(c)                                   Base Taxes are the taxes which would have been paid if the Base Development Plan was actually implemented and achieved the results contemplated by Exhibit A.

 

(d)                                  Base Permitting Costs are the costs associated with the acquisition and maintenance of permits for the Base Development Plan.

 

(e)                                   Base Land Rentals are the fees, rentals and other payments required to lease the area necessary for the Base Development Plan operations.

 

(f)                                    Base License Costs are the costs associated for licenses and other approval required to implement the Base Development Plan operations.

 

(g)                                   Base Water Supply Costs are the costs and expenses associated with the acquisition or discovery of additional water sources for LBU development that are required for the Base Development Plan.

 

(h)                                  GNP Deflator is that factor which will adjust a monetary value from current dollars to January 1, 1990 dollars.  The factor utilized shall be the Fixed-weighted price index, gross domestic business product published by the Survey of Current Business by the Bureau of Economic Analysis of the United States Department of Commerce.  The GNP Defrator is not used in the Computer Program.  It is used outside of the Computer Program to calculate the oil price in terms of January 1, 1990 dollars as described in Equation 17 of Exhibit A.  The Fixed-weighted price index as of January 1, 1990 was calculated to be 130.3.  The GNP Deflator for each quarter will be the product of the prior quarter’s GNP Deflator index and the quotient of the GNP Deflator index for the prior quarter divided by the GNP Deflator index for the quarter preceding the prior quarter.  An adjustment will be made at the time of the subsequent quarter’s accounting to account for differences in Base Costs resulting from differences between the GNP

 

B-1



 

De.flator calculated above and the actual GNP Deflator as published by the United States Department of Commerce.

 

(i)                                      GNP Inflator is that factor which will adjust a monetary value from January 1, 1990 dollars to current dollars to account for inflation.  The factor shall be that published by the Department of Commerce and noted in Paragraph 1.2(h).  The GNP Inflator is not used in the Computer Program, but is used in calculations made outside of the Computer Program.

 

1.3                                Determination .  Base Costs shall be defined as the sum of Base Operating Expense, Base Drilling Capital, Base Taxes, Base Permitting Costs, Base Land Rentals, Base License Costs and Base Water Supply Costs.

 

Section 2
Base Operating Expense

 

2.1                                Determination .  Base Operating Expense shall be determined from the Base oil, Base Water, and average oil price, P, as defined in Exhibit A.  The Base Operating Expense shall be calculated in each quarter as follows:

 

A.                                     The Base Operating Expense (in dollars, adjusted for actual oil price and inflation) is calculated as follows:

 

1.                                       If the sum of the Base Oil and Base Water is greater than 165085 BBL/Day for the quarter, then

 

Base Operating Expense = [ (Base Oil) * (0.290560) + (Base Oil + Base Water) * (0.430874) + (73691.17) * (Number of days in quarter) ] * [GNP Inflator] * [Cost Reduction Factor] * [Oil Price Adjustment Factor]

 

Note:  As described in Paragraph 1.2(i), the GNP Inflator is not referenced in the Computer Program, but is effectively equal to 1.0 for purposes of the Computer Program calculations.  The GNP Inflator is used outside of the Computer Program as described above.

 

Where:

 

Base Oil is the total barrels of Base Oil produced during the quarter, as defined in Exhibit A.

 

Base Water is the total barrels of Base Water produced during the quarter as defined in Exhibit A.

 

Cost Reduction Factor is an adjustment factor to account for temporary cost reductions during the first eight quarters of this agreement.  The values to be used in this factor are referenced to the effective date of this agreement and are defined as follows:

 

B-2


 

1st Quarter:

 

0.943327

2nd Quarter:

 

0.950411

3rd Quarter:

 

0.957495

4th Quarter:

 

0.964579

5th Quarter:

 

0.971663

6th Quarter:

 

0.978747

7th Quarter:

 

0.985832

8th Quarter:

 

0.992916

Thereafter:

 

1.000000

 

Oil Price Adjustment Factor adjusts the costs to reflect varying real oil prices and is calculated as follows:

 

Oil Price Adjustment Factor = (0.0123615) (P) + (0.8145769)

 

where:

 

P is the average oil price as defined in Exhibit A

 

2.  If the sum of the Base Oil and Base Water is less than or equal to 165085 BBL/Day for the quarter, then

 

Base Operating Expense = [ (Base Oil) * (0.290560) + (Base Oil + Base Water) * (0.293756) + (96327.30) * (Number of days in quarter) ] * [GNP Inflator] * [Cost Reduction Factor] * [Oil Price Adjustment Factor]

 

Note:  As described in Paragraph 1.2(i), the GNP Inflator is not referenced in the Computer Program, but is effectively equal to 1.0 for purposes of the Computer Program calculations.  The GNP Inflator is used in the computer program as described above.

 

Where:

 

All terms are as defined in Section 2.1.A.

 

Section 3
Base Drilling Capital

 

3.1                                Determination .  Base Drilling Capital is determined by the number of Base Production Wells added in the quarter as determined in Exhibit A and are defined as follows:

 

Base Drilling Capital = ($900,000) * [Number of Base Production Wells added] * [GNP Inflator] * [Oil Price Adjustment Factor]

 

Note:  As described in Paragraph 1.2(i), the GNP Inflator in not referenced in the Computer Program, but is effectively equal to 1.0 for purposes of the Computer Program calculations.  The GNP Inflator is used outside of the Computer Program as described above.

 

B-3



 

Section 4
Base Taxes

 

4.1                                Determination and Allocation .  Base Taxes are not calculated or used by the Computer Program, but instead are calculated outside of the Computer Program.  Base Taxes to be used in calculation of total Base Costs for a quarter will be the sum of the actual taxes paid by the Unit Operator for operation of the Long Beach Unit, unless any specific taxes can be attributed to the incremental optimized waterflood program as follows.  Any taxes that are based on production volumes during a quarter will be attributed proportionally to Base Taxes by the ratio of to Base Oil production to actual oil production.  Any taxes which are based on economic value at a specific time will be attributed proportionally to Base Taxes by the ratio of Base Oil value to the total value, total value being that value of the Unit used in the tax assessment.  Base Oil value will be determined using the same economic environmental parameters, including but not limited to oil price and inflation rate, used in the tax assessment, the methodology for determining Base Oil as defined in Exhibit A and the methodology for determining Base Costs defined in this Exhibit.  Any taxes that are based on reserves at a specific time will be credited proportionally to Base Taxes by the ratio of Base Oil reserves to assessed reserves.  Base reserves are those reserves determined in the same manner described above for Base Taxes based on economic value.

 

Section 5
Base Permitting Costs

 

5.1                                Determination .  Base Permitting Costs are not calculated or used by the Computer Program, but instead are calculated outside of the Computer Program.  Base Permitting Costs shall be the actual permitting costs paid by the Unit Operator for operation of the Long Beach Unit, less any specific portions of the permitting costs directly related to the optimized waterflood program.

 

Section 6
Base Land Rental Costs

 

6.1                                Determination .  Base Land Rentals are not calculated or used by the Computer Program, but instead are calculated outside of the Computer Program.  Base Land Rental Costs shall be the actual land rental costs paid by the Unit Operator for operation of the Long Beach Unit, less any specific portions of the land rental costs directly related to the optimized waterflood program.

 

Section 7
Base License Costs

 

7.1                                Determination .  Base License Costs are not calculated or used by the Computer Program, but instead are calculated outside of the Computer Program.  Base License Costs shall be the actual license costs paid by the Unit Operator for operation of the Long Beach Unit, less any specific portions of the license costs directly related to the optimized waterflood program.

 

B-4



 

Section 8
Base Water Supply Costs

 

8.1                                Determination .  Base Water Supply Costs are not calculated or used by the Computer Program, but instead are calculated outside of the Computer Program.  Base Water Supply Costs for each of the first ten quarters following the Commencement Date shall be equal to $250,000 times the GNP Inflator to adjust the monetary value from January 1, 1990 to current dollars.  For all quarters after the tenth quarter following the Commencement Date, the Base Water Supply Costs shall be zero.

 

B-5



 

EXHIBIT C

 

SCOPE OF THE PROGRAM

 

For purposes of the Agreement the Program consists of four segments:  reservoir analysis; field data gathering and analysis; acquisition of injectant; and new wells and redrills.  Each of these segments are described below:

 

Reservoir analysis consists of a thorough geological, geophysical and engineering review of the various zones and subzones which comprise the reservoirs of the Long Beach Unit.  The analysis will be performed by ALBI technical personnel and consultants in participation with City and Field Contractor personnel.

 

Field data gathering and analysis consists of field performance analysis; well surveys; formation coring and core interpretation; waterflood performance and response; reservoir description and map development; analysis of perforation intervals and water surveys; water source analysis and injection surveys reviewing vertical conformance.

 

The Program may require additional supply of water and/or other injectant.  This material may need to be purchased and facilities may need to be constructed or acquired to deliver the injectant to the appropriate location for use in the field.

 

The final segment of the Program is initiation of a program of new wells and redrills.  The new wells and redrills will employ the technology developed by ALBI and improvements developed by the oil and gas industry.  Those techniques and developments will be applied to all new wells and redrills in the Long Beach Unit (including but not limited to all new wells and redrills contemplated to achieve base production and new wells and redrills which are included within the commitment of ALBI described in Section 2.02 of the Agreement).

 

The Agreement governs the relationship of the Parties concerning the Program and includes waterflood, water-alternating-hydrocarbon gas injection or other recovery methods where hydrocarbon material is injected into the reservoir.  Notwithstanding the California Division of Oil and Gas and the United States Department of Energy definitions of EOR or tertiary recovery, the above described methods shall be included as optimized waterflood techniques within the scope of the Program and governed by this Agreement (if economic to implement).  The Program does not include Enhanced Oil Recovery (EOR) or tertiary recovery projects unless specifically referenced above.  This definition applies to the Agreement only and does not affect the rights and responsibilities of the Parties under other agreements or laws, regulations or orders.

 

C-1



 

EXHIBIT D

 

DEPOSITORY AGREEMENT

 

THIS DEPOSITORY AGREEMENT (this “Agreement”) is made and entered into as of the 5th day of November, 1991, by and among National Safe Depository, a California limited partnership (“Depository”), the State of California (the “State”), by and through the State Lands Commission (the “SLC”), the City of Long Beach (the “City”), Atlantic Richfield Company, a Delaware corporation (“ARCO”), and ARCO Long Beach, Inc., a Delaware corporation and a wholly owned subsidiary of ARCO (“ALBI”).  ARCO and ALBI are collectively referred to herein as the “ARCO Parties.”

 

W I T N E S S E T H:

 

WHEREAS, the State, the City, ARCO and ALBI (individually a “Party” and collectively the “Parties”) are parties to that certain Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated as of November 5, 1991 (the “OWP Agreement”);

 

WHEREAS, Section 2.19 of the OWP Agreement provides that the Parties shall cause to be made and stored an exact copy of the computer program developed jointly by the ARCO Parties and the SLC for the purpose of performing certain accountings provided for in the OWP Agreement and related software (the “Computer Program”);

 

WHEREAS, Depository has the ability to store safely such copy of the Computer Program at its facilities located in San Jose, California; and

 

WHEREAS, the Parties jointly wish to engage Depository to store such copy of the Computer Program on behalf of the Parties and Depository is willing to perform such services on behalf of the Parties.

 

NOW, THEREFORE, the parties hereto agree as follows:

 

1.                                       Depository Services .

 

(a)                                  Upon their execution of this Agreement, the Parties are concurrently delivering to Depository one or more disks or other forms of media on which are stored an exact copy of the Computer Program (the “Media”).

 

(b)                                  Depository hereby accepts the Media and agrees to store it at the facility described above.  Depository shall ensure that the Media shall be stored separate and apart from all property designated as belonging to other customers of Depository.  Depository shall ensure that the Media shall be stored in an individual safe deposit box in a secure climate-controlled vault.

 

(c)                                   Depository shall ensure that the Parties shall have access to the Media pursuant to the terms provided in Section 2.

 

D-1



 

(d)                                  Depository shall not divulge, disclose or otherwise make available to any person or entity, other than as provided in Section 2, or make any use whatsoever of the Media.  Depository shall not permit any person access to the Media, other than as provided in Section 2, except as may be necessary for Depository’s authorized representatives to perform their functions under this Depository Agreement.

 

(e)                                   Depository shall have no obligation or responsibility to verify or determine that the Media deposited with it by the Parties does, in fact, consist of those items which the Parties are obligated to deliver under the OWP Agreement, and Depository shall bear no responsibility whatsoever to determine the existence, relevance, completeness, currency, or accuracy of the Media.

 

2.                                      Access by the Parties .

 

(a)                                  Concurrent with the delivery of the Media, each of the Parties will provide Depository with a list of all authorized representatives who on behalf of such Party may be granted access to the Media, which list shall include the signature of each such authorized representative.  No representative of any of the Parties shall be granted access to the Media unless such representative is one of the Party’s authorized representatives or is accompanied by one or more of the Party’s authorized representatives.  A Party may amend or substitute its list of adthorized representatives at any time by written notice to Depository executed by an authorized representative of the Party.

 

(b)                                  Any of the Parties desiring access to the Media shall give written notice thereof to each of the other Parties and Depository transmitted at least fourteen days prior to the proposed access if the mails are used, or seven days in advance if telephonic facsimile is used.  Upon its receipt of such notice, Depository shall immediately notify each of the other Parties using the same mode of transmission by which notice was given to Depository.  Such notice from Depository shall include the identity of the Party seeking access to the Media and the date and time of such proposed access.  Each of the other Parties shall be permitted to have one or more representatives (including at least one authorized representative) present at the time access is given to another party.  Upon compliance with the foregoing notice provisions, the Party requesting access to the Media shall be granted such access at the noticed date and time regardless of the absence of representatives of the other Parties.  Notwithstanding the foregoing, in the event one of the ARCO Parties desires access to the Media, no notices with respect to such access shall be required to be given to the other ARCO Party.

 

(c)                                   During Depository’s normal business hours, the Parties may obtain access to the Media, without advance notice to Depository, if each of the Parties is physically represented in person by one or more of its authorized representatives.

 

(d)                                  During the entire time of any access to the Media, Depository’s representatives shall ensure that no changes or modifications to the Media are made during such access.  In furtherance of the foregoing provision, access to the Media (other than access for the purpose of making a change or modification to the Computer Program) shall be limited to the making of a copy of the Computer Program.

 

D-2



 

3.                                       Payment to Depository .

 

Depository shall invoice the Parties for its services performed hereunder.  One-third of the amounts payable to Depository hereunder shall be paid by ALBI and the remaining two-thirds of such amounts payable shall be paid by the City.  Depository’s charges for its services hereunder shall be at rates no higher than the lowest rates charged to other customers of Depository for similar storage requirements.  Payment on Depository’s storage services invoice shall be due within 30 days after the City’s and ALBI’s receipt thereof.

 

4.                                       Amendment and Termination of Agreement .

 

(a)                                  This Agreement may be amended or terminated at any time upon written agreement of each of the parties hereto.

 

(b)                                  This Agreement may be terminated upon the written agreement of the Parties upon written notice thereof to Depository.  This Agreement shall terminate five years after the termination of Article 2 of the OWP Agreement, or, if later, the date of final resolution of the last dispute arising under Section 2.16 of the OWP Agreement.

 

(c)                                   Unless the Parties shall have provided Contrary Instructions to Depository within 10 business days after termination of this Agreement, the Media in the custody of Depository shall be delivered to the City by Depository within the next five business days following the end of such 10 day period.  Such delivery will terminate all duties and obligations of Depository to the Parties.  Depository shall be entitled to receive payment for reasonable costs, fees and expenses due it, prior to the release of the Media.

 

(d)                                  “Contrary Instructions” for purposes of this Agreement shall mean a notarized affadavit executed by an authorized representative of each of the Parties directing Depository to deliver the.Media in a manner or to a person or entity not specified in Section 4(b).

 

5.                                       Miscellaneous .

 

(a)                                  Assignment .  Neither this Agreement nor any right or obligation arising hereunder may be assigned, in whole or in part, by Depository except in connection with a merger, consolidation or other reorganization of Depository or in connection with the sale of all or substantially all the business or assets of Depository.  Depository shall provide 30 days’ prior written notice to the Parties of its intention to make any assignment of this Agreement.  Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the successors and assigns of each of the parties hereto.

 

(b)                                  Disputes; Choice of Law .  Any disputes hereunder between or among the Parties shall be resolved pursuant to and governed by the provisions of Sections 2.17, 7.12 and 7.15 of the OWP Agreement.  This Agreement shall be governed by and construed in accordance with the laws of the State of California without giving effect to conflicts-of-laws rules and laws.

 

(c)                                   Waiver .  No waiver of any right under this Agreement shall be deemed effective unless contained in a writing signed by an authorized representative of the party charged with such waiver, and no waiver of any right arising from any breach or failure to perform shall be

 

D-3



 

deemed to be a waiver of any future such right or of any other right arising under this Agreement.

 

(d)                                  Headings; Gender; Number .  The headings of the Sections herein are inserted for convenience of reference only and are not intended to be a part of, or to affect the meaning or interpretation of, this Agreement.  In this Agreement, unless the context requires otherwise, the masculine, feminine and neuter genders and the singular and plural numbers include one another.

 

(e)                                   Notices .  Any notice or other communication required or permitted to be given hereunder shall be in writing and shall be mailed by registered or certified mail, postage prepaid, return receipt requested, or delivered by commercial courier against receipt or in person (or pursuant to Section 2(b) by confirmed telephonic facsimile), as follows:

 

If to the State:

 

Executive Officer

State Lands Commission

1807 - 13th Street

Sacramento, California  95814

(Telecopier: (916) 322-3568)

(Confirmation: (916) 322-4105)

 

If to the City:

 

City Manager

13th Floor, City Hall

333 West Ocean Boulevard

Long Beach, California  90802

(Telecopier: (310) 590-6107)

(Confirmation: (310) 590-6818)

 

with a copy to:

 

Director of Department of Oil Properties

2nd Floor, City Hall

333 West Ocean Boulevard

Long Beach, California  90802

(Telecopier: (310) 590-6191)

(Confirmation: (310) 590-6878)

 

If to ARCO:

 

ARCO Oil and Gas Company

P.O. Box 147

Bakersfield, California  93302 (for mail delivery only)

or

4550 California Avenue

Bakersfield, California  93309

 

D-4



 

(Telecopier: (805) 321-4160)

(Confirmation: (805) 321-4136)

Attention: Vice President and General Manager

 

with a copy to:

 

Atlantic Richfield Company

515 South Flower Street

Los Angeles, California  90071

(Telecopier: (213) 486-1818)

(Confirmation: (213) 486-1774)

Attention: Senior Vice President and General Counsel

 

If to ALBI:

 

ARCO Long Beach, Inc.

300 Oceangate

Long Beach, California  90802

(Telecopier: (805) 321-4160)

(Confirmation: (805) 321-4136)

Attention: Business Unit Manager

 

with a copy to:

 

Atlantic Richfield Company

515 South Flower Street

Los Angeles, California  90071

(Telecopier: (213) 486-1818)

(Confirmation: (213) 486-1774)

Attention: Senior Vice President and General Counsel

 

If to Depository:

 

National Safe Depository

2109 Bering Drive

San Jose, California  95131

(Telecopier: (408) 441-6826)

(Confirmation: (408) 453-2753)

 

or to such other address as such party shall have furnished in writing in accordance with the provisions of this Section.  Any notice or other communication mailed by registered or certified mail shall be deemed given at the earlier of the time of its receipt by the addressee or seven days after the time of mailing thereof.  Any notice given in any other fashion shall be deemed to have been given when actually received by the addressee.

 

(f)                                    Indemnification .  The Parties jointly and severally agree to defend and indemnify Depository and to hold Depository harmless from and against any and all claims, actions, suits, whether groundless or otherwise, and from and against any and all liabilities, losses, damages,

 

D-5



 

reasonable costs, reasonable charges, penalties, reasonable counsel fees, any other reasonable expenses of any nature, including without limitation, settlement costs incurred by Depository on account of any act or omission of Depository, in respect of or with regard to this Agreement, except insofar as such liabilities arise by reason of Depository’s gross negligence or willful misconduct.

 

(g)                                   Counterparts .  This Agreement may be executed in any number of counterparts, each of which shall be an original and all of which shall constitute together but one and the same document.

 

(h)                                  Relationship of Parties .  Nothing set forth herein shall ever be construed to create an association, trust or partnership or impose a trust or partnership duty, obligation or liability on or with regard to any one or more of the Parties.

 

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.

 

 

THE STATE OF CALIFORNIA

 

 

 

By:

The State Lands Commission

 

 

 

 

 

By:

 

 

 

Charles Warren

 

 

Executive Officer

 

 

 

 

 

THE CITY OF LONG BEACH

 

 

 

 

 

By:

 

 

 

John F. Shirey

 

 

Assistant City Manager

 

 

 

 

 

ATLANTIC RICHFIELD COMPANY

 

 

 

 

 

By:

 

 

 

Paul B. Norgaard

 

 

Vice President

 

D-6


 

 

ARCO LONG BEACH, INC.

 

 

 

 

 

By:

 

 

 

Paul B. Norgaard

 

 

President

 

 

 

 

 

 

 

NATIONAL SAFE DEPOSITORY

 

 

 

 

 

 

 

By:

 

 

Name:

 

 

Title:

General Partner

 

D-7



 

The foregoing Depository Agreement is hereby approved as to form this 5th day of November, 1991.

 

 

JOHN K. CALHOUN, City Attorney

 

 

 

 

 

By:

 

 

 

Deputy

 

D-8



 

EXHIBIT E

 

WHEN RECORDED, PLEASE RETURN TO:

 

 

 

AMENDMENT TO CONTRACTORS’ AGREEMENT
LONG BEACH UNIT
WILMINGTON OIL FIELD

 

THIS AMENDMENT TO CONTRACTORS’ AGREEMENT (this “Amendment”) is made and entered into effective as of June 30, 1995, by and among the City of Long Beach (the “City”), the State of California, acting by and through the State Lands Commission, Atlantic Richfield Company, a Delaware corporation (“ARCO”), and any other Contractors or other Persons Comprising any Contractor who shall have properly executed and submitted a notarized signature page to this Amendment in accordance with the notice of the City dated January     , 1995, a copy of which is attached hereto as Attachment I (the “Notice”).

 

RECITALS

 

A.             The City of Long Beach and several Contractors entered into that certain Contractors’ Agreement, effective April 1, 1965, and recorded on March 10, 1965, among the official records of Los Angeles County at Book M1796, Pages 409-500 (the “Contractors’ Agreement”), which agreement is in full force and effect.

 

B.             Pursuant to the terms of the Contractors’ Agreement, the Contractors’ Agreement will terminate not later than March 31, 2000.

 

C.             The State of California (the “State”), the City, ARCO and ARCO Long Beach, Inc. entered into that certain Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated as of November 5, 1991 (the “OWP Agreement”),

 

E-1



 

which OWP Agreement, inter alia , provides for the parties thereto to implement an optimized waterflood program in the Long Beach Unit.

 

D.             At the time of its authorization of the OWP Agreement, the Legislature of the State also authorized the extension of the Contractors’ Agreement to be coterminous with the Unit Agreement for the Long Beach Unit. The Legislature also directed that each Contractor and each Person Comprising a Contractor shall be given the option to accept or reject such extension of the term of the Contractors’ Agreement, and that, upon the rejection of any such offer, ARCO shall become the Contractor or the Person Comprising a Contractor with respect to any interest under the Contractors’ Agreement of such an offeree.

 

NOW, THEREFORE, in consideration of the foregoing, the mutual promises herein set forth and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, it is agreed as follows:

 

1.              Defined Terms .  All terms defined in or for purposes of the Contractors’ Agreement shall have the same meanings as used herein, except as otherwise provided herein or unless the specific contract in which any such term is used herein indicates a contrary intention of the parties.

 

2.              Extension of Term of Contractors’ Agreement .  The following sentence is hereby added at the end of the first paragraph of Article 3 of the Contractors’ Agreement:

 

“Notwithstanding the foregoing, the term of this agreement shall be coextensive with the term of the Unit Agreement as to each Contractor or each Person Comprising a Contractor who becomes a party to the amendment to this agreement effective as of June 30, 1995 (including ARCO pursuant to paragraph 3 of such

 

E-2



 

amendment), unless sooner terminated as to any Contractor or any Person Comprising a Contractor in accordance with the provisions hereof.”

 

3.              Effect of Contractors not Signing this Amendment .  In the event that any Contractor or Person Comprising a Contractor (other than ARCO) fails to become a signatory to this Amendment in the manner provided for in the Notice, ARCO shall, on April 1, 2000, succeed to the undivided share of such Person or Persons under the Contractors’ Agreement and shall be entitled to the benefits of and shall assume, for the duration of the term of the Contractors’ Agreement, all of the rights, duties and obligations under the Contractors’ Agreement of such Person or Persons.  Attached hereto as Attachment II is a schedule specifying the names and the percentage interests and the net profits percentage interests of the Contractors and the Persons Comprising each Contractor for the extended term of the Contractors’ Agreement commencing on April 1, 2000.

 

4.              Abandonment Costs .  Effective April 1, 2000, and notwithstanding any other provision of the Contractors’ Agreement, the Unit Agreement or the Unit Operating Agreement to the contrary, no Contractor shall be obligated to pay in excess of its net profits percentage interest (as set forth on Attachment II) of such Contractor’s Unit Participation share of the costs of abandoning any Unit Wells or Unit Facilities upon and following the termination of Unit Operations.

 

5.              Full Force and Effect .  Except as modified hereby, the Contractors’ Agreement remains in full force and effect.

 

IN WITNESS WHEREOF, each of the following parties has executed this Amendment upon the date set forth opposite its name.

 

E-3



 

ATTACHED TO AND MADE A PART OF
AMENDMENT TO CONTRACTORS’ AGREEMENT,
LONG BEACH UNIT, WILMINGTON OIL FIELD, CALIFORNIA

 

Address

 

 

CITY OF LONG BEACH, a

 

 

municipal corporation

 

 

 

 

 

By

 

 

 

City Manager

 

 

Date                                                 , 1995

 

 

 

STATE OF CALIFORNIA

)

 

 

) SS.

 

COUNTY OF

)

 

 

On                                         , 1995, before me, the undersigned, a Notary Public in and for the County of                                         , State of California, duly sworn and commissioned, personally appeared                                         , personally known to me (or proved to me on the basis of satisfactory evidence) to be the person who executed this instrument as the City Manager of the City of Long Beach, and acknowledged to me that such City of Long Beach executed the same.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written.

 

 

 

 

 

 

 

Notary Public

 

 

 

My commission expires

 

 

The foregoing Amendment to Contractors’ Agreement, Long Beach Unit, Wilmington Oil Field, Los Angeles County, California, is hereby approved as to form this            day of                                       , 1995.

 

 

 

                                              , City Attorney

 

 

 

 

 

By

 

 

 

Deputy City Attorney

 

E-4



 

ATTACHED TO AND MADE A PART OF
AMENDMENT TO CONTRACTORS’ AGREEMENT,
LONG BEACH UNIT, WILMINGTON OIL FIELD, CALIFORNIA

 

Address

 

 

STATE OF CALIFORNIA, Acting

 

 

by and through the State

 

 

Lands Commission

 

 

 

 

 

 

 

 

By

 

 

 

Executive Officer

 

 

Date                                                 , 1995

 

 

 

STATE OF CALIFORNIA

)

 

 

) SS.

 

COUNTY OF

)

 

 

On                                         , 1995, before me, the undersigned, a Notary Public in and for the County of                                         , State of California, duly sworn and commissioned, personally appeared                                         , personally known to me (or proved to me on the basis of satisfactory evidence) to be the person who executed this instrument as the Executive Officer of the State Lands Commission of the State of California, and acknowledged to me that such State Lands Commission executed the same on behalf of the State of California.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written.

 

 

 

 

 

 

 

Notary Public

 

 

 

My commission expires

 

 

The foregoing Amendment to Contractors’ Agreement, Long Beach Unit, Wilmington Oil Field, Los Angeles County, California, is hereby approved as to form this            day of                                       , 1995.

 

 

                                              , Attorney General

 

 

 

 

 

By

 

 

 

Deputy Attorney General

 

E-5



 

ATTACHED TO AND MADE A PART OF
AMENDMENT TO CONTRACTORS’ AGREEMENT,
LONG BEACH UNIT, WILMINGTON OIL FIELD, CALIFORNIA

 

Address

ATLANTIC RICHFIELD COMPANY,

 

a Delaware corporation

 

 

 

By

 

 

 

Signature

 

 

 

Date                                                 , 1995

 

 

 

 

Name and Title

 

 

 

 

Attest

 

 

 

Signature

 

 

 

 

 

 

 

 

Name and Title

 

 

STATE OF CALIFORNIA

)

 

 

) SS.

 

COUNTY OF

)

 

 

On                                         , 1995, before me, the undersigned, a Notary Public in and for the County of                                         , State of California, duly sworn and commissioned, personally appeared                                          and                                         , personally known to me (or proved to me on the basis of satisfactory evidence) to be the persons who executed the within instrument as                                          and                                         , respectively, or on behalf of the corporation named therein, and acknowledged to me that such corporation executed the same.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written.

 

 

 

 

 

 

 

Notary Public

 

 

 

My commission expires

 

 

E-6



 

 

ATTACHED TO AND MADE A PART OF
AMENDMENT TO CONTRACTORS’ AGREEMENT,
LONG BEACH UNIT, WILMINGTON OIL FIELD, CALIFORNIA

 

Address

 

 

Contractor or Person

 

Comprising a Contractor

 

 

 

By

 

 

 

Signature

 

 

 

Date                                                 , 1995

 

 

 

 

Name and Title

 

 

 

 

Attest

 

 

 

Signature

 

 

 

 

 

 

 

 

Name and Title

 

 

STATE OF CALIFORNIA

)

 

 

) SS.

 

COUNTY OF

)

 

 

On                                         , 1995, before me, the undersigned, a Notary Public in and for the County of                                         , State of California, duly sworn and commissioned, personally appeared                                          and                                         , personally known to me (or proved to me on the basis of satisfactory evidence) to be the persons who executed the within instrument as                                          and                                         , respectively, or on behalf of the corporation named therein, and acknowledged to me that such corporation executed the same.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written.

 

 

 

 

 

 

 

Notary Public

 

 

 

My commission expires

 

 

E-7



 

EXHIBIT F

 

AMENDMENT TO TRACT NO. 2 AGREEMENT
LONG BEACH UNIT
WILMINGTON OIL FIELD

 

THIS AMENDMENT TO TRACT NO. 2 AGREEMENT (this “Amendment”) is made and entered into effective as of June 30, 1995, by and among the State of California (the “State”), acting by and through the State Lands Commission (the “SLC”), Atlantic Richfield Company, a Delaware corporation (“ARCO”), and the Contractor or other Persons Comprising the Contractor who shall have properly executed and submitted a notarized signature page to this Amendment in accordance with the notice of the SLC dated January     , 1995, a copy of which is attached hereto as Attachment I (the “Notice”).

 

RECITALS

 

A.             The State and The Atlantic Refining Company (successor by merger to Richfield Oil Comporation) entered into that certain Tract No. 2 Agreement, effective April 1, 1965 (the “Tract No. 2 Agreement”), which agreement is in full force and effect.

 

B.             Pursuant to the terms of the Tract No. 2 Agreement, the Tract No. 2 Agreement will terminate not later than March 31, 2000.

 

C.             The State, the City of Long Beach, ARCO and ARCO Long Beach, Inc. entered into that certain Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated as of November 5, 1991 (the “OWP Agreement”), which OWP Agreement, inter alia , provides for the parties thereto to implement an optimized waterflood program in the Long Beach Unit.

 

D.             At the time of its authorization of the OWP Agreement, the Legislature of the State also authorized the extension of the Tract No. 2 Agreement to be coterminous with the Unit Agreement for the Long Beach Unit. The Legislature also directed that the Contractor and each

 

F-1


 

Person Comprising the Contractor shall be given the option to accept or reject such extension of the term of the Tract No. 2 Agreement, and that, upon the rejection of any such offer, ARCO shall become the Contractor or the Person Comprising a Contractor with respect to any interest under the Tract No. 2 Agreement of such an offeree.

 

NOW, THEREFORE, in consideration of the foregoing, the mutual promises herein set forth and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, it is agreed as follows:

 

1.              Defined Terms .  All terms defined in or for purposes of the Tract No. 2 Agreement shall have the same meanings as used herein, except as otherwise provided herein or unless the specific context in which any such term is used herein indicates a contrary intention of the parties.

 

2.              Extension of Term of Tract No. 2 Agreement .  The following sentence is hereby added at the end of Article 3 of the Tract No. 2 Agreement:

 

“Notwithstanding the foregoing, the term of this agreement shall be coextensive with the term of the Unit Agreement as to the Contractor or each Person Comprising the Contractor who becomes a party to the amendment to this agreement effective as of June 30, 1995 (including ARCO pursuant to paragraph 3 of such amendment), unless sooner terminated as to the Contractor or any Person Comprising the Contractor in accordance with the provisions hereof.”

 

3.              Effect of Contractor not Signing this Amendment .  In the event that the Contractor or Person Comprising the Contractor (other than ARCO) fails to become a signatory

 

F-2



 

to this Amendment in the manner provided for in the Notice, ARCO shall, on April 1, 2000, succeed to the undivided share of such Person or Persons under the Tract No. 2 Agreement and shall be entitled to the benefits of and shall assume, for the duration of the term of the Tract No. 2 Agreement, all of the rights, duties and obligations under the Tract No. 2 Agreement of such Person or Persons.  Attached hereto as Attachment II is a schedule specifying the names and the percentage interests and the net profits percentage interests of the Contractor and the Persons Comprising the Contractor for the extended term of the Tract No. 2 Agreement commencing on April 1, 2000.

 

4.              Abandonment Costs .  Effective April 1, 2000, and notwithstanding any other provision of the Tract No. 2 Agreement, the Unit Agreement or the Unit Operating Agreement to the contrary, the Contractor shall not be obligated to pay in excess of its net profits percentage interest (as set forth on Attachment II) of the Contractor’s Unit Participation share of the costs of abandoning any Unit Wells or Unit Facilities upon and following the termination of Unit Operations.

 

5.              Full Force and Effect .  Except as modified hereby, the Tract No. 2 Agreement remains in full force and effect.

 

IN WITNESS WHEREOF, each of the following parties has executed this Amendment upon the date set forth opposite its name.

 

F-3



 

ATTACHED TO AND MADE A PART OF
AMENDMENT TO TRACT NO. 2 AGREEMENT,
LONG BEACH UNIT, WILMINGTON OIL FIELD, CALIFORNIA

 

Address

STATE OF CALIFORNIA, Acting

 

by and through the State

 

Lands Commission

 

 

 

By

 

 

 

Executive Officer

Date                                                 , 1995

 

 

 

 

STATE OF CALIFORNIA

)

 

) SS.

COUNTY OF

)

 

On                                         , 1995, before me, the undersigned, a Notary Public in and for the County of                                         , State of California, duly sworn and commissioned, personally appeared                                         , personally known to me (or proved to me on the basis of satisfactory evidence) to be the person who executed this instrument as the Executive Officer of the State Lands Commission of the State of California, and acknowledged to me that such State Lands Commission executed the same on behalf of the State of California.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written.

 

 

 

 

 

 

 

Notary Public

 

 

 

My commission expires

 

The foregoing Amendment to Tract No. 2 Agreement, Long Beach Unit, Wilmington Oil Field, Los Angeles County, California, is hereby approved as to form this            day of                                       , 1995.

 

 

 

                                                     , Attorney General

 

 

 

 

 

By

 

 

 

Deputy Attorney General

 

F-4



 

ATTACHED TO AND MADE A PART OF
AMENDMENT TO TRACT NO. 2 AGREEMENT,
LONG BEACH UNIT, WILMINGTON OIL FIELD, CALIFORNIA

 

Address

ATLANTIC RICHFIELD COMPANY,

 

a Delaware corporation

 

 

 

By

 

 

 

Signature

 

 

 

Date                                                 , 1995

 

 

 

 

Name and Title

 

 

 

 

Attest

 

 

 

Signature

 

 

 

 

 

 

 

 

Name and Title

 

 

STATE OF CALIFORNIA

)

 

) SS.

COUNTY OF

)

 

On                                         , 1995, before me, the undersigned, a Notary Public in and for the County of                                         , State of California, duly sworn and commissioned, personally appeared                                          and                                         , personally known to me (or proved to me on the basis of satisfactory evidence) to be the persons who executed the within instrument as                                          and                                         , respectively, or on behalf of the corporation named therein, and acknowledged to me that such corporation executed the same.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written.

 

 

 

 

 

 

Notary Public

 

 

 

My commission expires

 

F-5



 

ATTACHED TO AND MADE A PART OF
AMENDMENT TO TRACT NO. 2 AGREEMENT,
LONG BEACH UNIT, WILMINGTON OIL FIELD, CALIFORNIA

 

Address

 

 

Contractor or Person

 

Comprising a Contractor

 

 

 

By

 

 

 

Signature

 

 

 

Date                                                 , 1995

 

 

 

 

Name and Title

 

 

 

 

Attest

 

 

 

Signature

 

 

 

 

 

 

 

 

Name and Title

 

 

STATE OF CALIFORNIA

)

 

) SS.

COUNTY OF

)

 

On                                         , 1995, before me, the undersigned, a Notary Public in and for the County of                                         , State of California, duly sworn and commissioned, personally appeared                                          and                                         , personally known to me (or proved to me on the basis of satisfactory evidence) to be the persons who executed the within instrument as                                          and                                         , respectively, or on behalf of the corporation named therein, and acknowledged to me that such corporation executed the same.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal the day and year in this certificate first above written.

 

 

 

 

 

 

 

Notary Public

 

 

 

My commission expires

 

F-6



 

EXHIBIT G

 

RELEASE

 

KNOW ALL PERSONS BY THESE PRESENTS that [Name of Releasor], on behalf of itself, its successors and assigns (“Releasor”), for good and valuable consideration, the receipt of which is hereby acknowledged, does hereby absolutely, fully and forever release, relieve, remise and discharge to the date of these presents

 

(1)            [Name of Releasee], its predecessors, subsidiaries, divisions, affiliates, and parents,

 

(2)            each and every past and present representative, servant, officer, director, agent, employee and attorney of each Releasee described in (1), and

 

(3)            each and every heir, executor, administrator, successor and assign of each Releasee described in (1) and (2),

 

of and from any cause of action, suit, claim, controversy or damages, in law or in equity, asserted in or arising out of the action entitled Atlantic Richfield Co. et al. v. State Lands Commission, et al. , NO. C663010 (Los Angeles County Superior Court) and No. 2 Civil B054449 (California Court of Appeal), which against Releasees Releasor now has, may have or ever has had, except that (in the case of the Santa Barbara County defendants) the claims asserted in the Fifth Cause of Action shall not be released.

 

Releasor is aware that it or its attorneys may hereafter discover facts different from or in addition to the facts of which it or its attorneys now are aware with respect to the subject matter of this release. Releasor has been advised as to the meaning and effect of, and it understands, Section 1542 of the California Civil Code (“Section 1542”), which provides as follows:

 

A general release does not extend to claims which the creditor does not know or suspect to exist in his favor at the time of executing

 

G-1



 

the release, which if known by him must have materially affected his settlement with the debtor.

 

Releasor waives and relinquishes all rights and benefits it has or may have under Section 1542.

 

This release may not be changed orally.

 

IN WITNESS WHEREOF, Releasor has set his hand and seal the            day of                                     , 199   .

 

Signed, sealed and delivered

 

in the presence of

 

 

[Name of Releasor]

 

 

 

 

 

Name of Witness

 

 

G-2



 

EXHIBIT H

 

WHEN RECORDED, PLEASE RETURN TO:

 

 

 

CORPORATION QUITCLAIM DEED

 

Atlantic Richfield Company, a Delaware corporation, herein referred to as Grantor, hereby remises, releases and quitclaims to the State of California, herein referred to as Grantee, all of Grantor’s right, title and interest in and to that certain State Oil and Gas Lease number 308 more particularly described in Exhibit “A” attached hereto and made a part hereof and that certain State Oil and Gas Lease number 309 more particularly described in Exhibit “B” attached hereto and made a part hereof (the “Leases”).  Grantor hereby covenants that all wells drilled from the Leases or either of them have been plugged and abandoned in accordance with requirements established by the California Division of Oil and Gas and the State Lands Commission.

 

Notwithstanding the foregoing, Grantor shall have the power to terminate the right, title and interest of Grantee hereby conveyed in the event that (i).that certain Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated as of November 5, 1991, among Grantee, acting by and through the State Lands Commission, the City of Long Beach, Grantor and ARCO Long Beach, Inc., a Delaware corporation (“ALBI”), pursuant to Article IV of which this Corporation Quitclaim Deed is being delivered (the “Agreement”), shall be terminated by Grantor and ALBI pursuant to Section 5.01 of the Agreement as a result of a determination of voidness or unconstitutionality of Chapter 941 of the Statutes of 1991 of the State of California (“Chapter 941”), made at any time, in a lawsuit or other proceeding commenced prior to January 1, 1997, and (ii) within sixty (60) days after such a termination Grantor makes the payment described in Section 5.01 of the Agreement; in which event Grantor’s right, title and interest in and to the Leases shall be restored and the Leases shall be in full force and effect notwithstanding anything to the contrary in the Leases or the regulations of the State Lands Commission of the State of California.

 

The exercise, if any, of Grantor’s rights and powers under this Corporation Quitclaim Deed shall be evidenced by a notice from Grantor or by civil action in the manner contemplated by Section 885.050 of the California Civil Code, or the corresponding provision or provisions of any applicable succeeding law.

 

The power of termination set forth herein shall expire fifteen (15) years after the date of recordation of this Corporation Quitclaim Deed; provided, however, that such expiration date may be extended in the manner contemplated by Section 885.030 of the California Civil Code, or the corresponding provision or provisions of any applicable succeeding law, in the event that the issue of the voidness or unconstitutionality of Chapter 941 in a lawsuit or other proceeding referred to in the second paragraph of this Corporation Quitclaim Deed has not been finally determined prior fourteen (14) years and eleven (11) months after the date of recordation of this Corporation Quitclaim Deed.

 

H-1



 

This Corporation Quitclaim Deed shall not work a merger of the Leases conveyed hereby unless and until the foregoing power of termination shall expire or otherwise terminate.

 

Dated this            day of                           , 199   .

 

 

Atlantic Richfield Company,

 

a Delaware corporation

 

 

 

 

 

By

 

 

STATE OF CALIFORNIA

)

 

) ss

COUNTY OF KERN

)

 

On this            day of                                           , in the year 1991, before me, the undersigned Notary Public, personally appeared                                                       , personally known to me (or proved to me on the basis of satisfactory evidence) to be the person who executed the within instrument as the Attorney-in-Fact of the corporation therein named, ATLANTIC RICHFIELD COMPANY, and acknowledged to me that the corporation executed it.

 

WITNESS my hand and official seal.

 

 

 

 

 

Notary Public in and for said State

 

H-2



 

EXHIBIT I

 

Assembly Bill No. 227

 

CHAPTER 941

 

An act relating to tidelands and submerged lands granted by the state to the City of Long Beach, and in this connection, to amend Section 6 of Chapter 138 of the Statutes of 1964 (First Extraordinary Session), and declaring the urgency thereof, to take effect immediately.

 

[Approved by Governor October 13, 1991.  Filed with
Secretary of State October 14, 1991.]

 

LEGISLATIVE COUNSEL’S DIGEST

 

AB 227, O’Connell.  Tidelands revenues:  Long Beach.

 

(1)            Under existing law, the State Lands Commission and the City of Long Beach are required to enter into a contractors’ agreement and any other necessary contracts or agreements for the production of oil, gas, and other hydrocarbons from specified Long Beach tidelands, in accordance with prescribed requirements.

 

This bill would authorize the Commission to negotiate and execute, on behalf of the state, a contract with a private contractor and the city for the implementation of an optimized waterflood program for the Long Beach Unit, in accordance with the prescribed requirements.  The bill would specify related matters, to become operative only if the contract is executed.

 

(2)            Under existing law, any expenditure tidelands oil revenues by the City of Long Beach for capital improvements involving an amount in excess of $50,000 is subject to review by the commission in accordance with prescribed procedures.

 

This bill would increase that amount to $100,000 if the contract referred to above is executed.

 

(3)            The bill would declare that it is to take effect immediately as an urgency statute.

 

The people of the State of Chliforida do enact as follows:

 

SECTION 1.          (a) The State Lands Commission is authorized to negotiate and execute, on behalf of the State of California, a contract with a private contractor and the City of Long Beach for the implementation by the contractor and the City of Long Beach of an optimized waterflood program for the Long Beach Unit.  Neither this act nor the contract shall supersede or amend in any respect the existing contractors’ agreements for Tracts 1 and 2 of the Long Beach Unit (except to extend their terms), the Long Beach Unit Agreement, the Long Beach Unit Operating Agreement, or any other existing contract relating to the drilling for, developing, extracting, processing, taking, or removing of oil, gas, and other retention by the City of Long Beach and the state of a portion of the interest earned on the “reserve for subsidence contingencies” pursuant to Section 5, the “reserve for subsidence contingencies” will contain sufficient funds to

 

I-1


 

pay any and all of the claims, judgments, and costs enumerated in subdivision (f) of Section 4 of Chapter 138.

 

SEC. 7.            The Legislature finds and declares that the provisions of this act are necessary for the promotion of the public interest and are of statewide concern.  To the extent that any provision of this act conflicts with Chapter 138, any other provision of law, the Long Beach City Charter, or any law or ordinance of the city, the provisions of this act shall prevail.  However, nothing in this act shall limit the application of any law or regulation which is intended to protect or may protect the environment.  No person or entity shall have liability to any other person or entity by reason of the preparation, execution, or delivery of any and all contracts provided for in this act.  However, nothing in this act shall relieve any person or entity from liabilities imposed by those contracts or for operations conducted pursuant to those contracts.

 

SEC. 8.            Section 6 of Chapter 138 of the Statutes of 1964 (First Extraordinary Session) is amended to read:

 

Sec. 6.  The Legislature hereby finds that the remaining oil revenue hereinabove allocated to the City of Long Beach is needed and can be economically utilized by the city for the fulfillment of the trust uses and purposes described in the acts of 1911, 1925, and 1935 and described as follows in this act, which are hereby found to be matters of state, as distinguished from local, interest and benefit.

 

(a)            The construction, reconstruction, improvement, repair, operation and maintenance of works, lands, waterways, and facilities necessary for the harbor within the boundaries of the harbor district of the city (as those boundaries were defined on April 1, 1956).

 

(b)            The construction, reconstruction, repair, operation, and maintenance of streets, roadways, bridges, and bridge approaches within the boundaries of, or reasonably necessary to provide immediate access to, the harbor district (as such boundaries were defined on April 1, 1956).

 

(c)            The construction, reconstruction, repair, operation, and maintenance of the bulkheads, piers, earthfills, streets, roadways, bridges, bridge approaches, buildings, structures, recreational facilities, landscaping, parking lots, and other improvements on or adjacent to the Long Beach tidelands or on or adjacent to the Alamitos Beach Park Lands for the benefit and use of those tidelands or the Alamitos Beach Park Lands.

 

(d)            The construction, reconstruction, repair, operation, and maintenance of small boat harbors, marine stadiums, maritime museum, marine parks, beaches, waterways, and related facilities, on or adjacent to the Long Beach tidelands or on or adjacent to the Alamitos Beach Park Lands, or on or adjacent to aquatic recreational areas of the aforesaid nature.

 

(e)            The acquisition, filling, improvement, rehabilitation, and disposal of lands, which have, prior to January 1, 1964, been damaged by subsidence, located in the City of Long Beach westerly of Alamitos Avenue, easterly of the harbor district and southerly of Ocean Boulevard (as those streets and that district now exist).

 

I-2



 

(f)             The acquisition of property or the rendition of services reasonably necessary to the carrying out of the foregoing uses and purposes.

 

(g)            In addition to the foregoing, expenditures for any other use or purpose of state, as distinguished from purely local, interest and benefit which are in fulfillment of those trust uses and purposes described in the acts of 1911, 1925, and 1935, and which are approved in advance by the State Lands Commission.

 

(h)            As to any expenditure of oil revenue for a capital improvement involving an amount in excess of one hundred thousand dollars ($100,000) proposed to be made under subdivisions (a) to (f), inclusive, of this section, the City of Long Beach shall file with the State Lands Commission an adequate detailed description of such capital improvement not less than 60 days prior to the time of any disbursement therefor or in connection therewith.  The description shall specify, in addition, the particular subdivision or subdivisions of this section which the city deems applicable and its reasons, if necessary, for regarding such expenditure as being so authorized.  The commission shall have 60 days after the time of such filing within which to notify the city that such capital improvement is not authorized by any of such subdivisions.  In the event the commission so notifies the city, a copy of the opinion of the Attorney General (or other legal counsel of the commission) upon which such disapproval has been based shall be delivered to the city.  In the event the commission notifies the city that such capital improvement is not authorized, the city shall not disburse any oil revenue for or in connection with that capital improvement for a period of 30 days following such notice, during which period or afterwards the State Lands Commission may seek any judicial relief in any court of competent jurisdiction which it deems appropriate.

 

In order to carry out the purposes of this section and to effect a speedy determination of any disagreement between the city and the commission, the Superior Court of the State of California for the County of Los Angeles (in the event such proceeding is filed in that court) shall give any proceeding filed by the city or state under this section priority over other civil matters.

 

SEC. 9.            Sections 2 to 8, inclusive, of this act shall become operative only if the State Lands Commission executes on behalf of the State of California the contract referred to in subdivision (a) of Section 1 of this act.

 

SEC. 10.         This act is an urgency statute necessary for the immediate preservation of the public peace, health, or safety within the meaning of Article IV of the Constitution and shall go into immediate effect.  The facts constituting the necessity are:

 

In order to implement an urgently needed optimized waterflood program for the Long Beach Unit at the earliest possible time, it is necessary that this act take effect immediately.

 

I-3



 

EXHIBIT J

 

ATLANTIC RICHFIELD COMPANY

 

CERTIFICATE OF SECRETARY

 

I, Howard L. Edwards, Secretary of Atlantic Richfield Company, a Delaware corporation (the “Company”), hereby certify on behalf of the Company that the following is a true, complete and correct statement of all resolutions that are not confidential adopted by the Board of Directors of the Company relating to the authorization, execution and delivery of the Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated as of November 5, 1991, among the State of California, by and through the State Lands Commission, the City of Long Beach, the Company and ARCO Long Beach, Inc., and the other documents and agreements included as exhibits to such Agreement; such resolutions have been duly adopted by the Board of Directors of the Company, are now in full force and effect, have not been amended, modified or rescinded in any respect, and are the only resolutions of the Board of Directors of the Company with respect to such matters that are not confidential:

 

RESOLVED, that the Board of Directors hereby authorizes and approves the proposed agreement, and all exhibits thereto, with the State of California and the City of Long Beach, in the form and under the terms and conditions presented at the meeting, which agreement will settle litigation between the Company and the State of California and other parties relating to offshore oil and gas leases at Coal Oil Point, California, and be it further

 

RESOLVED, that the authorization for the settlement of the litigation with the State of California and other parties and the surrender of Coal Oil Point offshore oil and gas leases 308 and 309 is hereby approved, and be it further

 

RESOLVED, that the Chairman of the Board, President, any Executive Vice President, Senior Vice President, Vice President and Vice President of the ARCO Oil and Gas Company division of the Company are hereby severally authorized and empowered to execute and deliver said agreement, all exhibits thereto and any instrument, document or agreement ancillary to

 

J-1



 

EXHIBIT K

 

ARCO LONG BEACH, INC.

 

CERTIFICATE OF SECRETARY

 

I, Howard L. Edwards, Secretary of ARCO Long Beach, Inc., a Delaware corporation (the “Company”), hereby certify on behalf of the Company that the following is a true, complete and correct statement of all resolutions that are not confidential adopted by the Board of Directors of the Company relating to the authorization, execution and delivery of the Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated as of November 5, 1991, among the State of California, by and through the State Lands Commission, the City of Long Beach, Atlantic Richfield Company and the Company, and the other documents and agreements included as exhibits to such Agreement; such resolutions have been duly adopted by the Board of Directors of the Company, are now in full force and effect, have not been amended, modified or rescinded in any respect, and are the only resolutions of the Board of Directors of the Company with respect to such matters that are not confidential:

 

RESOLVED, that the Board of Directors hereby authorizes and approves the proposed agreement, and all exhibits thereto, with the State of California and the City of Long Beach, in the form and under the terms and conditions presented at the meeting, which agreement will provide an opportunity for the Company to pursue development of incremental oil reserves in the Long Beach Unit, California, and be it further

 

RESOLVED, that the Chairman of the Board, President, any Executive Vice President, Senior Vice President and Vice President of the Company are hereby severally authorized and empowered to execute and deliver said agreement, all exhibits thereto and any instrument, document or agreement ancillary to such agreement, such execution and delivery being the certification by the signing officer of that officer’s approval of the form, terms and conditions of the instrument, document or agreement and that the execution is the act of the Company.

 

IN WITNESS WHEREOF, I have set my hand and the official seal of the Company this            day of                                   , 1991.

 

 

 

 

 

Howard L. Edwards

 

Secretary

 

 

[CORPORATE SEAL]

 

K-2




Exhibit 10.11

 

AMENDMENT TO THE AGREEMENT FOR IMPLEMENTATION OF AN

OPTIMIZED WATERFLOOD PROGRAM FOR THE LONG BEACH UNIT

 

THIS AMENDMENT TO THE AGREEMENT FOR IMPLEMENTATION OF AN OPTIMIZED WATERFLOOD PROGRAM FOR THE LONG BEACH UNIT (this “Amendment”) is made and entered into as of the 16 day of January, 2009, by and among the State of California (the “State”), by and through the State Lands Commission ( the “SLC”), the City of Long Beach (the “City”), and Oxy Long Beach, Inc. (“OLBI”), collectively referred to herein as the “Parties.”

 

RECITALS

 

A.                                     Pursuant to Section 1 of Chapter 941 of the Statutes of 1991, the Parties or their predecessors in interest entered into the Agreement for Implementation of an Optimized Waterflood Program for the Long Beach Unit, dated as of November 5, 1991 (the “OWPA”) which, inter alia , provides for the Parties to implement an optimized waterflood program in the Long Beach Unit (“LBU”).

 

B.                                     The Parties believe that it is in their respective interests for OLBI to explore the viability of other methods of enhanced oil recovery that could potentially increase the volume of oil recovered from the LBU. If realized, the increased production would benefit all of the stakeholders in the LBU, as well as the State, which has the largest financial interest in the LBU.

 

C.                                     The California legislature has enacted enabling legislation to authorize this Amendment on behalf of the State in order to allow OLBI and the City to use other means of enhanced oil recovery at the LBU.

 

NOW, THEREFORE, in consideration of the foregoing, the mutual promises herein set forth and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, it is agreed as follows:

 

1. Defined Terms :  All terms defined in or for purposes of the LBU Agreements shall have the same meanings as used in this Amendment.

 

2. Use of Enhanced Oil Recovery .  Notwithstanding anything to the contrary in the OWPA, OLBI, pursuant to the terms and conditions set forth in the OWPA, may use all types of enhanced oil recovery consistent with good oil field practice in order to increase oil recovery in the course of implementing the optimized waterflood program for the LBU.

 

3. Enabling Legislation .  The legislation attached hereto as Exhibit I (the “Enabling Legislation”) adopted by the California Legislature and approved by the Governor of the State of California authorizes the State to enter into this Amendment. The Enabling Legislation shall be deemed to be a part of this Amendment and is hereby incorporated herein by reference.

 

4. Effectiveness of this Amendment . This Amendment shall become effective upon the date that is executed by all the Parties.

 

1



 

5. Full Force and Effect . Except as modified hereby, the OWPA remains in full force and effect.

 

IN WITNESS WHEREOF, each of the following Parties has executed this Amendment upon the date set forth opposite its name.

 

Dated:

November 5, 2008

 

 

OXY LONG BEACH, INC.

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

/s/ Frank E. Komin

 

 

 

 

Frank E. Komin

 

 

 

 

President and General Manager

 

 

 

 

 

 

 

 

 

 

Dated:

January 30, 2009

 

CITY OF LONG BEACH,

 

 

 

a municipal corporation,

 

 

 

acting in its capacity as Unit Operator

 

 

 

of the Long Beach Unit

 

 

 

 

 

 

 

 

 

 

 

 

By:

/s/ Patrick H. West

 

 

 

 

Patrick H. West

 

 

 

 

City Manager

 

 

 

 

 

 

 

 

 

 

Dated:

January 16, 2009

 

STATE OF CALIFORNIA, acting

 

 

 

through the State Lands Commission

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

/s/ Paul D. Thayer

 

 

 

 

Paul D. Thayer

 

 

 

 

Executive Officer

 

2



 

EXHIBIT I

 

BILL NUMBER: AB 2165 CHAPTERED

BILL TEXT

 

CHAPTER 446

FILED WITH SECRETARY OF STATE SEPTEMBER 27, 2008

APPROVED BY GOVERNOR SEPTEMBER 27, 2008

PASSED THE SENATE AUGUST 30, 2008

PASSED THE ASSEMBLY AUGUST 31, 2008

AMENDED IN SENATE AUGUST 26, 2008

AMENDED IN SENATE AUGUST 18, 2008

AMENDED IN SENATE JUNE 25, 2008

AMENDED IN ASSEMBLY APRIL 7, 2008

 

INTRODUCED BY Assembly Member Karnette

 

FEBRUARY 20, 2008

 

An act relating to tidelands and submerged lands granted by the state to the City of Long Beach, and declaring the urgency thereof, to take effect immediately.

 

LEGISLATIVE COUNSEL’S DIGEST

 

AB 2165, Karnette. Tidelands and submerged land: City of Long Beach: oil reserves.

 

Under existing law, the State Lands Commission and the City of Long Beach are required to enter into a contractors’ agreement and any other necessary contracts or agreements for the production of oil, gas, and other hydrocarbons from specified Long Beach tidelands, in accordance with prescribed requirements.

 

This bill would authorize the commission to negotiate and execute, on behalf of the state, a contract with the City of Long Beach and its tidelands oil operating contractor, that provides financial incentives for the contractor to explore for and develop additional oil reserves beneath the tidelands and submerged lands covering specified parcels in a certain oil field.

 

The bill would, with respect to that contract and the development of additional oil reserves, provide for the sharing of revenues among the state, the City of Long Beach, and the contractor, and the payment of and purposes for which the revenues may be used. The bill would also authorize the extension of the term of a related contract.

 

This bill would declare that it is to take effect immediately as an urgency statute.

 

1



 

THE PEOPLE OF THE STATE OF CALIFORNIA DO ENACT AS FOLLOWS:

 

SECTION 1. The Legislature finds and declares that the provisions of this act are necessary for the promotion of the public interest and are of statewide concern.

 

SEC. 2. The State Lands Commission is authorized to negotiate and execute on behalf of the State of California a contract with the City of Long Beach and its tidelands oil operating contractor, that provides financial incentives for the contractor to explore for and develop  additional oil reserves beneath the tidelands and submerged lands, whether unitized or nonunitized, covered by the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract and beneath the uplands parcels in the Fault Block II Unit, the Fault Block III Unit, the Fault Block IV Unit, and the Fault Block V Ranger Zone Unit in the Wilmington oil field. This act and any contract entered into pursuant to this act shall not supersede or amend the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract except to extend its term as provided in Section 4. Furthermore, neither this act nor any contract entered into pursuant to this act shall supersede or amend the Unit Agreements or Unit Operating Agreements for the Fault Block II Unit, the Fault Block III Unit, the Fault Block IV Unit, or the Fault Block V Ranger Zone Unit, or any other contract relating to the drilling for, developing, extracting, processing, taking, or removing of oil, gas, and other hydrocarbons from the tide and submerged lands and uplands parcels referred to in this section.

 

SEC. 3. The contract entered into pursuant to Section 2 shall provide for the preservation of the current method for sharing among the contractor, the State of California, and the City of Long Beach of revenues from the sale of production under the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract with regard to all current oil reserves. The contract shall provide a means responsive to the market price of crude oil for determining the additional oil reserves and a method for sharing the revenues from the development of these additional oil reserves among the State of California, the City of Long Beach, and the contractor that will provide both an economic incentive to the contractor to pursue the development of these additional oil reserves and a fair and equitable return to the State of California and the City of Long Beach. The contract shall require the contractor to spend an amount to be negotiated for geologic and engineering evaluation and development in any oil and gas zones beneath the tide and submerged lands covered by the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract. The contractor shall be required to prepare, on a regular and continuing basis, plans and budgets for the exploration for and development of the additional oil reserves. The staff of the State Lands Commission shall be permitted to review these plans and budgets for consistency with good oil field practice, compliance with the goals of the program for the development of additional oil reserves, and responsiveness to environmental and safety concerns. The contract shall permit the City of Long Beach, the State Lands Commission staff, and the contractor to take whatever actions may be necessary to secure the approval of the working interest owners of the determinations sought in furtherance of the exploration and development plans pursuant to the terms of the Unit Agreements and Unit Operating Agreements for the Fault Block II, Fault Block III, Fault Block IV, and Fault Block V Ranger Zone Units.

 

SEC. 4. The term of the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract may be extended upon the execution of the contract authorized in Section 2 to the time when oil, gas, or other hydrocarbons from the zones beneath the tide and submerged lands covered by the contract no longer can be produced in paying quantities, notwithstanding the termination of any or all of the Fault Block II, Fault Block III, Fault Block IV, and Fault Block V Ranger Zone

 

2



 

Units, or anything to the contrary in Chapter 1163 of the Statutes of 1991, or the Long Beach City Charter.

 

SEC. 5. Any revenue payable to the City of Long Beach solely from the sale of production of additional oil reserves under the contract authorized by Section 2 shall be paid to the City of Long Beach before the distribution of “remaining oil revenue,” as defined in Section 4 of Chapter 138 of the Statutes of 1964, First Extraordinary Session.  This additional revenue, when received by the City of Long Beach, shall be used for the purposes and in the manner set forth in Section 6 of Chapter 138 of the Statutes of 1964, First Extraordinary Session, as amended by Section 8 of Chapter 941 of the Statutes of 1991.

 

SEC. 6. The contractor under the contract authorized in Section 2 may use any means of enhanced oil recovery consistent with good oil field practice to develop additional oil reserves. Notwithstanding anything to the contrary in Chapter 941 of the Statutes of 1991, the contractor under the contract authorized by Section 1 of Chapter 941 of the Statutes of 1991 may use all types of enhanced oil recovery applications that are consistent with good oil field practice to increase oil recovery in the course of implementing the optimized waterflood program for the Long Beach Unit.

 

SEC. 7. Any oil extracted pursuant to Section 2 shall maintain the same environmental footprint that exists as of July 1, 2008, including limiting any new wells to the industrialized area of the Port of Long Beach or the Port of Los Angeles, and requiring that any wells drilled pursuant to Section 2 shall be drilled from an onshore location.

 

SEC. 8. To the extent any provision of this act conflicts with Chapter 138 of the Statutes of 1964 (First Extraordinary Session), Chapter 29 of the Statutes of 1956 (First Extraordinary Session), the Long Beach City Charter, or any law or ordinance of the City of Long Beach, the provisions of this act shall prevail.

 

SEC. 9. This act is an urgency statute necessary for the immediate preservation of the public peace, health, or safety within the meaning of Article IV of the Constitution and shall go into immediate effect. The facts constituting the necessity are:

 

In order to implement as soon as possible the exploration for and development of additional oil reserves that should produce more oil, prevent waste of oil and gas resources, and bring additional money to the State Treasury, it is necessary that this act take effect immediately.

 

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BILL NUMBER: AB 2165    AMENDED

BILL TEXT

 

AMENDED IN SENATE            AUGUST 26, 2008

AMENDED IN SENATE            AUGUST 18, 2008

AMENDED IN SENATE            JUNE 25, 2008

AMENDED IN ASSEMBLY APRIL 7, 2008

 

INTRODUCED BY    Assembly Member Karnette

 

FEBRUARY 20, 2008

 

An act relating to tidelands and submerged lands granted by the state to the City of Long Beach, and declaring the urgency thereof, to take effect immediately.

 

LEGISLATIVE COUNSEL’S DIGEST

 

AB 2165, as amended, Karnette. Tidelands and submerged land: City of Long Beach: oil reserves.

 

Under existing law, the State Lands Commission and the City of Long Beach are required to enter into a contractors’ agreement and any other necessary contracts or agreements for the production of oil gas, and other hydrocarbons from specified Long Beach tidelands, in accordance with prescribed requirements.

 

This bill would authorize the commission to negotiate and execute, on behalf of the state, a contract with the City of Long Beach and its tidelands oil operating contractor, that provides financial incentives for the contractor to explore for and develop additional oil reserves beneath the tidelands and submerged lands covering specified parcels in a certain oil field.

 

The bill would, with respect to that contract and the development of additional oil reserves, provide for the sharing of revenues among the state, the City of Long Beach, and the contractor, and the payment of and purposes for which the revenues may be used. The bill would also extend authorize the extension of the term of a related contract.

 

This bill would declare that it is to take effect immediately as an urgency statute.

 

Vote:  2/3. Appropriation:  no.  Fiscal committee:  yes.

 

State-mandated local program:  no.

 

THE PEOPLE OF THE STATE OF CALIFORNIA DO ENACT AS FOLLOWS:

 

SECTION 1.     The Legislature finds and declares that the provisions of this act are necessary for the promotion of the public is interest and are of statewide concern.

 

SECTION 1.     SEC. 2.         The State Lands Commission is authorized to negotiate and execute on behalf of the State of California a contract with the City of Long Beach and its tidelands oil operating contractor, that provides financial incentives for the contractor to explore for and develop additional oil reserves beneath the tidelands and submerged lands, whether unitized or nonunitized, covered by the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract and beneath the uplands parcels in the Fault Block II Unit, the Fault Block III Unit, the Fault Block IV Unit, and the Fault Block V Ranger Zone Unit in the Wilmington oil field. This act and any contract entered into pursuant to this act shall not supersede or amend the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract except to extend its term as

 

1



 

provided in Section  3 4. Furthermore, neither this act nor any contract entered into pursuant to this act shall supersede or amend the Unit Agreements or Unit Operating Agreements for the Fault Block II Unit, the Fault Block III Unit, the Fault Block IV Unit, or the Fault Block V Ranger Zone Unit, or any other contract relating to the drilling for, developing, extracting, processing, taking, or removing of oil, gas, and other hydrocarbons from the tide and submerged lands and uplands parcels referred to in this section.

 

SEC. 2.                                 The contract entered into pursuant to Section 1 shall

 

SEC. 3.                                 The contract entered into pursuant to Section 2 shall provide for the preservation of the current method for sharing among the contractor, the State of California, and the City of Long Beach of revenues from the sale of production under the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract with regard to all current oil reserves. The contract shall provide a means responsive to the market price of crude oil for determining the additional oil reserves and a method for sharing the revenues from the development of these additional oil reserves among the State of California, the City of Long Beach, and the contractor that will provide both an economic incentive to the contractor to pursue the development of these additional oil reserves and a fair and equitable return to the State of California and the City of Long Beach. The contract shall require the contractor to spend an amount to be negotiated for geologic and engineering evaluation and development in any oil and gas zones beneath the tide and submerged lands covered by the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract. The contractor shall be required to prepare, on a regular and continuing basis, plans and budgets for the exploration for and development of the additional oil reserves. The staff of the State Lands Commission shall be permitted to review these plans and budgets for consistency with good oil field practice, compliance with the goals of the program for the development of additional oil reserves, and responsiveness to environmental and safety concerns. The contract shall permit. the City of Long Beach, the State Lands Commission staff, and the contractor to take whatever actions may be necessary to secure the approval of the working interest owners of the determinations sought in furtherance of the exploration and development plans pursuant to the terms of the Unit Agreements and Unit Operating Agreements for the Fault Block II, Fault Block III, Fault Block IV, and Fault Block V Ranger Zone Units.

 

SEC 3.                                    SEC. 4.         The term of the Long Beach Harbor Tidelands Parcel and Parcel “A” Oil Contract shall may be extended upon the execution of the contract authorized in Section  1 2 to the time when oil, gas, or other hydrocarbons from the zones beneath the tide and submerged lands covered by the contract no longer can be produced in paying quantities, notwithstanding the termination of any or all of the Fault Block II, Fault Block III, Fault Block IV, and Fault Block V Ranger Zone Units, or anything to the contrary in Chapter 1163 of the Statutes of 1991, Chapter 138 of the Statutes of 1964 (First Extraordinary Session), Chapter 29 of the Statutes of 1956 (First Extraordinary Session), any other provision of state law, the Long Beach City Charter, or any law or ordinance of the City of Long Beach in Chapter 1163 of the Statutes of 1991, or the Long Beach City Charter.

 

SEC. 4.                                 SEC. 5.         Any revenue payable to the City of Long Beach solely from the sale of production of additional oil reserves under the contract authorized by Section  1 2 shall be paid to the City of Long Beach before the distribution of “remaining oil revenue,” as defined in Section 4 of Chapter 138 of the Statutes of 1964, First Extraordinary Session. This additional revenue, when received by the City of Long Beach, shall be used for the purposes and in the manner set forth in Section 6 of Chapter 138 of the Statutes of 1964, First Extraordinary Session, as amended by Section 8 of Chapter 941 of the Statutes of 1991.

 

2



 

SEC. 5.                                 SEC. 6.         The contractor under the contract authorized in Section  1 2 may use any means of enhanced oil recovery consistent with good oil field practice to develop additional oil reserves. Notwithstanding anything to the contrary in Chapter 941 of the Statutes of 1991, the contractor under the contract authorized by Section 1 of Chapter 941 of the Statutes of 1991 may use all types of enhanced oil recovery applications that are consistent with good oil field practice to increase oil recovery in the course of implementing the optimized waterflood program for the Long Beach Unit.

 

SEC. 6.                                 Any oil extracted pursuant to Section 1 shall maintain

 

SEC. 7.                                 Any oil extracted pursuant to Section 2 shall maintain the same environmental footprint that exists as of July 1, 2008, including limiting any new wells to the industrialized area of the Port of Long Beach or the Port of Los Angeles, and requiring that any wells drilled pursuant to Section  1 2 shall be drilled from an onshore location.

 

SEC. 8.                                 To the extent any provision of this act conflicts with Chapter 138 of the Statutes of 1964 (First Extraordinary Session), Chapter 29 of the Statutes of 1956 (First Extraordinary Session), the Long Beach City Charter, or any law or ordinance of the City of Long Beach, the provisions of this act shall prevail.

 

SEC. 7.                                 SEC. 9.         This act is an urgency statute necessary for the immediate preservation of the public peace, health, or safety within the meaning of Article IV of the Constitution and shall go into immediate effect. The facts constituting the necessity are:

 

In order to implement as soon as possible the exploration for and development of additional oil reserves that should produce more oil, prevent waste of oil and gas resources, and bring additional money to the State Treasury, it is necessary that this act take effect immediately.

 

3




Exhibit 10.12

 

CONTRACTORS’ AGREEMENT
LONG BEACH UNIT
WILMINGTON OIL FIELD, CALIFORNIA

 

TABLE OF CONTENTS

 

 

 

Page Number

 

 

 

RECITALS

 

2

ARTICLE 1

- DEFINITIONS

2

a

.

Unitization Agreement Terms

2

b

.

Advance Royalty Period

2

c

.

Bid Percentage

3

d

.

City Manager

3

e

.

Continuing Purchaser

3

f

.

Contractor

3

g

.

Contract Lands

3

h

.

Contractor’s Percentage

3

i

.

Current Operating Profits

3

j

.

Named Fields

4

k

.

Net Profits Account

4

l

.

Net Profits Attributable

4

m

.

Oil Allocated

4

n

.

Oil Allocated to the Contract Lands

4

o

.

Payment, Contribution or Subsidy

4

p

.

Persons Comprising

4

q

.

Plans of Development and Operation

4

r

.

Persons Having an Interest in any Contractor

5

s

.

Prices Paid

5

t

.

Purchases of Oil

5

u

.

Substantial Purchaser

6

v

.

Total Value of Oil and Gas Allocated to the Contract Lands

6

w

.

Unit Agreement

6

x

.

Unit Operating Agreement

6

y

.

Value of Oil Allocated

7

z

.

Value of Wet Gas Products Attributable

7

 



 

aa

.

Wet Gas Allocated

7

bb

.

Wet Gas Products

7

cc

.

Wet Gas Products Attributable

7

dd

.

Wet Gas Products Attributable to the Contract Lands

7

ARTICLE 2

 - CREATION OF UNDIVIDED SHARES IN THE CONTRACT LANDS

7

ARTICLE 3

 - TERM

8

ARTICLE 4

 - CONTRACTORS’ NET PROFITS

8

(a

)

The Net Profits Accounts

8

 

 

(1)      Credits

 

8

 

 

(2)      Charges

 

9

(b

)

Net Profits Computation

10

ARTICLE 5

 - FIELD CONTRACTOR’S PAYMENTS TO THE CITY

10

(a

)

Advance Royalty Period

10

(b

)

Subsequent Payments

13

(c

)

Minimum Payments

13

(d

)

Excess Value

14

ARTICLE 6

 - NONOPERATING CONTRACTORS’ PAYMENTS TO CITY

14

ARTICLE 7

 - RESERVE FOR SUBSIDENCE CONTINGENCIES

15

ARTICLE 8

 - TERMINATION BY THE CONTRACTORS

16

ARTICLE 9

 - CRUDE OIL

18

(a

)

General Provision

18

(b

)

Valuation Applicable to all Contractors

18

(c

)

Valuation Applicable to Certain Contractors

21

(d

)

Information

22

(e

)

Review and Adjustment

23

(f

)

Public Law 31

23

(g

)

Cut Back

24

ARTICLE 1

0 - GAS PROCESSING AND VALUE

24

ARTICLE 1

1 - SELL OFF OF OIL

26

(a

)

Twelve and one-half percent (12-1/2%) Sell Off

26

(b

)

Sell-Off of Excess Over Sixty-Seven and One-Half Percent (67-1/2%)

27

ARTICLE 1

2 - FIELD CONTRACTOR’S EXCLUSIVE RIGHT TO OPERATE

28

ARTICLE 1

3 - OPERATING COMMITTEE

29

ARTICLE 1

4 - SUPERVISION BY CITY MANAGER

30

 



 

ARTICLE 1

5 - FIELD CONTRACTOR’S EMPLOYEES

32

ARTICLE 1

6 - CONTRACTORS’ RIGHT OF REIMBURSEMENT LIMITED

32

ARTICLE 1

7 - EXCLUDED RECEIPTS

33

ARTICLE 1

8 - TAXES

34

ARTICLE 1

9 - OWNERSHIP OF UNIT FACILITIES

34

ARTICLE 2

0 - BILLS, BUDGETS AND ADVANCES

35

(a

)

Obligations of all Contractors

35

(b

)

Obligations of Field Contractor

36

(c

)

Advances by Participants

38

ARTICLE 2

1 - AUDITS

39

ARTICLE 2

2 - RELATIONSHIP OF PARTIES

39

ARTICLE 2

3 - WARRANTY

40

ARTICLE 2

4 - LITIGATION

41

ARTICLE 2

5 - ASSIGNMENT

41

ARTICLE 2

6 - BANKRUPTCY

42

ARTICLE 2

7 - COMPLIANCE WITH THE CITY ORDINANCE AND CHAPTER 138

43

ARTICLE 2

8 - COMPLIANCE WITH LAWS

44

ARTICLE 2

9 - MECHANICS’ LIENS

46

ARTICLE 3

0 - DEFAULT

47

ARTICLE 3

1 - INDEMNITY AND INSURANCE

48

(a

)

Indemnity

48

(b

)

Insurance

49

ARTICLE 3

2 - BONDS

50

ARTICLE 3

3 - FORCE MAJEURE

52

ARTICLE 3

4 - REFORMATION TO CONFORM TO APPLICABLE LAW

52

ARTICLE 3

5 - CONTRACTORS MAY CONSIST OF SEVERAL PERSONS

53

ARTICLE 3

6 - NOTICES

53

ARTICLE 3

7 - GENDER AND HEADINGS

53

ARTICLE 3

8 - SUCCESSORS AND ASSIGNS

54

ARTICLE 3

9 - COUNTERPARTS

54

 



 

CONTRACTORS’ AGREEMENT
LONG BEACH UNIT
WILMINGTON OIL FIELD, CALIFORNIA

 

This Contractors’ Agreement is entered into by and

 

BETWEEN

 

CITY OF LONG BEACH, a municipal corporation, hereinafter referred to as “City”

 

 

 

AND

 

HUMBLE OIL & REFINING COMPANY, SHELL OIL COMPANY, SOCONY MOBIL OIL COMPANY, INC., TEXACO, INC., and UNION OIL COMPANY OF CALIFORNIA, hereinafter referred to, collectively, as the “Field Contractor”

 

 

 

AND

 

PAULEY PETROLEUM, INC., and ALLIED CHEMICAL CORPORATION, hereinafter referred to, collectively, as the “Nonoperating Contractor with a Ten Percent (10%) Contractor’s Percentage”

 

 

 

AND

 

RICHFIELD OIL CORPORATION and STANDARD OIL COMPANY OF CALIFORNIA, hereinafter referred to, collectively, as the “Nonoperating Contractor with a Five Percent (5%) Contractor’s Percentage”

 

 

 

AND

 

RICHFIELD OIL CORPORATION and STANDARD OIL COMPANY OF CALIFORNIA, hereinafter referred to, collectively, as the “Nonoperating Contractor with a Two and One-half Percent (2-1/2%) Contractor’s Percentage”

 

 

 

AND

 

RICHFIELD OIL CORPORATION and STANDARD OIL COMPANY OF CALIFORNIA, hereinafter referred to, collectively, as the “Nonoperating Contractor with a One and One-half Percent (1-1/2%) Contractor’s Percentage”

 

 

 

AND

 

RICHFIELD OIL CORPORATION and STANDARD OIL COMPANY OF CALIFORNIA, hereinafter referred to, collectively, as the “Nonoperating Contractor with a One Percent (1%) Contractor’s Percentage”

 

1



 

RECITALS

 

The City, the State, and other Persons, have negotiated the unitization of the Long Beach Unit, Wilmington Oil Field, California. Under the terms of the Unit Operating Agreement the City is named as Unit Operator. The purpose of this agreement is to set forth the terms and conditions under which the Field Contractor will assume responsibility for day-to-day operations, under the direction and control of the City, of the Contract Lands, and all Committed Parcels, and to set forth the respective rights and obligations of the Field Contractor, the Nonoperating Contractors, and the City with respect to the Oil and Gas allocated or assigned to the Contract Lands, and with respect to the costs of exploration, development and operation attributable to said lands.

 

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements herein contained, and the payment by the Field Contractor to the City at or before the execution of this agreement of the sum of ten million dollars ($10,000,000), as an initial consideration, in cash, for Field Contractor’s undivided share hereunder, paid in accordance with the notice inviting bids for such undivided share, receipt of which is hereby acknowledged by City, it is agreed as follows:

 

Article 1.                                                 DEFINITIONS

 

As used in this agreement, the terms hereinafter set forth shall have the following meanings:

 

a.                                       Unitization Agreement Terms . Terms used in this agreement which are the same as the terms defined in the Unitization Agreements shall have the same meanings as the meanings of those terms in such Unitization Agreements, except as follows: The words “approval,” “determination” and “establish” as used herein (whether as nouns or verbs) shall have their normal meanings, and shall not have the defined meanings set forth in the Unitization Agreements unless the context so requires. The word “Person” means and includes any firm, corporation, association, partnership or natural person.

 

b.                                       Advance Royalty Period means that period commencing on the first day of the first calendar month which begins on or after the one hundred and twentieth (120th) day after the effective date of this agreement, and terminating at the time the City has the right to receive payments from the Field Contractor based upon the Field Contractor’s Bid Percentage of Net

 

2



 

Profits Attributable to Field Contractor pursuant to Section 5(b) hereof, or at the end of the sixtieth (60th) calendar month after the effective date of this agreement, whichever is earlier.

 

c.                                        Bid Percentage of any Contractor means the percentage of Net Profits Attributable to such Contractor set forth in such Contractor’s successful bid for its Contractor’s Percentage undivided share under this agreement.

 

d.                                       City Manager means the City Manager of the City of Long Beach or any other public officer designated to carry out the functions of the City Manager hereunder.

 

e.                                        Continuing Purchaser means any Person who has, as determined on the basis of all available reliable information, made Purchases of Oil in the Named Fields of an average amount of oil per day during each of the preceding twelve (12) calendar months equal to or exceeding the higher of the following:

 

(1)                                  one thousand (1000) barrels; or

 

(2)                                  (after there has been at least one (1) full calendar year of production hereunder) two and one-half percent (2-1/2%) of the average daily amount of the Tract Allocation of oil to Tract No. 1, during the preceding calendar year, up to but not exceeding three thousand (3000) barrels.

 

f.                                         Contractor means and includes the Field Contractor and each Nonoperating Contractor.  All such contractors are herein called “the Contractors.”

 

g.                                        Contract Lands means the City’s portion of the Off-shore Area ( i.e. , the “undeveloped portion of the Long Beach tidelands” described in Section 1(f) of Chapter 138), and includes Tract No. 1.

 

h.                                       Contractor’s Percentage means the percentage undivided share of a Contractor hereunder in the Unitized Substances assigned or allocated to Tract No. 1, namely, eighty percent (80%) as to the Field Contractor, and ten percent (10%), five percent (5%), two and one-half percent (2-1/2%), one and one-half percent (1-1/2%), and one percent (1%), respectively, as to the Nonoperating Contractors.

 

i.                                           Current Operating Profits attributable to any Contractor for any calendar month means the excess of the Value of Oil Allocated to such Contractor during such month plus the Value of Wet Gas Products Attributable to such Contractor during such month over and above such Contractor’s Percentage of the Operating Costs attributable to Tract No. 1 during such month.

 

3



 

j.                                          Named Fields means the Field and the Huntington Beach, Inglewood, and Signal Hill (or Long Beach) oil fields.

 

k.                                       Net Profits Account of any Contractor means the account provided for as to such Contractor in Article 4 hereof.

 

l.                                           Net Profits Attributable to any Contractor as of the end of any calendar month means the credit balance in such Contractor’s Net Profits Account computed as of the end of such calendar month, which balance reflects total net profits attributable to such Contractor from the effective date of this agreement to such time.

 

m.                                   Oil Allocated to any Contractor means such Contractor’s Participant Allocation of oil attributable to such Contractor’s Working interest in Tract No. 1 or, stated otherwise, such Contractor’s Percentage of the sum of the Participant Allocations of oil attributable to the Contract Lands.

 

n.                                       Oil Allocated to the Contract Lands means the sum of the Participant Allocations of oil attributable to the Contract Lands.

 

o.                                       Payment, Contribution or Subsidy received by Field Contractor or any Nonoperating Contractor shall mean any amounts received by Field Contractor or any Nonoperating Contractor as payment, contribution, or subsidy in connection with operations under this agreement; excluding, however, any amounts which are not to be credited to Field Contractor’s or any Nonoperating Contractor’s Net Profits Account under the terms hereof, any amounts received by any Contractor as consideration for Oil Allocated to such Contractor or Wet Gas Products Attributable to such Contractor, any amount received by any Contractor as consideration for any assignment, hypothecation or pledge of its right to receive oil or Wet Gas Products hereunder made pursuant to Article 25 hereof, any compensation for processing Wet Gas Allocated to such Contractor, and any amount credited to such Contractor’s Net Profits Account other than as Payment, Contribution or Subsidy.

 

p.                                       Persons Comprising any Contractor means and includes each Person joining in a successful joint bid for such Contractor’s Percentage undivided share under this agreement, and each such Person’s heirs, administrators, executors, successors or assigns.

 

q.                                       Plans of Development and Operation means the initial and all subsequent plans of development and operation adopted in accordance with the provisions of Article 4 of the Unit Agreement and Section 5 of Chapter 138.

 

4



 

r.                                          Persons Having an Interest in any Contractor means and includes any of the Persons Comprising such Contractor, and any Person who, by means of stock ownership or otherwise, owns, directly or indirectly, ten percent (10%) or more of any Contractor’s Percentage undivided share under this agreement.

 

s.                                         Prices Paid for oil means consideration given for the crude oil itself at the point of delivery within the field in which it was produced, and shall not include consideration for any transportation beyond that point.

 

t.                                          Purchases of Oil means all purchases of crude oil, except that it shall not include the following:

 

(1)                                  Acquisitions of royalty oil by an owner of a Working Interest at a price or value determined in accordance with Lease terms, provided that acquisitions of royalty oil by any lessee of the State in tide and submerged lands in the Field or the Huntington Beach Field, but outside the original Unit Area, shall, except for purposes of Section 9(c) hereof, be deemed “Purchases of Oil” by such lessees at the prices at which such lessees account to the State for such royalty oil;

 

(2)                                  Acquisitions of oil (but not purchases of oil from) the State’s contractor or lessee pursuant to the Tract No. 2 agreement or any new Lease covering Tract No. 2, in whole or in part;

 

(3)                                  Acquisitions of oil by (but not purchases of oil from) the City’s Contractor under the Drilling and Operating Contract (Long Beach Harbor Tidelands Parcel)(1) and purchases of oil pursuant to the terms of the Drilling and Operating Contract, (Parcel “A”)(2) issued by the City of Long Beach, or any acquisitions or purchases of oil valued or priced pursuant to the terms of any new Lease covering either said Parcel, in whole or in part;

 

(4)                                  Purchases of oil by competitive bidders pursuant to Article 11 hereof, during, and only during, any period in which the price of such oil is computed by reference to the valuation of Oil Allocated to the Field Contractor, so that both computations would be interdependent absent this exception;

 


(1)  Contract No. 2001 in the files of the City Clerk of the City of Long Beach

(2)  Contract No. 2935 in the files of the City Clerk of the City of Long Beach

 

5


 

(5)                                  Exchanges of oil for other Oil or Gas or other products extracted or manufactured from Oil or Gas or for other property or services;

 

(6)                                  Purchases at an artificially high price; provided a purchase shall be so deemed if and when, and only if and when, a party hereto can show that he has offered to sell to such purchaser at a lower price oil of like quantity, gravity and quality and under like terms and conditions (other than price) and that such purchaser has nevertheless, subsequent to such offer and while such offer was still in effect, purchased other oil at a price higher than such offer other than pursuant to a pre-existing binding contractual obligation of thirty (30) days or less;

 

(7)                                  Purchases at an artificially low price; provided that a purchase shall be so deemed if, and only if, the price thereof is lower than the lowest price posted, by a Continuing Purchaser, in the field in which it is made; and such purchase is made by any Contractor or any Person Having an Interest in any Contractor.

 

(8)                                  Purchases from any person other than a Person acquiring such oil in its capacity as an owner of a Working Interest or a Royalty Interest in the lands from which the crude oil was produced.

 

u.                                       Substantial Purchaser means any Person who has, as determined on the basis of all available reliable information, made Purchases of Oil in the Named Fields of an average amount of oil during each of the preceding twelve (12) calendar months of three hundred (300) barrels per day, or more.

 

v.                                       Total Value of Oil and Gas Allocated to the Contract Lands at any time means the cumulative total value, computed in accordance with the provisions of Section 9(b) hereof, of the Oil Allocated to the Contract Lands and the Wet Gas Products Attributable to the Contract Lands from the effective date of this agreement to such time.

 

w.                                     Unit Agreement means that certain agreement entitled “Unit Agreement, Long Beach Unit, California,” effective as of the same date as this agreement, and all exhibits thereto.

 

x.                                       Unit Operating Agreement means that certain agreement entitled “Unit Operating Agreement, Long Beach Unit, California,” effective as of the same date as this agreement, and all exhibits thereto.

 

6



 

y.                                       Value of Oil Allocated to any Contractor means the value of Oil Allocated to such Contractor, computed in accordance with the provisions of Article 9 hereof.

 

z.                                        Value of Wet Gas Products Attributable to any Contractor means the value of Wet Gas Products Attributable to such Contractor, computed in accordance with the provisions of Article 10 hereof.

 

aa.                                Wet Gas Allocated to any Contractor means such Contractor’s Participant Allocation of Wet Gas attributable to such Contractor’s Working Interest in Tract No. 1 or, stated otherwise, such Contractor’s Percentage of the sum of the Participant Allocations of Wet Gas attributable to the Contract Lands.

 

bb.                                Wet Gas Products means natural gasoline and other liquid and liquefied hydrocarbon products.

 

cc.                                  Wet Gas Products Attributable to any Contractor means the Wet Gas Products Extracted from the Wet Gas Allocated to such Contractor, less all compensation retained by treaters of such Wet Gas pursuant to Article 10 hereof.

 

dd.                                Wet Gas Products Attributable to the Contract Lands means the Wet Gas Products extracted from the sum of the Participant Allocations of Wet Gas attributable to the Contract Lands, less all compensation retained by treaters of such Wet Gas pursuant to Article 10 hereof.

 

Article 2.                                                 CREATION OF UNDIVIDED SHARES IN THE CONTRACT LANDS

 

The Unitized Substances assigned or allocated to the Contract Lands are hereby divided into six undivided shares as follows: The Field Contractor shall have an eighty percent (80%) share and the Nonoperating Contractors shall have ten percent (10%), five percent (5%), two and one-half percent (2-1/2%), one and one-half percent (1-1/2%) and one percent (1%) shares, respectively.

 

Each Contractor shall execute and become bound by the Unit Agreement and the Unit Operating Agreement as a Working Interest Owner in the Contract Lands and a Participant as to Tract No. 1 with a Tract Participation Share equal to such Contractor’s Percentage of the Tract Participation of Tract No. 1; provided that the City, subject to the terms of the Unitization Agreements and Chapter 138, shall have the sole right to vote the entire Working Interest assigned to the Contract Lands. Each Contractor agrees to perform fully and faithfully every

 

7



 

obligation imposed upon it as a Working Interest Owner in the Contract Lands and Participant in Tract No. 1 under the terms of the Unitization Agreements.

 

Article 3.                                                 TERM

 

The term of this agreement shall be for a period of thirty-five (35) years as to each Contractor, unless sooner terminated as to any Contractor in accordance with the provisions hereof, commencing as of the effective date of the Unit Agreement; provided, however, that if the Unit Agreement is not effective as of January 1, 1967 this agreement shall be null and void, the initial consideration paid to the City by the Field Contractor shall be repaid to the Field Contractor, and all rights, obligations and liabilities of the parties hereto shall cease and be deemed fully discharged.

 

In the event this agreement should, for any reason, terminate as to any Contractor prior to the final termination of this agreement as to all Contractors, the remaining Contractors agree that such terminating Contractor’s rights, duties and obligations hereunder may be assumed, exercised and enjoyed by any Person or Persons succeeding to or acquiring the undivided share of such Contractor as to which this agreement has so terminated.

 

Article 4.                                                 CONTRACTORS’ NET PROFITS

 

(a)                                  The Net Profits Accounts

 

A Contractor’s Net Profits Account shall be established for each Contractor as of the effective date of this agreement.

 

(1)                                  Credits - Each Contractor’s Net Profits Account shall be credited with the following:

 

(a)                                  The total Value of Oil Allocated to such Contractor;

 

(b)                                  The total Value of Wet Gas Products Attributable to such Contractor;

 

(c)                                   Such Contractor’s Unit Participation share, attributable to its Working Interest in the Contract Lands, of the net salvage value of Unit Facilities at the termination of the Unit Agreement, if this agreement does not terminate as to all Contractors or as to such Contractor prior to the termination of the Unit Agreement;

 

8



 

(d)                                  The total of all amounts, if any, received by such Contractor as Payment, Contribution or Subsidy; provided that each Contractor shall immediately notify the City Manager of any and all amounts received by it as Payment, Contribution or Subsidy.

 

(e)                                   The total of all amounts received by such Contractor pursuant to the provisions of the Unit Operating Agreement for the adjustment of either the Value of Tangible Property or taxes attributable to such Contractor’s Working Interest in the Contract Lands, or any other cash adjustment pursuant to the terms of the Unitization Agreements attributable to such Contractor’s Working Interest in the Contract Lands.

 

(f)                                    The total of all amounts paid over to such Contractor out of the “reserve for subsidence contingencies” provided for in Article 7 hereof.

 

(2)                                  Charges - Each Contractor’s Net Profits Account shall be charged with the following:

 

(a)                                  Such Contractor’s Percentage of the amount of all Unit Expense attributable to the Contract Lands, except as otherwise expressly provided herein;

 

(b)                                  Such Contractor’s Percentage of the total amount of all taxes, assessments and governmental charges payable by the Contractors as Participants in the Contract Lands under the terms of the Unitization Agreements, and any additional taxes, assessments and governmental charges payable under Article 18 hereof other than those payable by the Contractors as Participants in the Contract Lands under the terms of the Unitization Agreements;

 

(c)                                   The total of all amounts paid by such Contractor pursuant to the provisions of the Unit Operating Agreement for the adjustment of either the Value of Tangible Property or taxes attributable to such Contractor’s Working Interest in the Contract Lands, or any other cash adjustment pursuant to the terms of the Unitization Agreements attributable to such Contractor’s Working interest in the Contract Lands;

 

(d)                                  Such Contractor’s Percentage of costs and expenses of handling, settling or otherwise discharging claims and suits arising out of or resulting from

 

9



 

work or operations hereunder, not chargeable as Unit Expense, except as otherwise provided herein;

 

(e)                                   The actual cost of such Contractor’s bond as provided for in Article 32 hereof, not to exceed one percent (1%) per year of the principal amount of such bond;

 

(f)                                    Such Contractor’s payments into the “reserve for subsidence contingencies,” as provided for in Article 7 hereof;

 

(g)                                   Any amounts chargeable to such Contractor’s Net Profits Account by virtue of any cut back of all or any portion of the Oil Allocated to such Contractor pursuant to the provisions of Section 9(g) hereof;

 

(h)                                  Such Contractor’s Percentage of the total cost not chargeable as Unit Expense of insurance provided for in Article 30 hereof, and, except as otherwise provided herein, such Contractor’s Percentage of all other costs, charges, expenses and liabilities attributable to the Contract Lands incurred by Field Contractor at the written direction of the City Manager, as provided in this agreement and arising out of or resulting from work or operations hereunder, not chargeable as Unit Expense or otherwise chargeable to the Net Profits Account.

 

(b)                                  Net Profits Computation

 

Net Profits Attributable to each of the Contractors shall be computed as of the end of each calendar month by subtracting the amount of all charges to such Contractor’s Net Profits Account from the effective date of this agreement from the amount of all credits to such Contractor’s Net Profits Account from the effective date of this agreement, and any excess of such credits over such charges in any Contractor’s Net Profits Account shall constitute the Net Profits Attributable to such Contractor for purposes of this agreement.

 

Article 5.                                                 FIELD CONTRACTOR’S PAYMENTS TO THE CITY

 

(a)                                  Advance Royalty Period

 

Except as hereinafter provided, Field Contractor, with respect to each calendar month during the Advance Royalty Period, shall account for and pay over to the City Current Operating Profits, if any, attributable to Field Contractor for such month, to the extent of the

 

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amount set forth for such month in the following schedule (which payments are sometimes hereinafter called “current profit payments”);

 

1.                                       For the first calendar month which begins on or after the one hundred twentieth (120th) day after the effective date of this agreement; three million dollars ($3,000,000.00).

 

2.                                       For each month during the succeeding seven (7) calendar months; two million dollars ($2,000,000.00).

 

3.                                       For each subsequent calendar month remaining prior to the final termination of the Advance Royalty Period; one million dollars ($1,000,000.00).

 

Except as hereinafter provided, for each calendar month during the Advance Royalty Period as to which there are no Current Operating Profits attributable to the Field Contractor, or Current Operating Profits attributable to the Field Contractor are less than the amount set forth in the foregoing schedule for such month, the Field Contractor shall make advance royalty payments as an advance against the Oil Allocated to the Field Contractor and the Wet Gas Products Attributable to the Field Contractor, in such amount as is necessary to increase the Field Contractor’s total payment to the City for such month to the amount so scheduled.

 

The aggregate amount of all such advance royalty payments made by the Field Contractor shall be charged to an account designated as the Field Contractor’s Advance Royalty Account.

 

For any calendar month during the Advance Royalty Period as to which such Current Operating Profits attributable to the Field Contractor for such month shall exceed the amount set forth for such month in the foregoing schedule, such excess shall be retained by the Field Contractor (except as otherwise provided in Section 5(c) hereof). The entire amount of such excess (less any payments pursuant to Section 5(c)) shall be credited to the Field Contractor’s Advance Royalty Account to the extent of any unpaid balance therein.

 

The term “payments pursuant to Section 5(a)” as hereinafter used in this Article shall mean both current profit payments and advance royalty payments.  All payments pursuant to Section 5(a) shall be made to the City on or before the last day of the calendar month following the month for which such payment is made, subject to subsequent adjustment as provided in Section 9(e) hereof.

 

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For any month during the Advance Royalty Period as to which the Field Contractor’s obligation to make payments pursuant to Section 5(a) is suspended or finally terminated as hereinafter provided, the Field Contractor’s Advance Royalty Account shall be credited with Current Operating Profits, if any, attributable to the Field Contractor for such month (less any payments made pursuant to Section 5(c)) to the extent of the unpaid balance therein. The suspension or final termination during the Advance Royalty Period of the Field Contractor’s obligation to make payments pursuant to Section 5(a) shall not affect the Field Contractor’s obligation, if any, to make payments pursuant to Section 5(c) or 5(d).

 

Field Contractor’s payments pursuant to Section 5(a) shall continue, subject to the suspension and termination provisions in the following paragraph, until and only until the end of the Advance Royalty Period, i.e., until the City has the right to receive from the Field Contractor its Bid Percentage of Net Profits pursuant to Section 5(b) hereof, or at the end of the sixtieth (60th) calendar month after the effective date of this agreement, whichever is earlier, at which time the City’s right to receive payments pursuant to Section 5(a) shall terminate and shall not thereafter be revived.

 

It is recognized that the City and the State under the Unitization Agreements and applicable law, and subject to the terms thereof, have control over the rate of development of the Unit Area and the rates of production of Oil and Gas, and consequently have control over the volume of Oil and Gas Allocated to the Contract Lands. If, on the date three (3) years from the effective date of this agreement, the Advance Royalty Period has not terminated and if, for any cause (including but not limited to the causes specified in Article 33 hereof) the Oil Allocated to the Contract Lands during any of the last six (6) calendar months of such three (3) year period was less than 1,500,000 barrels, Field Contractor’s payments pursuant to Section 5(a) shall be suspended until such future time as the Oil Allocated to the Contract Lands during each month for a period of six (6) successive calendar months has been at least 1,500,000 barrels. If the Advance Royalty Period has not terminated at the end of such last mentioned period of six (6) months, then Field Contractor’s payments pursuant to Section 5(a) shall be revived and shall continue until the end of the Advance Royalty Period; provided, however, that if, after the Field Contractor’s obligation to make such payments is so revived and before Field Contractor’s Advance Royalty Account is fully paid and liquidated, the Oil Allocated to the Contract Lands is less than 1,500,000 barrels during any calendar month during the Advance Royalty Period, Field

 

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Contractor’s obligation to make payments pursuant to Section 5(a) shall terminate for the remainder of the Advance Royalty Period and shall not be again revived.

 

(b)                                  Subsequent Payments

 

Commencing with the first calendar month in which the Field Contractor’s Bid Percentage of Net Profits Attributable to the Field Contractor exceeds the total of (1) Field Contractor’s initial consideration paid at or before the execution of this agreement; (2) all prior payments pursuant to Section 5(a) made to the City by the Field Contractor; (3) all prior payments, if any, pursuant to Section 5(c) made to the City by Field Contractor; and, (4) if said calendar month occurs within the first sixty (60) months after the effective date of this agreement, One Million Dollars ($1,000,000), Field Contractor shall pay to the City with respect to such calendar month, and each calendar month thereafter during the term of this agreement, Field Contractor’s Bid Percentage of Net Profits Attributable to Field Contractor (if any), less the total of (1) Field Contractor’s said initial consideration payment; (2) all prior payments pursuant to Section 5(a) made to the City by Field Contractor; (3) all prior payments, if any, pursuant to Section 5(c) made to the City by Field Contractor; and (4) all prior payments, if any, made by Field Contractor to the City pursuant to this Section 5(b). Such payments shall be made to the City on or before the last day of the calendar month following the month for which the payment is made, subject to subsequent adjustment as provided in Section 9(e) hereof.

 

(c)                                   Minimum Payments

 

The Field Contractor shall, on a cumulative basis throughout the life of this agreement, account for and pay over to the City not less than sixteen and two-thirds percent (16 2/3%) of the value (as determined hereunder) of Field Contractor’s Percentage (i.e. eighty percent (80%)) of the oil, gas and other hydrocarbons allocated or assigned to the Contract Lands. Therefore, notwithstanding any provision to the contrary in Section 5(a) or 5(b) hereof, in respect to any calendar month during the term of this agreement as to which the payment specified in either said Section (whichever is applicable) plus any payment pursuant to Section 5(d) is insufficient to bring the total of (1) Field Contractor’s said initial consideration payment; (2) all prior payments pursuant to Section 5(a) made to the City by Field Contractor; (3) all prior payments (if any) pursuant to Section 5(b) made to the City by Field Contractor; (4) all prior payments (if any) pursuant to this Section 5(c) made to the City by Field Contractor; and (5) all prior payments (if any) pursuant to Section 5(d) made to the City by Field Contractor, to an

 

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amount equal to sixteen and two-thirds percent (16 2/3%) of Field Contractor’s Percentage (i.e., eighty percent (80%)) of the Total Value of Oil and Gas Allocated to the Contract Lands as of the end of such calendar month, Field Contractor’s payment for such calendar month shall be increased by the amount necessary to bring the total amount of all such payments by Field Contractor to such sixteen and two-thirds percent (16 2/3%) minimum.  The amounts necessary to bring Field Contractor’s total payments up to the minimum specified in the foregoing sentence are referred to in this Article       as “payments pursuant to Section 5(c).” All payments pursuant to Section 5(c) shall be made to the City on or before the last day of the calendar month following the month for which payment is made, subject to subsequent adjustment as provided in Section 9(e) hereof.

 

(d)                                  Excess Value

 

In the event the Field Contractor or any Person or Persons party to this agreement shall sell any oil by competitive bidding pursuant to the provisions of Article 11 hereof, the Field Contractor on its own behalf or the Field Contractor on behalf of such Person or Persons shall account for and pay over to the City, for each calendar month during the term of any agreement of sale pursuant to said Article 11, any bonus or excess amount received for such oil over and above the value of such oil computed in accordance with the provisions of Section 9(b) hereof. All payments pursuant to this Section 5(d) shall be made to the City on or before the last day of the calendar month following the month for which such payment is made, subject to subsequent adjustment as provided in Section 9(e) hereof. Payments made pursuant to this Section 5(d) shall not be included in any of the computations made pursuant to Sections 5(a) and 5(b) of this agreement, but shall be included in computing the cumulative minimum payment by Field Contractor specified in Section 5(c) hereof.

 

Article 6.                                                 NONOPERATING CONTRACTORS’ PAYMENTS TO CITY

 

Each Nonoperating Contractor, with respect to each calendar month during the term of this agreement, shall account for and pay over to the City one of the following two amounts, whichever shall be higher:

 

(1)                                  Such Contractor’s Bid Percentage of Net Profits Attributable to such Contractor at the end of such calendar month, less the total of all prior payments by such Contractor pursuant to this Article 6; or

 

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(2)                                  Sixteen and two-thirds percent (16 2/3%) of such Contractor’s Percentage of the Total Value of Oil and Gas Allocated to the Contract Lands as of the end of such calendar month less the total of all prior payments by such Contractor pursuant to this Article 6 (the payment specified in this subparagraph (2) being for the purpose of assuring that each Nonoperating Contractor shall, on a cumulative basis throughout the life of this agreement, account for and pay over to the City not less than sixteen and two-thirds percent (16 2/3%) of such Contractor’s Percentage of the oil, gas and other hydrocarbons allocated or assigned to the Contract Lands).

 

Such payments shall be made to the City on or before the last day of the calendar month following the month for which the payment is made, subject to subsequent adjustment as provided in Section 9(e) hereof.

 

Article 7.                                                 RESERVE FOR SUBSIDENCE CONTINGENCIES

 

In addition to the payments provided for as to Field Contractor in Article 5 hereof and as to Nonoperating Contractors in Article 6 hereof, each Contractor shall pay over to the City, in equal monthly installments, payable on the first day of each calendar month, an annual amount equal to such Contractor’s Percentage of two million dollars ($2,000,000), in compliance with the provisions of Section 4(b) of Chapter 138. Such payment shall commence from and after the first day of the second month following the termination of the Field Contractor’s Advance Royalty Period, or the final termination of the Field Contractor’s obligation to make payments pursuant to Section 5(a) hereof, whichever is earlier, and shall continue for a period of twenty (20) years thereafter. Said amounts so accumulated, but not the interest thereon, shall be treated as a cost of oil production and each such payment shall be charged to the paying Contractor’s Net Profits Account. Said amounts so accumulated, together with interest, shall be impounded by the City in a separate fund (designated as the “reserve for subsidence contingencies”) and shall be invested in bonds issued by the State of California or, if such bonds are unavailable, then in securities of the United States. Said fund shall be available to indemnify and hold harmless the City of Long Beach, the State of California, and any and all Contractors from claims, judgments and costs of defense, arising from subsidence alleged to have occurred as a result of operations under this agreement. Said fund may also be used for the purpose of paying subsidence costs or for conducting Repressuring Operations in the event there is no “oil revenue”

 

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(as such term is defined in Chapter 133) or such oil revenue is insufficient to pay such costs. Said fund shall remain impounded until such time as the City and State shall jointly determine that there is no longer any hazard of such claims or judgments or that there is no potential danger of Subsidence, whichever is later; provided, that if the City and State are unable to agree upon such a joint determination, the State Lands Commission may make application to a court of competent jurisdiction for determination by the court as to whether it is necessary to continue the impoundment of said fund. Upon termination of such impoundment, the money so impounded, including all interest and earnings thereof, shall be distributed to the City and the State as provided by Section 4(f) of Chapter 138, or as may otherwise be provided by law, at the time of such termination. Nothing herein contained shall constitute a waiver of sovereign immunity by the State of California; nor shall anything herein contained affect in any manner the rights and obligations of the City of Long Beach, the State of California, or the Contractors, or any of them, as against any other Person or Persons, relative to claims, judgments or liability arising from Subsidence of the land surface.

 

In the event the City, the State of California or any Contractor or Contractors hereunder shall incur any cost arising out of a claim or judgment, or any cost of defense, arising from Subsidence alleged to have occurred as a result of operations under this agreement, the amount or amounts of such cost (over and above the amounts, if any, covered by insurance or paid by Participants in Tracts other than Tract No. 1) shall be paid (as Unit Expense or otherwise) by all Contractors in proportion to their respective Contractor’s Percentages, and the amount so paid by each Contractor shall be charged to such Contractor’s Net Profits Account. The Contractors making any such payment shall be entitled to reimbursement therefor out of the “reserve for subsidence contingencies”; provided that in the event the balance in such “reserve for subsidence contingencies” at such time is insufficient to reimburse all such Contractors, the balance therein shall be paid over to such Contractors in proportion to their respective Contractor’s Percentages. Any amount paid to any Contractor out of the “reserve for subsidence contingencies” shall be credited to such Contractor’s Net Profits Account.

 

Article 8.                                               TERMINATION BY THE CONTRACTORS

 

(a)                                  Field Contractor may, upon one hundred eighty (180) days’ notice, terminate this agreement as to Field Contractor. Such notice may be given at any time until the end of the

 

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sixtieth (60th) calendar month after the effective date of this agreement.  Immediately upon giving any such notice Field Contractor shall be released from its obligation to make advance royalty payments for any calendar month which has not terminated at the time of giving such notice, but shall make all other payments to the City and shall enjoy and discharge all other rights and obligations of Field Contractor hereunder accruing until the end of such notice period.

 

(b)                                At any time after final Tract Assignment have been Established under the provisions of Exhibit “D” of the Unit Agreement and all adjustments pursuant to Article 11 of the Unit Operation Agreement have been completed, Field Contractor, upon one hundred eighty (180) day’s notice, and any Nonoperating Contractor, upon one hundred twenty (120) days’ notice, may terminate this agreement as to such Contractor if either of the following conditions exist:

 

1.                                       There has been a period of twelve (12) consecutive calendar months during which there have been no Net Profits Attributable to such Contractor payable to the City by such Contractor; or

 

2.                                       There has been a calendar month when there have been no Net Profits Attributable to such Contractor payable to the City by such Contractor and thereafter such Contractor in its capacity as a Participant in Tract No. 1 and a party to this agreement has advanced as Unit Expense, taxes and/or other expenses under the Unitization Agreements and/or this agreement its Contractor’s Percentage of One Million Dollars ($1,000,000.00) or more in the aggregate during a period when no further Net Profits Attributable to such Contractor become payable to the City.

 

During the notice periods specified in this Section 8(b), the Field Contractor or Nonoperating Contractor so electing to terminate will not, in its capacity as a Participant in Tract No. 1, be required to advance any money or incur any cost for Unit Expense except for Operating Costs; but shall, during such notice period, account for and pay over to the City (1) Current Operating Profits, if any, attributable to such Contractor during such period; (2) any additional amounts over and above Current Operating Profits attributable to such Contractor necessary to bring the cumulative total payments by such Contractor to the sixteen and two-thirds percent (16-2/3%) minimum specified as to Field Contractor in Section 5(c) hereof or as to any such Nonoperating Contractor in subparagraph (2) of Article 6 hereof; and (3) payments into the “reserve for subsidence contingencies” attributable to such Contractor during such period.

 

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(c)                                 Upon termination of any Contractor’s interest under this agreement, such Contractor shall cause to be recorded in the office of the County Recorder of Los Angeles County a declaration, properly acknowledged, that this agreement has terminated as to such Contractor and that such Contractor surrenders to the City its Working Interest in the Contract Lands, and its interest in Unit Facilities hereunder and as a Participant in Tract No. 1.

 

Article 9.                                                 CRUDE OIL

 

(a)                                  General Provision

 

Subject to the provisions of Article 11 hereof, each Contractor shall have the exclusive right to take and shall be obligated to take the Oil Allocated to such Contractor. All Oil Allocated to each Contractor shall be accounted for and payment made to the City on the basis of its value as computed under this Article. Delivery of all Oil Allocated to each Contractor shall be taken by such Contractor or its nominee in the manner and in accordance with the applicable provisions of the Unit Agreement and Unit Operating Agreement.

 

(b)                                Valuation Applicable to all Contractors

 

The Value of Oil Allocated to each Contractor as to each delivery thereof shall be established in accordance with one of the following four (4) standards, whichever shall be highest:

 

1.                                       The arithmetical average of the prices posted in the Field by Continuing Purchasers for oil of like gravity during the month the oil to be valued is run into the Contractor’s or nominee’s tanks and/or pipelines (weighted, in the event of a price change during such month, as to each Continuing Purchaser in accordance with the number of days each such price was posted during such month).

 

2.                                       The arithmetical average of the prices posted in the Named Fields (or in such of them in which there are prices posted by one or more Continuing Purchasers) by Continuing Purchasers for oil of like gravity during the month the oil to be valued is run into the Contractor’s or nominee’s tanks and/or pipelines (weighted in the event of a price change during such month, as to each Continuing Purchaser and as to its posting in each field, in accordance with the number of days each such price was posted during such month).

 

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3.                                       The weighted average of the Prices Paid by Substantial Purchasers for Purchases of Oil in the Field for oil of like gravity during the calendar month in which the oil to be valued is run into the Contractor’s or nominee’s tanks and/or pipelines.

 

4.                                       The weighted average of the Prices Paid by Substantial Purchasers for purchases of Oil in the Named Fields for oil of like gravity during the calendar month in which the oil to be valued is run into the Contractor’s or nominee’s tanks and/or pipelines.

 

The price for valuing each delivery of oil, as determined by any of the above methods, shall be computed to the closest tenth of each degree of API gravity and the closest tenth of a cent per barrel.

 

If, for any reason, none of the aforesaid four standards set forth in the first paragraph of this Section 9(b) are ascertainable, on the basis of all available relevant and reliable information, as to any delivery, the Value of Oil Allocated to any Contractor by such delivery shall be the actual current market price; of such oil at the point of delivery determined on the basis of all available relevant and reliable information.

 

In the event prices posted by any Continuing Purchaser in any field on any day do not include prices for all gravities of oil to be valued hereunder to the closest tenth of a degree of API gravity, the price deemed to be posted by such Continuing Purchaser on such day for oil of any gravity whose price is not actually posted in such field by such Continuing Purchaser shall be determined as follows:

 

1.                                       If such Continuing Purchaser posts prices in such field for oil of both a higher and a lower API gravity than that of any oil to be valued, the price deemed to be posted in such field by such Continuing Purchaser for such oil to be valued shall be computed to the closest tenth of each degree of API gravity and the closest tenth of a cent per barrel, by interpolating on a straight line between the nearest lower degree as to which a price is posted by such Continuing Purchaser and the nearest higher degree so posted; provided that no such interpolation shall be made if either the nearest higher or the nearest lower degree of oil as to which a price is posted is more than five degrees (5°) API gravity higher or lower than that of the oil to be valued, in which event the price of the oil to be valued will be determined by extrapolation under subparagraph (2) hereof, if either the nearest lower degree of oil or the nearest higher degree of oil as to which a price is posted is within five degrees (5°) API gravity of that of the oil to be valued.

 

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2.                                       If such Continuing Purchaser posts a price in such field for only a single gravity of oil, or if all oil as to which it posts a price is either of a higher or of a lower gravity than that of the oil to be valued, the price deemed to be posted in such field by such Continuing Purchaser for such oil to be valued shall be computed to the closest tenth of each degree of API gravity and the closest tenth of a cent per barrel, by extrapolating from such single price, or from the price of oil of the nearest gravity to that of the oil to be valued, on the basis of the then current Index of Crude Oil Prices (Schedule “C” to Exhibit “D” of the Unit Agreement), provided that no such price posted shall be extrapolated more than five degrees (5°) API gravity above or below the API gravity of the oil to be valued.

 

Any prices posted by a Continuing Purchaser in the Field or in any of the Named Fields shall be excluded from the computation of the arithmetical averages of prices posted in the Field or in the Named Fields provided for in this Section 9(b) during the first fifteen (15) days of such posting (or during the entire period thereof if less than fifteen (15) days) if it can be shown on the basis of reliable information by any party hereto or the State that such Continuing Purchaser has not, during such period, made Purchases of Oil in the oil field in question of at least fifteen thousand (15,000) barrels of oil, including a substantial quantity at the same or within five degrees (5°) API gravity of the average gravity of the Oil Allocated to the Contract Lands during such period, at a price determined on the basis of its posted prices or on the basis of an average of posted prices including its posted prices in such field; and thereafter such posted prices shall be excluded from the computation for any day if it can be shown on the basis of reliable information by any party hereto or the State that during the fifteen (15) day period immediately preceding the day for which such computation is made, such Continuing Purchaser has not made Purchases of Oil in the oil field in question of at least fifteen thousand (15,000) barrels of oil, including a substantial quantity at the same or within five degrees (5°) API gravity of the average gravity of the Oil Allocated to the Contractors during such period, at a price determined on the basis of prices posted by it in such field, or on the basis of an average of posted prices including its posted prices in such field.

 

In computing the weighted average of the Prices Paid for Purchases of Oil in the Field or in the Named Fields for oil of like gravity to that which is being valued, the following procedure shall be followed: (1) There shall first be aggregated all known Purchases of Oil by

 

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Substantial Purchasers in the Field or in the Named Fields (as the case may be) of oil having an API gravity equal to or within five degrees (5°) higher or lower than that of the oil to be valued; (2) Then the price of each such Purchase of Oil shall be weighted by multiplying such price by the number of barrels of oil purchased at such price during the month; (3) Then each price, so weighted, relating to oil of an API gravity different from that of the oil to be valued will be modified by extrapolation to the API gravity of the oil to be valued, on the basis of the then current Crude Oil Price Index (Schedule “C” to Exhibit “D” to the Unit Agreement); (4) Then the total price, so weighted and modified, of all such oil shall be divided by the number of barrels purchased during the month by means of such Purchases of Oil.

 

(c)                                 Valuation Applicable to Certain Contractors

 

If any Contractor or any of the Persons Having an Interest in any Contractor acquires oil in the Field from any other Person either by a Purchase of Oil or by an exchange of oil for other Oil or Gas or other products extracted or manufactured from Oil or Gas or for other property or services, at a price or other consideration per barrel higher than the valuation for such oil, calculated in accordance with Section 9(b) hereof, the Value of Oil Allocated to such Contractor shall include, in addition to its value computed in accordance with Section 9(b) hereof, a further amount computed as follows:

 

Such further amount shall be calculated for each day such Person making such purchase or exchange receives such purchased or exchanged oil into its tanks and/or pipelines by first valuing such Person’s share of the Oil Allocated to such Contractor on such day in accordance with the price or other consideration paid for oil of like gravity to such other Person in the Field and then subtracting the value of such Person’s share of such oil computed in accordance with Section 9(b) hereof.

 

The price or other consideration paid to such other Person in the Field shall be computed to the closest tenth of each degree of API gravity and the closest tenth of a cent per barrel. In the event the oil so purchased or received by exchange by such Person making such purchase or exchange on any day does not include all gravities of oil to be valued under this Section 9(c) to the closest tenth of a degree API gravity, the price or other consideration deemed to be paid by such Person making such purchase or exchange on any such day for oil of any gravity not actually purchased or received by exchange shall be determined by interpolation or extrapolation on the basis of the gravity or gravities of the oil purchased from or exchanged with

 

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such other Person in the Field and the price or prices or other consideration paid therefor, in accordance with the method set forth in the third full paragraph of Section 9(b) and the two subparagraphs thereof.

 

The foregoing provisions of this Section 9(c) shall not apply to the Field Contractor during the term of any agreement of sale by the Field Contractor, or by another Person or Persons party to this agreement, to a successful bidder pursuant to Article 11 hereof. All oil sold by competitive bidding pursuant to Article 11 hereof shall be valued and accounted for by the Field Contractor in accordance with its valuation computed in accordance with Section 9(b) hereof, and any excess amount or bonus received by Field Contractor, or by any Person or Persons party to this agreement, from such successful bidder shall be accounted for and paid over to the City as provided in Section 5(d) hereof.

 

(d)                                Information

 

Each Contractor and each Person Comprising any Contractor, hereby agrees to furnish to the City or the State, upon request, the following:

 

1.                                       A current and accurate (to the extent practicable) valuation schedule based upon information available to such Contractor or such Person, covering all gravities of oil available for delivery in the Field, computed to the nearest tenth of a degree API gravity and the nearest tenth of a cent in accordance with the provisions of Section 9(b) hereof, including a specification of all calculations upon which such schedule is based.

 

2.                                       A current and accurate list of all purchases and sales of oil by such Contractor, and by all of the Persons Having an Interest in such Contractor, in each of the Named Fields, including a specification of quantities, delivery dates, prices (including any premiums and bonuses), gravities, and names of sellers and purchasers.

 

Each Contractor and each Person Comprising any Contractor shall permit authorized representatives of the City and the State of California to examine relevant books, ledgers, accounts, correspondence, memoranda and other records in the possession of or under control of such Contractor and Persons Comprising any Contractor (and, to the extent it is within their power, those of Persons Having an Interest in any Contractor) for the purpose of obtaining and confirming information relevant to or necessary for the implementation of the valuation provisions contained in this Article 9 and in Article 10 hereof.

 

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(e)                                 Review and Adjustment

 

Each Contractor shall make payments currently to the City, as provided in this agreement, on the basis of the Value of the Oil Allocated to such Contractor determined on the basis of posted prices as set forth in subparagraph (1) or subparagraph (2) of the first full paragraph of Section 9(b) hereof, whichever shall be higher. At any time within nine (9) months after the end of each calendar year (or any fiscal year agreed upon between any Contractor and the City) during the term of this agreement, the City shall review and, if necessary adjust, the Value of Oil Allocated to each Contractor during such year on the basis of all available relevant and reliable information, for the purpose of determining whether any Contractor is required to account for any further Value of Oil Allocated to such Contractor under the terms of subparagraph (3) or (4) of said first full paragraph of Section 9(b) hereof, or under the provisions of Section 9(c) hereof. Any Contractor or the State, may require the City to make a review and, if necessary an adjustment, on the basis of all available relevant and reliable information, at any time within nine (9) months after the end of any such calendar (or fiscal) year of the Value of Oil Allocated to Contractors during such year and the proper application of the provisions of this Article 9.

 

Each Contractor and the City shall pay or repay to the party entitled thereto any amount or amounts necessary to make the adjustments herein provided. After making any payment required by the City pursuant hereto to which any Contractor objects, or after the City’s refusal to make any adjustment which any Contractor requests, such Contractor may, after ninety (90) days’ notice to the City, bring an action against the City before a judge or judges of a court of competent jurisdiction for an adjudication on the basis of all reliable information then available pertaining to the matter at issue, for the recovery of all or any part of any amount paid pursuant to any adjustment hereunder, or for the recovery of any amount as to which the City has refused to make such an adjustment.

 

(f)                                  Public Law 31

 

Pursuant to Public Law 31, 83rd Congress, Chapter 65, 1st Session, in time of war when necessary for national defense, and the Congress or the President shall so prescribe, the United States shall have the right of first refusal to purchase, at the prevailing market price, all or any portion of the oil to be taken and accounted for under this agreement or to acquire and use any portion of the Contract Lands by proceeding in accordance with due process of law and paying just compensation therefor. If the United States exercises such right to purchase any

 

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portion of the Oil Allocated to any Contractor, then the price paid by the United States for such oil shall be used in valuing such portion of the Oil Allocated to such Contractor under this agreement in lieu of any other provision of this Article otherwise applicable.

 

(g)                                 Cut Back

 

In the event any Contractor shall fail to take delivery of its Participant Allocation of oil attributable to its Working Interest in Tract No. 1 and if there shall be a decision to cut back all or part of such Contractor’s said Participant Allocation as provided in Section 5.14 of the Unit Agreement, such Contractor shall nevertheless continue to pay its Contractor’s Percentage of all Unit Expense and taxes attributable to Tract No. 1 and all additional costs chargeable to such Contractor under this agreement, and such Contractor’s Net Profits Account shall be credited with the oil so cut back as if such oil had actually been delivered to such Contractor; provided that nothing herein shall affect any rights at law or in equity which such Contractor may have as against the City by virtue of the net benefit to the City under this agreement occasioned by the future production of such cut back oil. Any amount to which such Contractor is entitled by virtue of such rights, if any, shall be charged to such Contractor’s Net Profits Account. So long as such Contractor shall continue to carry out the obligations specified in this Section 9(g) during the period of such cut back, and shall otherwise discharge its obligations under this agreement and under the Unitization Agreements, such Contractor shall not be in default by virtue of its failure to take delivery of oil during such period.

 

Article 10.                                        GAS PROCESSING AND VALUE

 

Except as hereinafter provided, each Contractor shall have the exclusive right and shall be obligated to treat all Wet Gas Allocated to such Contractor by processing such Wet Gas for the extraction of Wet Gas Products; provided, however, that if any Wet Gas Allocated to any Contractor contains one-half gallon or less of recoverable gasoline per Mcf, such Wet Gas, upon written direction of the City Manager, shall not be treated and shall be delivered to the City by such Contractor at no cost to the City.

 

Any Contractor may, at any time or from time to time, subcontract all or any portion of the treatment required hereunder to one or more financially responsible subcontractors; provided, however, that any such subcontract must be approved in advance by the City Manager unless such subcontract is made with one or more of the Persons Comprising

 

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such Contractor or a wholly owned subsidiary of the Contractor or of any such Person or Persons.

 

Wet Gas Allocated to each Contractor shall be delivered to such treater or treaters, whether the Contractor itself or such subcontractor, at the site or sites provided for under the terms of the Unit Operating Agreement at the pressure there prevailing. Wet Gas Allocated to any Contractor may be commingled with gas from other sources and the quantity of Wet Gas Products extracted from such Wet Gas when commingled with other gas shall be deemed to be such proportion of all the Wet Gas Products produced and saved from said commingled gas at the treatment facilities as the computed Wet Gas Products contained in such Wet Gas Allocated to such Contractor bear to the computed Wet Gas Products contained in all of said commingled gas. All Residue Dry Gas remaining after treatment of the Wet Gas Allocated to each Contractor, after deduction as hereinafter provided for computed actual plant shrinkage, plant loss and plant fuel used in the collection of the Wet Gas Allocated to such Contractor and in the extraction of Wet Gas Products from such Wet Gas shall, except as hereinafter provided, be delivered to the City or the City’s order at such treater’s or treaters’ outlet facilities in the Long Beach area at sufficient pressure to enter the facilities of the City or it nominee, but not at a pressure in excess of thirty-five (35) pounds per square inch, gauge, at no cost to the City. The sum of plant loss and plant fuel to be deducted from the total quantity of dry gas attributable to the Wet Gas Allocated to any Contractor shall not exceed twenty-five percent (25%) of such total quantity before any deduction for plant shrinkage, plant loss and plant fuel. Any such Residue Dry Gas, or other dry gas equivalent thereto, necessary for Unit Operations shall, upon written direction of the City Manager, be returned by such treater or treaters to the Unit Operator in accordance with the Unit Agreement at no cost to the City.

 

Such treater or treaters, whether the Contractor itself or subcontractors, shall receive fifty percent (50%) of the Wet Gas Products derived from the Wet Gas treated as compensation for treating such Wet Gas. The remaining fifty percent (50%) of the Wet Gas Products derived from the Wet Gas so treated shall be delivered to such Contractor or Contractor’s order at such treater’s or treaters’ plant or plants in the Long Beach area.

 

Each Contractor shall have the exclusive right to take and shall be obligated to take and to account for all Wet Gas Products Attributable to such Contractor. All Wet Gas Products Attributable to each Contractor shall be valued and accounted for on the basis of the

 

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highest price posted or paid in the Field for natural gasoline of like grade and like quality on the day of treatment, and the prevailing market price for other liquid or liquefied hydrocarbon products of like grade and like quality in the Field on the day of treatment.

 

None of the Residue Dry Gas or Wet Gas delivered to the City without treatment pursuant to the terms hereof shall ever become the property of any Contractor at any time nor shall it be credited to any Contractor’s Net Profit Account.

 

Article 11.                                        SELL OFF OF OIL

 

(a)                                Twelve and one-half percent (12 1/2%) sell off

 

The Field Contractor shall offer for sale, by competitive bidding, up to twelve and one-half percent (12 1/2%) of one hundred percent (100%) of all Oil Allocated to the Contract Lands from the Field Contractor’s eighty percent (80%) share of such oil (or, stated otherwise, fifteen and five-eighths percent (15 5/8%) of the Oil Allocated to Field Contractor).  Said bidding shall be limited to Persons other than (1) the Field Contractor, (2) any of the Persons Comprising Field Contractor, (3) any Person owning a controlling interest in, controlled by or under common control of the Field Contractor, or (4) any Person owning a controlling interest in, controlled by, or under common control of any of the Persons Comprising the Field Contractor. The phrases “owning a controlling interest in,” and “controlled by or under common control,” as used in this Article, shall mean that relationship between two Persons resulting from the direct or indirect ownership or control by one Person of a majority of the voting securities of the second Person or the direct or indirect ownership or control by a third Person of a majority of the voting securities of each of such two Persons. No bid shall be accepted, however, unless it is equal to or greater than the amount per barrel at which the Field Contractor accounts for like oil, computed as provided in Section 9(b) hereof.

 

Any agreement of sale between the Field Contractor and the successful bidder pursuant to the provisions of this Section 11(a) shall be for a fixed term to be determined by the State. The successful bidder shall commence purchasing oil at a date, determined by the City subject to the approval of the State, not less than one hundred eighty (180) days subsequent to the execution of such agreement of sale. Such agreement of sale shall contain such other reasonable provisions as may be determined by the City subject to the approval of the State.

 

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Said oil shall be offered for competitive bidding pursuant to this Section 11(a) not more than sixty (60) days after the State notifies the City to direct the Field Contractor to offer such oil for bidding. The notice by the State shall specify the amount or amounts of oil to put out for bid, and such notice maybe given whenever any amount of oil less than said twelve and one-half percent (12 1/2%) of the Oil Allocated to the Contract Lands (i.e., fifteen and five-eighths percent (15 5/8%) of the Oil Allocated to Field Contractor) is committed by agreement of sale under this Section, but in no event more than once in any twelve (12) month period.

 

(b)                                Sell-Off of Excess Over Sixty-Seven and One-Half Percent (67 1/2%)

 

In the event any one Person party to this agreement, or any two or more such Persons controlled by or under common control of any one Person, shall at any time during the term of this agreement have, or acquire, the right to receive any percentage over and above sixty-seven and one-half percent (67 1/2%) of one hundred percent (100%) of all Oil Allocated to the Contract Lands, said Person or Persons shall offer all oil in excess of said sixty-seven and one-half percent (67 1/2%) for sale by competitive bidding. No bid shall be accepted, however, unless it is equal to or greater than the amount per barrel at which the Field Contractor accounts for like oil under the provisions of Section 9(b) hereof.

 

Any agreement of sale between said Person or Persons and the successful bidder shall be for a fixed term to be determined by the State. The successful bidder shall commence purchasing oil at a date, determined by the City subject to the approval of the State, not less than one hundred eighty (180) days subsequent to the execution of such agreement of sale. Such agreement of sale shall contain such other reasonable provisions as may be determined by the City, subject to the approval of the State.

 

Said oil in excess of said sixty-seven and one-half percent (67 1/2%) shall be offered for competitive bidding, in an amount or amounts specified by the State, not more than sixty (60) days after the State shall determine that said Person or Persons have the right to receive any percentage over and above such sixty-seven and one-half percent (67 1/2%), and notifies the City to direct said Person or Persons to offer such oil for bidding. The notice by the State may be given whenever the State makes the aforesaid determination, but in no event more than once in any twelve (12) month period.

 

For purposes of this Section 11(b), the percentage of Oil Allocated to the Contract Lands which said Person or Persons have the right to receive shall be computed after deducting a

 

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percentage of such oil equal to twelve and one-half percent (12 1/2%) times such Person’s or Persons’ percentage interest in the Field Contractor’s undivided share hereunder. Any oil sold pursuant to this Section 11(b) shall come out of such Person’s interest in the Oil Allocated to the Field Contractor. In the event of a joint bid and the awarding of any Contractor’s undivided share hereunder to two or more Persons, the interest of each such Person and not the joint interest (unless such Persons are controlled by or under the common control of any one Person) shall be considered in computing the percentage of oil which any Person has the right to receive for purposes of this Section 11(b).  Each Person party to this agreement shall furnish to the State each year any and all information in its possession, or to which it has access, required to carry out the purposes of this Article 11, including but not limited to any of the following information which is requested by the State:

 

(1)                                  The name of each Person owning a controlling interest in, controlled by or under common control of any Contractor and the name of each Person owning a controlling interest in, controlled by, or under common control of each Person Comprising any Contractor; and

 

(2)                                  The percentage or quantity of Oil Allocated to the Contract Lands which any such named Person has a right to receive, including the percentage or quantity receivable out of the Oil Allocated to each Contractor in which such named Person has an interest.

 

Article 12.                                        FIELD CONTRACTOR’S EXCLUSIVE RIGHT TO OPERATE

 

The Field Contractor, acting under the direction and control of the City, shall have the exclusive right, responsibility and obligation to conduct day-to-day operations for the exploration, development and operation of the Contract Lands and all the Committed Parcels for the production of Unitized Substances, and hereby agrees to conduct all such operations as directed by the City as herein provided. Field Contractor shall perform all Unit Operations which are the responsibility of the City as Unit Operator which the City Manager requests Field Contractor to perform, including, without limiting the generality of the foregoing, the assumption and compliance with all obligations and duties of the Unit Operator with respect to the initial and subsequent Plans of Development and Operation; provided, however, that the Field Contractor shall never be required without its consent to exercise Unit Operator’s power to dispose of

 

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Unitized Substances for the account of a Participant as provided in Section 5.14 of the Unit Agreement. Field Contractor shall have the exclusive use of the Offshore Islands to such extent as required to conduct Unit Operations hereunder and consistent with safety requirements. If the Offshore Islands are used for other purposes, the Field Contractor shall not be liable for damages resulting from such other use by the City or any other Person.

 

Nonoperating Contractors shall have no right nor obligation to develop or operate the Contract Lands or the Committed Parcels, but shall be obligated to share in the expenses of exploration, development and operation attributable to the Contract Lands and shall have the right to share in the Oil allocated and Wet Gas Products attributable to the Contract Lands, all in accordance with the provisions of this agreement.

 

The rights of the Contractors are subject to the provisions of this agreement, the Unit Agreement, the Unit Operating Agreement, the Plans of Development and Operations, the determinations and approvals given or imposed by the City Manager, and Chapter 138.  In the event of any conflict between this agreement and Chapter 138, said Chapter 138 shall govern, as if fully set forth herein, and any such conflict shall not affect the validity of this agreement. In the event of any conflict between this agreement and the Unitization Agreements, this agreement shall govern in any controversy between the parties hereto in their capacity as such parties; but in all other instances the Unitization Agreements shall govern.

 

Article 13.                                        OPERATING COMMITTEE

 

A committee shall be established to meet at appropriate intervals prescribed by the City Manager to review and make recommendations concerning the budgets, and Plans of Development and Operation and implementation thereof required for carrying on the exploration, development and operation of the Contract Lands.  The Field Contractor shall submit all data necessary to reasonably inform the Committee of operations being conducted hereunder.

 

Membership of the Committee shall include any City personnel authorized by the City Manager, any State personnel authorized by the State, and one member authorized by each Contractor.

 

The function of this Committee shall be advisory only and no recommendation shall be binding unless adopted pursuant to the applicable provisions of the Unitization Agreements and Chapter 138. Any Contractor may use any information or Committee records to

 

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petition the City Council and/or the State concerning any operation the Contractor deems to be both:

 

(a)                                  not in accord with good oil field practices; and

 

(b)                                  not needed for a plan of complete pressure maintenance or to prevent, arrest or ameliorate subsidence;

 

or which the Contractor deems to be inconsistent with the Unitization Agreements, any Plan of Development and Operation, Chapter 138, or any other applicable law.

 

Nothing in this Article shall be taken as an authorization to receive reimbursement for expenses incurred hereunder unless such expenses are explicitly provided to be reimbursable in another section of this agreement.

 

Article 14.                                        SUPERVISION BY CITY MANAGER

 

The City Manager acting on behalf of the City as such and the City as Unit Operator shall exercise supervision and control of all day-to-day Unit Operations subject to the terms and conditions of the Unitization Agreements and the Plans of Development and Operation, and, subject to such terms and conditions, shall make determinations and grant approvals in writing as he may deem appropriate for the supervision and direction of the day-to-day operations of the Field Contractor, and Field Contractor shall be bound by and shall perform in accordance with such determinations and approvals of the City Manager; provided that in the event the City Manager should direct the Field Contractor to perform any act or to perform in a way and manner which the Field Contractor deems to be inconsistent with the Unit Agreement or Unit Operating Agreement or with any Plan of Development and Operation, the Field Contractor, within five days of such direction, may notify the City Manager of its contention and the specific and detailed reasons therefor, in writing, and a copy of such notice shall be given to the State and to all the Participants. Should the City Manager then repeat his direction to the Field Contractor, the Field Contractor shall be bound thereby and obligated to perform in accordance therewith; but should it be finally adjudicated that such action in fact constituted a breach of either of said agreements, or any Plan of Development and Operation, for the reasons contended by Field Contractor, any legal liability to the Participants and/or the State for such breach shall be borne by the City notwithstanding the provisions of Article 16 hereof, and the costs of discharging such liability shall not be borne by the Contractors hereunder and shall not

 

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be charged to their Net Profits Accounts.  Likewise, in the event the City Manager fails or refuses to direct Field Contractor to perform any act whose performance Field Contractor deems necessary in order to comply with the terms or conditions of the Unit Agreement or Unit Operating Agreement, or any Plan of Development and Operation, Field Contractor may notify the City Manager of its contention and the specific and detailed reasons therefor, in writing, and a copy of said notice shall be given to the State and to all the Participants. Should the City Manager thereafter continue in such failure or refusal, Field Contractor shall not be entitled to perform such act; but should it be finally adjudicated that such act was in fact required to be performed by the City, as Unit Operator, or by the Field Contractor, under the terms or conditions of either of said agreements, or any Plan of Development and Operations, for the reasons contended by Field Contractor, any legal liability to the Participants and/or the State for failure to perform such act after such notice by the Field Contractor shall be borne by the City notwithstanding the provisions of Article 16 hereof, and the costs of discharging such liability shall not be borne by the Contractors hereunder and shall not be charged to their Net Profits Accounts. As soon as practicable, a copy of each such determination or approval shall be furnished to the State.

 

In the interest of minimizing the number of approvals of determinations to be granted by the City Manager, the City Manager may, from time to time, standardize a tabulated list of approvals and determinations. Without limiting the generality of the foregoing, this list may include plans and specifications, standardized well programs, drilling, producing and operating techniques, services and procedures, types, grades and specifications of equipment, materials and facilities, outside services and rentals. The items on this list may be given in whatever detail or lack of same that is deemed appropriate by the City Manager. The procedures for implementing this list shall be prescribed by the City Manager; but nothing therein shall preclude the City from requiring competitive bidding on those items deemed to be appropriate. A copy of any such list shall be furnished to the State at least thirty (30) days before its effective date. Any such list shall be subject to supplementation, modification or revocation, in whole or in part, at any time at the sole discretion of the City Manager, except that the Field Contractor and the State shall be entitled to written notice of the City Manager’s intended action at least thirty (30) days prior to the declared effective date of such supplementation, modification or revocation; provided however, that where practical, no new operations or procurements shall be

 

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made under those items modified or revoked during such thirty (30) day period. During the time that such list is in effect, it will not be necessary for the Field Contractor to make application in advance, or secure City Manager’s approval, as to any of the items specified in such list, as it shall be deemed that the inclusion of such item in such list shall constitute approval by the City Manager.

 

All sampling, testing, gauging, measuring and the taking of gravities which may be done by Field Contractor hereunder shall be taken, done and performed by methods or processes approved by the City Manager. The Field Contractor shall carry out all determinations and approvals by the City Manager in accordance with good oil field engineering and operating practices, and with due care.

 

Article 15.                                        FIELD CONTRACTOR’S EMPLOYEES

 

The selection of employees used by the Field Contractor in conducting operations hereunder, their hours of labor, their conditions of employment, and their supervision shall be the responsibility of the Field Contractor. A schedule of the number of such employees and their salaries and benefits must be approved  by the City Manager, and he shall give due regard to the requirements of good oil field engineering and operating practices and to the compensation and other benefits normally allowed to comparable employees by Field Contractor and by other responsible Persons engaged in comparable oil field operations. Field Contractor agrees that in its employment practices hereunder it shall not discriminate against any individual because of race, color, ancestry, national origin, or religion.

 

Article 16.                                        CONTRACTORS’ RIGHT OF REIMBURSEMENT LIMITED

 

Except as expressly provided in Articles 3, 14, 17, Section 20(c), and Article 28 hereof, and as hereinafter provided in this Article 16, nothing in this agreement contained shall be deemed to obligate City or State to reimburse Contractors, or any of them, for any of their costs or expenditures; and Contractors, and each of them, renounce any right or claim to money previously paid under this contract to the City or State, or against the general funds, tideland trust funds, or tax revenues of the City of Long Beach, or any funds of the State of California, for the repayment of any accounts hereunder. Provided, however, that nothing herein shall affect the rights or remedies at law or in equity which the Contractors, or any of them, would otherwise have in the event this agreement, the Unitization Agreements, or any of them, should, for any

 

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reason or cause, be held invalid by a final judgment or decree of a court of competent jurisdiction, or in the event there should be a failure of consideration to any Contractor by virtue of a final judgment or decree of a court of competent jurisdiction holding invalid, for any reason or cause, any covenant or condition contained in this agreement, the Unitization Agreements, or any of them; provided that such adjudication of invalidity shall not vest any right or remedy in any Contractor if such adjudication resulted from an attack, directly or indirectly, by such Contractor, or any officer; agent or employee of such Contractor duly authorized, in a legal or equitable proceeding, upon the validity of any such agreement or agreements or any covenant or condition therein contained.

 

Article 17.                                        EXCLUDED RECEIPTS

 

Since (as provided in Section 20(b) hereof) Field Contractor is required to make initial payment of all sums which the Unit Operator may be required to pay or advance under the Unit Agreement and Unit Operating Agreement, all sums (except for the City’s one percent (1%) overhead allowance and other amounts paid by or attributable to the City, rather than the Field Contractor, and allowable to the Unit Operator under the Accounting Procedure, Exhibit “F” to the Unit Operating Agreement) which the City as Unit Operator collects pursuant to said agreements as Unit Expense and as taxes from all Participants (including advance payments pursuant to Section 9.6 of the Unit Operating Agreement) shall be paid to Field Contractor upon receipt by the City. Such sums so paid to Field Contractor shall not be credited to the Field Contractor’s Net Profits Account. Field Contractor may avail itself of all liens and other remedies which Unit Operator may employ under the terms of the Unit Agreement and/or Unit Operating Agreement for the collection from Participants of Unit Expense and/or taxes.

 

Section 5.15 of the Accounting Procedure, Exhibit “F” to the Unit Operating Agreement, provides that the Field Contractor shall receive an administrative overhead allowance of three percent (3%). Such administrative overhead allowance, if received by the City as Unit Operator, shall be paid directly to the Field Contractor upon receipt by the City of any money representing such overhead allowance; and Section 5.15 of such Accounting Procedure provides that the City shall receive an administrative overhead allowance of one percent (1%) as Unit Operator. Any money received by the Field Contractor or the City for such administrative overhead allowance shall not be deemed to have been received under the terms of this

 

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agreement, and money so received by the Field Contractor shall not be Credited to the Field Contractor’s Net Profits Account.

 

Compensation received for the treatment of Wet Gas pursuant to this agreement shall not be credited to any Contractor’s Net Profits Account.

 

Article 18.                                        TAXES

 

A.                                     All severance taxes, gross production taxes, business license taxes, mining rights taxes and any other taxes, assessments or governmental charges imposed upon, based upon or measured by production allocated to the Contract Lands; and

 

B.                                     All sales, use and excise taxes; and

 

C.                                     All personal property taxes, real property taxes, possessory interest taxes, contractual interest taxes and all other ad valorem taxes, assessments or governmental charges.

 

1.                                       Which are imposed upon, based upon or measured by:

 

(a)                                  Any interest of the Contractors held under and by virtue of this agreement; or

 

(b)                                  Any property used in or held for or as a result of or in connection with the conduct of Unit Operations under the Unit Agreement and Unit Operating Agreement; and

 

2.                                       For which the Contractors are ultimately liable;

 

shall be paid by the Contractors in proportion to their respective Contractor’s Percentages, and when so paid such proportion shall be charged to each Contractor’s Net Profits Account.

 

To the extent the amounts referred to in this Article 18 are chargeable as Unit Expense or taxes under the Unitization Agreements, the obligations hereunder shall be discharged by each Contractor’s payment as such under the terms of the Unitization Agreements.

 

Nothing herein contained shall be deemed to provide for the charging to any Contractor’s Net Profits Account of any franchise, income, profits, capital stock, and other like general taxes or assessments which such Contractor may be required or compelled to pay upon any profits or consideration received hereunder.

 

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Article 19.                                        OWNERSHIP OF UNIT

 

The Unit Facilities shall be owned by the Contractors, in proportion to their respective Contractor’s Percentages, as tenants in common with the other Participants as provided in the Unit Operating Agreement.

 

If this agreement terminates as to any Contractor or as to all Contractors prior to the termination of the Unit Agreement, the interest or interests in Unit Facilities of any such Contractor or Contractors as to which this agreement shall so terminate, as a Participant or as Participants in Tract No. 1, shall become the property of the City without any further act by such Contractor or Contractors and without any compensation to such Contractor or Contractors for or by virtue of such interest or interests. If this agreement does not terminate prior to the Unit Agreement, then upon the termination of the Unit Agreement, the net salvage value of the Contractors’ interests in the Unit Facilities as Participants in Tract No. 1, after costs of salvage, shall be paid over to the Contractors and credited to Contractors’ Net Profits Accounts in proportion to their respective Contractors’ Percentages.

 

Article 20.                                        BILLS, BUDGETS AND ADVANCES

 

(a)                                Obligations of all Contractors

 

Each Contractor (including Field Contractor and each Nonoperating Contractor) agrees to pay promptly when due all sums due and payable by such Contractor under the terms of this agreement, and payable by such Contractor as a Participant in Tract No. 11 under the terms of the Unit Agreement and Unit Operating Agreement. Without limiting the generality of the foregoing, each Contractor shall pay when due, and its Net Profits Account will be charged with, its Unit Participation share or its Participant Allocation share, attributable to its Contractor’s Percentage of the Working Interest in the Contract Lands, of all Unit Expense, as required by, and subject to the terms of, the Unitization Agreements. Also without limiting the generality of the first sentence of this Section, each Contractor, in its capacity as a Participant in Tract No. 1, shall pay its share of all taxes, assessments and governmental charges (in addition to those chargeable as Unit Expense) (hereinafter called “taxes”) provided for in the Unitization Agreements, attributable to its Contractor’s Percentage of the Working Interest in Tract No. 1; and such payment, to the extent it constitutes performance of such Contractor’s obligations to pay its Contractor’s Percentage of taxes provided for in Article 18 of this agreement, shall likewise

 

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discharge such Contractor’s obligations under said Article 18 hereof. Each Contractor expressly agrees that City may withhold and sell, or direct the withholding of, all or any part of any sums or Unitized Substances which may be payable or deliverable to such Contractor hereunder or under the Unit Agreement or Unit Operating Agreement, until such time as the City Manager is satisfied that all past due obligations of such Contractor hereunder or under the Unit Agreement or Unit Operating Agreement have been paid in full. City shall have the right from time to time, but shall not be required, to pay in whole or in part any indebtedness or liability which any Contractor shall permit to remain unpaid after its maturity so as to prevent any lien or liens being filed or accruing against any property of City and/or any property of Contractors used in the performance of the terms of this agreement, and in the event of any such payment by City, such Contractor shall reimburse City for the same, together with ten percent (10%) interest per annum from the date of payment, and City shall have the right to deduct, or direct the deduction of, the amount or value of any such payment or payments, from any sums or Unitized Substances which may thereafter become payable or deliverable to such Contractor hereunder or under the Unit Agreement or Unit Operating Agreement.

 

(b)                                  Obligations of Field Contractor

 

The Field Contractor initially shall pay and discharge all Unit Expense (including cost of core holes and printing incurred before the effective date of this agreement and of the Unit Agreement) and taxes which the City as Unit Operator is required to pay or advance under the terms of the Unitization Agreements for all Tracts in the Unit Area.  The Field Contractor’s Net Profits Account shall be charged only with Field Contractor’s Unit Participation share or Participant Allocation share, attributable to its Contractor’s Percentage of the Working Interest in Tract No. 1, of Unit Expense, and taxes, and its Contractor’s Percentage of expenses, other than Unit Expense and taxes, as provided herein, and shall not be charged with Unit Expense or taxes attributable to other Tracts or attributable to the Working Interests of the Nonoperating Contractors in Tract No. 1, nor with Nonoperating Contractors’ Percentages of such taxes or other expenses hereunder. The Field Contractor, as hereinafter provided, shall be entitled to advance payment or reimbursement from the other Participants, including the Nonoperating Contractors, of their respective Unit Participation or Participant Allocation shares of all Unit Expense and taxes payable by Field Contractor.

 

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Except as otherwise expressly provided in this agreement, Field Contractor’s charges for exercising its operating responsibilities under the Unit Agreement and Unit Operating Agreement and under this agreement shall be limited to costs and expenses borne by or attributable to Field Contractor which are allowable to Unit Operator and/or Field Contractor under the Accounting Procedure, Exhibit “F,” of the Unit Operating Agreement, plus Field Contractor’s three percent (3%) administrative overhead allowance provided for in, and subject to the provisions of, Section 5.15 of said Exhibit “F” to the Unit Operating Agreement.

 

Since, as hereinabove provided, Field Contractor is required to advance all Unit Expense and taxes which the City as Unit Operator is required to pay under the Unit Agreement and Unit Operating Agreement, Field Contractor shall not, except as hereinafter provided in this Section 20(b), be required to pay over any of the sums which would otherwise be due under the Unit Agreement and Unit Operating Agreement from Field Contractor as a Participant in Tract No. 1 as Unit Expense and taxes attributable to Field Contractor’s eighty percent (80%) undivided share in the Working Interest in the Contract Lands; provided that Field Contractor, as a Participant in Tract No. 1, shall pay to the City as Unit Operator an amount equal to Field Contractor’s Participant Allocation share, attributable to Field Contractor’s eighty percent (80%) undivided share in the Working Interest in the Contract Lands, of City’s one percent (1%) overhead allowance provided for in Section 5.15 of Exhibit “F” of the Unit Operating Agreement, and of other amounts not borne by or attributable to the Field Contractor, payable to the City as Unit Operator under said Exhibit “F.” Field Contractor expressly agrees to pay promptly when due all indebtedness which it may incur in carrying on its operations hereunder, and expressly agrees that City may withhold or direct the withholding of all or any part of any sums which may be payable to the Field Contractor hereunder or under the Unit Agreement or Unit Operating Agreement until such time as City Manager is satisfied that all past due obligations for labor, material, claims or liens have been paid in full or released. City shall have the right from time to time, but shall not be required, to pay in whole or in part any indebtedness or liability which Field Contractor shall permit to remain unpaid after its maturity so as to prevent any lien or liens being filed or accruing against any property of City and/or any property of the Contractors and/or any property of the Field Contractor used in the performance by it of the terms of this agreement, and in the event of any such payment by City, Field Contractor shall reimburse City for the same, together with ten percent (10%) interest per annum from the date of

 

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payment, and City shall have the right to deduct, or direct the deduction of, the amount of any such payment or payments, with interest, from any sums payable or which may thereafter become, payable to Field Contractor hereunder.

 

(c)                                   Advances by Participants

 

The City, as Unit Operator, shall, to the extent practicable, require the Participants (including the Nonoperating Contractors) to advance their Unit Participation shares of any proposed Unit Expenses, advance working fund, and their respective shares of taxes required to be paid under the terms of the Unitization Agreements, as permitted by Section 9.6 of the Unit Operating Agreement.

 

Field Contractor shall not be relieved of its obligation (set forth in Section 20(b) hereof) to make actual payment of any Unit Expense or taxes by any Participant’s (including any Nonoperating Contractor’s) failure to advance its proportionate share thereof as provided in the Unitization Agreements; provided, however, to the extent that Field Contractor has incurred any expense for which any Participant (including any Nonoperating Contractor) has failed to pay its proportionate share when due, Field Contractor, in addition to any other rights it may have in law or equity, shall be subrogated to any lien which City, as Unit Operator, may have for the purpose of collecting such expense under the terms of the Unitization Agreements, and, as to any Nonoperating Contractor, shall be subrogated to the City’s rights relating to such expense under such Nonoperating Contractor’s bond provided for in Article 32 hereof. In the event any Nonoperating Contractor should fail to make any payment required under this agreement or the Unitization Agreements, when due, the City, at Field Contractor’s request, shall immediately serve notice of default upon such Nonoperating Contractor as provided in Article 30 hereof, and in the event the City (with the approval of the State) is thereafter empowered to terminate said Nonoperating Contractor’s rights and privileges hereunder, and the City and/or state refuse to do so at Field Contractor’s request, the City shall (the provisions of Article 16 to the contrary notwithstanding) indemnify Field Contractor and hold it harmless for any loss to Field Contractor resulting from such Nonoperating Contractor’s failure to make such payments when due.

 

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Article 21.                                          AUDITS

 

The books, records and accounts of each Contractor and each Person Comprising any Contractor shall be subject to inspection is by authorized representatives of the City and the State of California during regular business hours, and shall be subject to audit not more than once each year unless additional audits are required to carry out any responsibility imposed by law upon the City and the State of California, or any officer, agency or employee of either.  The Field Contractor’s books, records and accounts relating to Unit Operations shall be subject to inspection and audit as provided by the Unit Operating Agreement.

 

Article 22.                                          RELATIONSHIP OF PARTIES

 

In performing their obligations hereunder, Contractors are engaged solely in the capacity of independent contractors, it being expressly understood that no relationship between the City and any Contractor other than that of independent contractor has been, or is intended to be, created by this agreement. This agreement does not constitute, and the parties hereto do not intend it to create among the Contractors themselves or between the City and any Contractor, a partnership, or a joint venture, or the relationship of master and servant, or principal and agent. Said parties hereto have entered into this agreement with full knowledge of the provisions of California Statutes of 1911, page 1304 (Chapter 676), California Statutes of 1925, page 235 (Chapter 102), and California Statutes of 1935, page 793 (Chapter 158) and Chapter 138, and it is not the intention of said City to, nor does said City grant, convey, give or alien to or vest in said Contractors for any purpose whatsoever, any title, interest or estate in or to any lands whatsoever, or any title, interest or estate in or to the oil, gas and/or other hydrocarbons and/or other minerals underlying any lands whatsoever, or any title, interest or estate in or to said oil, gas and/or other hydrocarbons and/or other minerals when removed from any lands until allocated by the Unit Operator, and it is not the intention of said Contractors that this agreement shall at any time, nor shall the same be so construed as to grant, convey, give or alien to or vest in said Contractors for any purpose whatsoever, any title, interest or estate in or to any lands whatsoever hereunder, or any title, interest or estate in or to the oil, gas and/or other hydrocarbons and/or other minerals underlying any lands whatsoever hereunder, or any part thereof, or any title, interest or estate in or to said oil, gas and/or other hydrocarbons and/or other minerals when removed from any lands until allocated by the Unit Operator, and it is the

 

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intention of each and all of the parties hereto that insofar as the Contract Lands, or the oil, gas and/or other hydrocarbons and/or other minerals underlying the Contract Lands, or when removed therefrom, are affected by California Statutes of 1911, page 1304 (Chapter 676), California Statutes of 1925, page 235 (Chapter 102), and/or California Statutes of 1935, page 793 (Chapter 158), and Chapter 138, or by any trust for commerce, navigation or fishery, said lands shall be at all times so used, and said oil, gas and/or other hydrocarbons and/or other minerals underlying the same shall be so removed and disposed of, as not to violate said statutes hereinabove enumerated, or any of them, or any part or portion of any of them, or any such trust for commerce, navigation or fishery; and should a court of competent jurisdiction hereafter hold, by final judgment, that this instrument does grant, convey, give or alien to or vest in said Contractors, for any purpose whatsoever, any right, title, interest or estate in or to the Contract Lands, or any right, title, interest or estate in or to any oil, gas and/or other hydrocarbons and/or other minerals underlying the Contract Lands, or any right, title, interest or estate in or to said oil, gas and/or other hydrocarbons and/or other minerals when removed from the Contract Lands, but prior to allocation by the Unit Operator, in any manner or to any extent which is by such judgment held to be contrary to and/or in violation of said statutes, or any of them, or any provision or provisions of said statutes, or any of them, or of any such trust for commerce, navigation or fishery, then, and in that event, this agreement, to the extent, and only to the extent, that it is so held to violate the aforesaid statutes, or any of them, or any provision or provisions of said statutes, or any of them, shall, as of the date hereof, be and become, without further act upon the part of either of the parties hereto, null and void and of no force whatsoever. Nothing in this agreement shall impair the governmental powers of the State of California expressly reserved by the Legislature in Section 8 of Chapter 138.

 

Article 23.                                          WARRANTY

 

It is agreed that neither the City nor the State makes any covenant or warranty, express or implied, as to the title of City to possession of any lands, or as to the condition thereof, or as to any easements, licenses or privileges whatsoever pertaining thereto, and any rights, license and privileges of use and occupancy hereby created in favor of Contractors, or any of them, are so created by City without covenant of title, or right of possession, or for quiet enjoyment.

 

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Article 24.                                          LITIGATION

 

Field Contractor and each Nonoperating Contractor shall serve upon City and the State, and City shall serve upon each Contractor and the State, notice of any litigation or the levy of any process of any court or order thereof affecting any operations hereunder, or affecting any moneys accruing from the sale or disposal of any Oil or Gas allocated to the Contract Lands by Unit Operator, as soon as any such Contractor or City, as the case may be, shall have knowledge thereof.

 

The Field Contractor, under the direction and control of the City Manager, shall handle any suits or claims by or against any third Person arising out of this agreement which are not covered under the provisions of the Unitization Agreements providing for the handling of suits or claims; provided, however, that the City and the State, or either, may join in the defense or prosecution of any such suit or claim. No claim or suit shall be settled except at the direction of the City Manager with the approval of the State. Except as otherwise provided in Articles 14, 28, 29 and 31, hereof all costs and expenses of handling, settling or otherwise discharging any claim or suit by or against any third Person arising out of this agreement, not chargeable as Unit Expense, incurred by the City, the State, or the Field Contractor, shall be paid by the Contractors, in proportion to their respective Contractor’s Percentages, and each Contractor’s proportionate share of such cost when so paid shall be charged to such Contractor’s Net Profits Account.

 

Article 25.                                          ASSIGNMENT

 

None of the Contractors, nor any of their successors or assigns, shall have the right or the power to sublet or subcontract all or any part of the work or obligations contemplated by this agreement to be performed or assumed by such Contractor, except as otherwise provided in this agreement, without first obtaining written consent of, and subject to such terms and conditions as may be prescribed by, City Manager. None of the Contractors nor any of their successors or assigns shall have the right or power to assign, hypothecate, pledge, or in any manner dispose of its rights, privileges or obligations under this agreement, or any part thereof, without first obtaining the written consent of, and subject to such terms and conditions as may be prescribed by, the City Manager, with the approval of the State. Any attempt to so sublet or subcontract all or any part of the work or obligations contemplated by this agreement to be performed or assumed by the Contractors, or any of them, or to assign, hypothecate, pledge, or in

 

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any manner dispose of this agreement, or any part thereof, or of the whole or any part of any Contractor’s rights, privileges or obligations hereunder, shall be void, and no rights thereunder shall pass to any Person whomsoever, and City shall not be obligated to accept, nor shall it be deemed bound by, or to have acquiesced in, or be estopped in any respect by, any performance hereunder by any person other than a Contractor, or one or more of the Persons Comprising such Contractor. The giving of consent by City in either of the methods set forth above to any assignment, hypothecation, pledge or other disposition of this agreement, or any part thereof, or of the whole of any part of such Contractor’s rights, privileges or obligations hereunder, shall not be deemed to nor shall it confer any right upon such Contractor or its successors or assigns, to thereafter assign, hypothecate, pledge or in any manner dispose of this agreement or any part thereof, or of the whole or any part of the rights, privileges or obligations of such Contractor or its successors or assigns thereunder. After obtaining the requisite consent and/or approval from the City Manager or the City Manager and the State as hereinabove provided in this Article 25, any Contractor may exercise the rights herein specified without the approval or Consent of the other Contractors, or any of them.

 

Article 26.                                          BANKRUPTCY

 

Should any Contractor at any time during the term hereof file a voluntary petition in bankruptcy or be adjudged a bankrupt, either upon the voluntary petition in bankruptcy of any such Contractor, or upon the involuntary petition or petitions of creditors of any such Contractor, or should any such Contractor seek, claim or apply for any right, privilege, remedy, relief or protection afforded by any statute or statutes of the United States relating to bankruptcy, or should it make an assignment for the benefit of its creditors, or should a receiver be appointed over, or should an attachment be levied and permitted to remain for a period of more than thirty (30) days following the levying of such attachment upon or against any right, privilege or asserted interest of any such Contractor in, to, under or pursuant to this agreement, or upon any of the property used in the performance of the terms of this agreement, then, and upon the happening of either of said events, all interest, rights and privileges of any such Contractor, whether then existing or contingent in, to, under or pursuant to this agreement, and except such of said interest, rights and/or privileges as shall have been theretofore validly assigned by such Contractor pursuant to the terms, covenants and conditions of this agreement, shall at the sole

 

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option of the City, acting with the approval of the State, exercisable within thirty (30) days after acquiring knowledge of the facts, cease, terminate and end; provided, however, if said receiver be discharged within thirty (30) days after his appointment, such Contractor may, at any time within ten (10) days thereafter, resume the performance of this agreement, and the same shall thereupon again become in full force and effect. If such Contractor consists of more than one Person, City shall not exercise the option to terminate specified herein, or shall revoke its exercise of such option, if only one such Person comes within the facts above stated and the remaining Person or Persons Comprising such Contractor, or a third Person, prior to the expiration of the time within which such option is exercisable, acquires the interest of such insolvent Person by assignment, and the City, acting with the approval of the State, determines that such assignee is financially able to discharge its obligations hereunder and consents to such assignment.

 

Article 27.                                          COMPLIANCE WITH THE CITY ORDINANCE AND CHAPTER 138

 

Contractors, and each of them, agree that the City and the State shall carry out all powers vested in them, or either of them, by Chapter 138, the City Ordinance, and the Unitization Agreements. Contractors, and each of them, hereby expressly waive any and all damages as against the City and the State; or either of them, claimed to have resulted from the exercise of all or any such powers. Without limiting the generality of the foregoing, Contractors, and each of them, agree as follows:

 

1.                                       That in accordance with the City Ordinance and Chapter 138, by means of approvals and determinations of the City Manager hereunder, the City reserves the right, subject to the criteria set forth in the Unitization Agreements and the Plans of Development and Operation, to control the rates of production of the oil and gas and the Repressuring Operations and practices to be conducted; that a program of complete pressure maintenance by water injection shall be instituted at the inception of drilling operations; that the City Manager shall have the right, subject to said criteria, to order the shut-in of high gas-low oil ratio and high water-low oil ratio wells; that the Contractors, and each of them, hereby expressly waive any and all damages claimed to have resulted as a consequence of water injection operations and practices conducted or ordered by the City Manager; that the City Manager, subject to the approval of the State and the terms of

 

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the Unitization Agreements and applicable law, shall have the unilateral right as against the Contractors, without the necessity of obtaining the consent or approval of the Contractors, or any of them, to commit Tract No. 1 to unitized operation or to a cooperative type agreement providing for coordinate repressuring operations; that the City, subject to the terms of the Unitization Agreements and Chapter 138, shall have the sole right to vote the entire Working Interest assigned to the Contract Lands; and that the Contractors, and each of them, agree to all other matters to which they are required to agree by valid and operative provisions of the City Ordinance and Chapter 138.

 

2.                                       That, in accordance with and subject to the terms of Section 3(h) of Chapter 138 and Section 4.6 of the Unit Agreement, at any time the value of Oil Allocated to the Contract Lands, as determined under Section 9(b) of this agreement, having 20.0° API gravity or higher shall be and remain less than one dollar and fifty cents ($1.50) per barrel, the Unit Operator and the Field Contractor shall curtail, limit or suspend production when, and to the extent, determined by the City acting pursuant to the direction of the State.

 

3.                                       That subject to, and in accordance with, the provisions of Section 5(e) of Chapter 138, and Section 4.5 of the Unit Agreement, the City shall have the power, upon receipt of any evidence of Subsidence or a significant diminution of underground pressure, to order a cessation or curtailment of production until the time such precautions have been taken, which in the opinion of the City are completely adequate and sufficient to prevent or arrest any land Subsidence or carry out a program of complete pressure maintenance, and that any such cessation or curtailment shall be subject to judicial review upon application of the State, all as provided in Section 5(e) of Chapter 138; and that the Contractors, and each of them, hereby expressly waive any and all damages as against the City and the State, or either of them, claimed to have resulted as a consequence of any cessation, curtailment, limitation, or suspension of production referred to in this subparagraph or in subparagraph 2 hereof.

 

Article 28.                                          COMPLIANCE WITH LAWS

 

Each of the Contractors and City agree to be bound by all valid provisions of federal, state, municipal and local laws, ordinances, rules and/or regulations in any manner

 

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affecting Field Contractor’s operations hereunder, and to the extent of their respective powers hereunder, to faithfully comply therewith. This agreement and all of the terms, covenants and conditions thereof are subject and subordinate to and controlled by each and all of the valid and operative terms and provisions of Chapter 138, the Code, the Charter of the City of Long Beach, and the City Ordinance.  Field Contractor shall faithfully comply with all valid rules and regulations governing the drilling of oil wells promulgated by the Supervisor, and, except as in this Article otherwise provided, will hold the City harmless against any and all fines, penalties, costs, assessments or liens for the enforcement thereof incurred, levied or imposed under any act, law, statute, rule or regulation by reason of Field Contractor’s operations hereunder, and any such fines, penalties, costs, assessments or liens shall not be charged to any Contractor’s Net Profits Account. Should the City Manager direct the Field Contractor to perform any act or to perform in a lay or manner which the Field Contractor deems violative of any act, law, statute, rule or regulation, the Field Contractor, within five days of such direction, may notify the City Manager of its contention, and the specific and detailed directions therefor, in writing. Should the City Manager then repeat his direction to the Field Contractor, the Contractor shall be bound thereby and obligated to perform in accordance therewith; but any fine, penalty, cost, assessment or lien incurred, levied or imposed under any act, law, statute, rule or regulation specified in Contractor’s notice by reason of compliance with any such direction of the City Manager shall be borne, discharged or paid by the City and shall not be charged to any Contractor’s Net Profits Account.

 

Likewise, in the event the City Manager fails or refuses to direct Field Contractor to perform any act whose performance Field Contractor deems necessary in order to comply with any such act, law, statute, rule or regulation, Field Contractor may notify the City Manager of its contention, and the specific and detailed reasons therefor, in writing. Should the City Manager thereafter continue in such failure or refusal, Field Contractor shall not be entitled to perform such act; but should it be finally adjudicated that such act was in fact required to be performed by the City, as Unit Operator, or by the Field Contractor under the provisions of any act, law, statute, rule or regulation theretofore specified by Field Contractor, any fine, penalty, cost assessment or lien incurred, levied or imposed by reason of such non-performance after such notice by Field Contractor shall be borne, discharged, or paid by the City and shall not be charged to any Contractor’s Net Profits Account.

 

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Field Contractor shall, within the time specified herein, serve a copy of any notice provided for herein upon the State and each of the Participants.

 

Neither the execution of this agreement by the City nor the approval thereof by the State, nor any action taken hereunder by the City or any agency of the State of California shall be deemed to affect or diminish the applicability of either state or federal antitrust laws, or to create any immunity therefrom in favor of any party hereto.

 

Article 29.                                          MECHANICS’ LIENS

 

Field Contractor shall not suffer or permit any mechanic’s, laborer’s or materialman’s lien, or any other lien, to exist upon lands or the property of City by reason of Field Contractor’s operations hereunder, and Field Contractor shall hold City harmless from and against any and all such liens. If, however, as a result of any Unit Operations, any liens shall be filed upon any lands within the Unit Area owned by or subject to the control of City or the State by any mechanic, laborer or materialman, Field Contractor shall, with due diligence, and at its own cost and expense, defend any action brought to foreclose such lien, and such cost and expense shall be borne by Field Contractor and shall not be chargeable to any Contractor’s Net Profits Account, and, if it shall be necessary for City or State to defend or prosecute any action arising out of any such lien for its own protection, Field Contractor shall pay and discharge all reasonable expense incurred in so doing at Field Contractor’s sole cost and expense, and such cost and expense shall not be chargeable to any Contractor’s Net Profits Account. In the event of judgment being rendered in favor of such claimant in any such action, Field Contractor will promptly pay the same on final judgment, together with all costs of suit, at Field Contractor’s sole cost and expense and such cost and expense shall not be chargeable to any Contractor’s Net Profits Account. The foregoing provisions of this article shall not apply to the extent of the principal amount of any obligation giving rise to any such lien where such obligation was incurred by reason of compliance with any request, approval, or determination of the City Manager or the Unit Operator, and shall not apply to any other costs and expenditures to the extent they were incurred by reason of such compliance.

 

Field Contractor shall exercise due care and diligence in protecting from defacement or destruction any notices of non-responsibility for liens which City may post, or cause to be posted, upon any property of the City used by Field Contractor hereunder.  Field

 

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Contractor shall also comply with the provisions of Section 7.6 of the Unit Operating Agreement concerning Unit Operator’s obligations with respect to liens.

 

Article 30.                                          DEFAULT

 

Each and every term, covenant and condition hereof, is hereby declared to be, respectively, a continuing term, covenant and/or condition, and the waiver by the City or the City Manager of any violation by a Contractor of, or failure by a Contractor to comply with, any of the terms, covenants and conditions of this agreement, or the failure by City or City Manager to exercise any option on account of any such violation or failure by a Contractor, shall not be deemed a waiver by City of any subsequent violations or failures on the part of such Contractor to comply with all or any of the terms, covenants and conditions hereof.

 

In case of default in the performance by a Contractor of any of the terms, covenants and/or conditions of this agreement to be done or performed, and the failure by said Contractor to remedy the same within twenty (20) days after service of written notice by said City so to do, specifying the particulars in which it is claimed by said City that such Contractor is then in default, at the option of City, exercisable with the approval of the State, all rights and privileges of said Contractor under this agreement shall automatically and forthwith cease and terminate and be at an end and surrendered unto City, and such Contractor shall thereafter be without any rights or privileges whatsoever hereunder, either in law or in equity; provided, however, that in case any default by the Field Contractor so specified in such notice is such that the same cannot, with due diligence and in good faith, be cured and remedied within such twenty-day period following the service of such notice by City upon the Field Contractor, and if the Field Contractor shall, within such twenty-day period, commence good and adequate operations in good faith to remedy and cure the default specified in such notice, and shall, at all times continuously, diligently and in good faith thereafter continue such operations until such default is cured and remedied, then the rights and privileges of the Field Contractor hereunder, as aforesaid, shall not cease, terminate nor be at an end by reason of such specified default.

 

Provisions of this agreement to the contrary notwithstanding, the Field Contractor shall not be in default hereunder so long as in complies with the directions, determinations, approvals and requests made by the City Manager.

 

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Article 31.                                          INDEMNITY AND INSURANCE

 

(a)                                  Indemnity

 

Field Contractor shall indemnify and save harmless the City, the State, and the officers, agents and employees of each of them, from and against any and all claims, demands, loss or liability, of any kind or nature which the City, the State, or the officers, agents and employees of each of them, may sustain or incur or which may be imposed upon them, or any of them, for injury to or death of persons or damage to property arising out of or in any manner connected with the negligent or other wrongful act or omission of or breach of this agreement, or any term, condition or provision thereof, by the Field Contractor, or any of its officers, agents or employees, arising out of or connected with work and operations under this agreement, to the extent, if any, such claim, demand, loss or liability is not covered, or not fully covered, by insurance or self-insurance.  In carrying out the aforesaid obligations, the Field Contractor shall pay over to the City the full amount of all losses to the City resulting from Field Contractor’s negligence, whether or not such claim, demand, loss or liability was charged as Unit Expense under the terms of the Unitization Agreements. The amount of such indemnification shall be borne solely by the Field Contractor, and shall not be chargeable to any Contractor’s Net Profits Account.

 

Any claim, demand, loss or liability of any kind or nature, chargeable as Unit Expense pursuant to the terms of the Unitization Agreements, or, if not chargeable as Unit Expense under the Unitization Agreements, paid pursuant to a final judgment or a court of competent jurisdiction or at the direction of the City Manager acting with the approval of the State, arising out of or connected with work and operations under this agreement which the City, the State, the Field Contractor or the officers, agents, or employees of any of them may sustain or incur or which may be posed upon them or any of them for injury to or death of person or damages to property arising out of or in any manner connected with acts or omissions of the City, the State or the Field Contractor, not arising out of or in any manner connected with the negligent or other wrongful act or omission of or breach of this agreement, or any term, condition, or provision hereof, by the Field Contractor or its officers, agents or employees, not covered or to the extent not fully covered by insurance or self-insurance, and to the extent not paid as Unit Expense by Participants in Tracts other than Tract No. 1, shall be paid by the Contractors, in proportion to their respective Contractors’ Percentages, and each Contractor’s

 

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proportionate share of such cost, when so paid, shall be charged to such Contractor’s Net Profits Account. Each Contractor shall be entitled to reimbursement out of the “reserve for subsidence contingencies” for any claim, judgment or cost of defense arising from subsidence alleged to have occurred as a result of operations under this agreement if, and to the extent, provided for in Article 7 hereof.

 

(b)                                  Insurance

 

Field Contractor shall procure and maintain in full force and effect during the term of this agreement a policy, or policies, of public liability and property damage insurance from a company, or companies, authorized to do business in the State, with minimum limits of One Million Dollars ($1,000,000.00) for death or bodily injury or property damage sustained in any one occurrence. The policy shall either contain a provision for a broad form of contractual liability or there shall be attached thereto an endorsement providing for such coverage. The policy shall further provide that the same shall not be cancelled until a ten (10) day notice of cancellation has been served upon the City.  Field Contractor shall coincidentally with the execution of this agreement, deliver such policies of insurance, or certified or exact image copies thereof, to the City Manager and the State for approval, including approval as to the maximum amount of such policy or policies, and to the City Attorney for approval as to form. The cost of such insurance shall be paid when due by the Contractors in proportion to their respective Contractors’ Percentages, and each Contractor’s proportionate share of such cost, when so paid, shall be charged to such Contractor’s Net Profits Account. If directed by the City Manager, Field Contractor shall make full initial payment for such insurance, and in such event, each Nonoperating Contractor shall pay over to Field Contractor such Nonoperating Contractor’s Percentage of such payment within five (5) days’ notice of such payment by the Field Contractor or the City Manager.

 

If Field Contractor desires to self-insure such risk, or any portion thereof, it may include such risk under its self-insurance program subject to the approval and consent of the City Manager and the approval of the State; and in that event, each Non-operating Contractor shall pay to Field Contractor, upon five (5) days’ notice by the Field Contractor or the City Manager, a percentage of the fair and reasonable cost of such self-insurance (as fixed by the City Manager) equal to such Nonoperating Contractor’s Contractor’s Percentage. Each Contractor’s (including Field Contractor’s) Contractor’s Percentage of such cost shall be charged to such Contractor’s Net

 

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Profits Account.  In no event shall the cost of such self-insurance exceed the amount at which like insurance could be obtained from outside sources.

 

In addition, Field Contractor shall procure and maintain in full force and effect the insurance required of the Unit Operator in the Unit Operating Agreement. Such insurance shall name the persons insured as required by the Unit Operating Agreement, and Field Contractor shall also require any and all independent contractors performing work or services hereunder to carry insurance required by the Unit Operating Agreement. Since the cost of the insurance provided for in this paragraph will be paid as Unit Expense, it shall not otherwise be shared by Contractors and shall not otherwise be charged to any Contractor’s Net Profits Account.

 

The procuring of policies of insurance or the self-insurance of such risk as provided in this Article 31 shall not be construed to be a limitation upon Field Contractor’s liability, or as a full performance on its part of the indemnification provisions of this contract, Field Contractor’s obligations being, notwithstanding said policies of insurance or self-insurance, for the full and total amount of any damage, injury or loss covered by such indemnification provisions (over and above that covered by insurance) sustained in any one occurrence.

 

Article 32.                                          BONDS

 

Each Contractor shall, concurrently with the execution by it of this agreement, furnish or cause to be furnished, to City, and, at all times during the term hereof, maintain or cause to be maintained, in full force and effect, a good and sufficient bond in the following principal sums:

 

(1)                                  as to Field Contractor, eight million dollars ($8,000,000);

 

(2)                                  as to the Nonoperating Contractor with a ten percent (10%) Contractor’s Percentage, one million five hundred thousand dollars ($1,500,000);

 

(3)                                  as to the Nonoperating Contractor with a five percent (5%) Contractor’s Percentage, seven hundred fifty thousand dollars ($750,000);

 

(4)                                  as to the Nonoperating Contractor with a two and one-half percent (2 1/2%) Contractor’s Percentage, three hundred seventy-five thousand dollars ($375,000);

 

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(5)                                  as to the Nonoperating Contractor with a one and one-half percent (1 1/2%) Contractor’s Percentage, two hundred twenty-five thousand dollars ($225,000);

 

(6)                                  as to the Nonoperating Contractor with a one percent (1%) Contractor’s Percentage, one hundred fifty thousand dollars ($150,000).

 

Each said bond shall be executed by the Contractor, as principal, and as surety or sureties by a corporation or corporations, authorized and admitted to engage in the business of and to act as surety upon such bonds, pursuant to the laws of the State; provided, however, each such bond must be approved as to the surety and otherwise as to the sufficiency thereof by the City Manager and the State, and as to form thereof by the City Attorney and the Attorney General of the State of California. Each said bond shall be conditioned for the faithful performance by the Contractor of all and singular the terms, covenants and conditions of this agreement on the part of said Contractor to be done and performed, including, as to the Field Contractor’s bond, the full payment of the liens of all mechanics, laborers and materialman furnishing labor and/or material for the work done and the services performed by Field Contractor pursuant to the terms of this agreement, as said liens are provided for in Part III, Title IV, of the Code of Civil Procedure of the State of California, or may hereafter be provided for by any law of the State of California. The obligations and liabilities of the surety under any such bond shall be continuing obligations and liabilities; provided, however, that the surety under any such bond, upon giving at least sixty (60) days’ written notice to City by serving such notice upon the City Manager, and upon the principal, may terminate the liability of the surety thereunder solely and only for events, acts, omissions and defaults occurring after the expiration of said period of such notice. If the surety under any such bond shall serve any such notice of termination of liability as hereinabove provided, the Contractor named as principal thereunder shall, prior to the expiration of said period of such notice, furnish, or cause to be furnished, to City, as a substitute for such bond (the liability on which may be so terminated), a new bond, in the same principal sum as hereinabove provided, and conditioned the same as and meeting all of the requirements of the bond in this section first above required, and approved by the City Manager, the State, the City Attorney and the Attorney General as aforesaid. Notwithstanding any of the provisions of Article 15.1 hereof, if any Contractor, or the successors and/or assigns of any Contractor, shall fail to perform any of the terms, covenants and conditions set forth in this Article 31, for a period of six (6) days after

 

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written notice from City so to do, then all rights and privileges under this agreement of such Contractor, or its successors and/or assigns hereunder, shall, at the option of the City, exercisable with the approval of the State, forthwith cease and terminate.

 

The City Manager, with the approval of the State, may, at his sole discretion, in the future order the amount of any of the aforesaid surety bonds to be reduced.

 

The actual cost of each Contractor’s bond, not to exceed one percent (1%) per year of the principal amount thereof, shall be charged to such Contractor’s Net Profits Account.

 

Article 33.                                          FORCE MAJEURE

 

All obligations of each party hereto, except for the payment of money, shall be suspended while said party is prevented from complying therewith, in whole or in part, by strikes, lockouts, fire, war, civil disturbances, acts of God, federal, state, county or municipal laws, orders or regulations, inability to secure materials, unavoidable accidents or other causes beyond the reasonable control of said party, whether or not similar to the matters herein specifically enumerated; provided, however, that performance shall be resumed within a reasonable time after such cause has been removed; and provided further that no party hereto shall be required against its will to adjust or settle any labor dispute. This agreement shall not be terminated by reason of suspension of Unit Operations due to the aforesaid causes. No party hereto shall incur any liability hereunder by reason of compliance in good faith with any such law, rule, regulation or order, irrespective of whether it is subsequently determined to be invalid or inapplicable.

 

Article 34.                                          REFORMATION TO CONFORM TO APPLICABLE LAW

 

Nothing herein contained shall be construed as being in any manner in derogation of any of the valid and operative terms, conditions, or provisions of Chapter 138, the City Ordinance, the Code, or other applicable laws; but to the contrary, this agreement and each and every part thereof shall in all particulars be deemed amenable to reformation to eliminate or modify any portions thereof found to be in contravention of any of the aforesaid terms, conditions or provisions, or against public policy, and shall remain and be in full force and effect as to all provisions not so eliminated or modified.

 

52



 

Article 35.                                          CONTRACTORS MAY CONSIST OF SEVERAL PERSONS

 

If any Contractor shall at any time consist of more than one Person, all reference to such Contractor in this agreement shall be deemed to refer to each and every of such Persons, and each Person Comprising any Contractor shall be jointly and severally obligated to perform all the obligations of such Contractor under this agreement, except as hereinafter in this article otherwise provided. Each of the Persons Comprising any Contractor may perform hereunder any or all of the obligations of such Contractor.

 

This section shall not be construed to impose upon any Contractor any obligation greater than or in addition to that which would exist if such Contractor were a single person.

 

Article 36.                                          NOTICES

 

Any notice required or permitted to be given to the City, the State, or the Contractors shall be deemed to have been given twenty-four (24) hours after such notice is deposited in the United States mail as registered or certified mail, with postage thereon fully prepaid, addressed to such party at its address set forth under or opposite its signature to this agreement, or when such notice is filed as a telegram with the Western Union Telegraph Company or any successor in interest of said telegraph company, addressed as above provided with all charges thereon fully prepaid; provided, however, if any action, based upon such notice may be taken within twenty-four (24) hours, such notice shall be deemed given when received. Any notice given in any other fashion shall be deemed to have been given when actually received by the addressee.  Any party may change its address by giving written notice to the other parties. Any notice required or permitted to be given to or by the City shall be directed to or signed by the City Manager. Any notice required or permitted to be given to or by the State shall be directed to or signed by the Executive Officer of the State Lands Commission.

 

Article 37.                                          GENDER AND HEADINGS

 

As used herein, whenever the context so requires, the neuter gender includes the masculine and the feminine, and the singular includes the plural and vice versa. Defined terms are to have their defined meanings regardless of the grammatical form, number or tense of such terms. The table of contents contained in this agreement and the title headings of the respective articles and sections of this agreement are inserted for convenience only, and shall not be deemed a part of this agreement or considered in construing this agreement.

 

53



 

Article 38.                                          SUCCESSORS AND ASSIGNS

 

The terms, provisions and conditions hereof shall be binding upon and inure to the benefit of the respective heirs, administrators, executors, successors and assigns of the parties hereto.

 

Article 39.                                          COUNTERPARTS

 

This agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument and as if all of the parties to the aggregate counterparts had signed the same instrument. The signature pages of this agreement may be detached by the City from any counterpart of this Contractors’ Agreement without impairing the legal effect of any signatures thereon and may be attached to another counterpart of this Contractors’ Agreement identical in form hereto by having attached to it one or more additional signature pages.

 

IN WITNESS WHEREOF each party hereto has executed this Contractors’ Agreement upon the date set opposite its name.

 

54



 

ATTACHED TO AND MADE A PART OF
THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,
WILMINGTON OIL FIELD, CALIFORNIA

 

Address 303 City Hall

CITY OF LONG BEACH, a municipal corporation

Long Beach, Calif.

 

March 2, 1965

 

 

 

By:

/s/ John R. Mansel

 

Title:

City Manager

 

 

 

 

STATE OF CALIFORNIA

)

 

)ss.

COUNTY OF SACRAMENTO

)

 

On March 2, 1965, before me, the undersigned, a Notary Public in and for the County of Sacramento, State of California, personally appeared JOHN R. MANSELL, known to me to be the City Manager of the City of Long Beach, and known to me to be the person who executed the within instrument on behalf of said City of Long Beach.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal on the day and year in this certificate first above written.

 

 

 

/s/ Alice J. Clover

 

Notary Public in and for the County

 

of Sacramento, State of California

 

ALICE J. CLOVER

 

My Commission Expires: June 15, 1974

 

[Notary Seal]

 

The Contractors’ Agreement, Long Beach Unit, Wilmington Oil Field, Los Angeles County, California, is hereby approved as to form this 2 nd  day of March, 1965.

 

 

LEONARD PUTNAM, City Attorney

 

 

 

By:

/s/ Harold A. Lingle

 

 

Chief Deputy

 


 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 135 East 42 nd  St.

TEXACO Inc.

New York, New York 10017

Field Contractor or Person Comprising Field Contractor

February 24, 1965

 

 

 

 

By

/s/ M.J. Epley, Jr.

 

 

President

 

 

 

 

Attest:

/s/ William J. Clayton

 

 

Secretary

 

STATE OF NEW YORK

)

 

 

)

ss.

COUNTY OF NEW YORK

)

 

 

On February 24, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared M. J. Epley, Jr., known to me to be the President, and William J. Clayton, known to me to be the Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Robert C. Gross

 

Notary Public in and for said County and State

 

ROBERT C. GROSS

 

Commission Expires March 30, 1965

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  800 Bell Street

Humble Oil & Refining Company

Houston, Texas  77001

Field Contractor or Person Comprising Field Contractor

February 24, 1965

 

 

 

 

 

 

By

/s/ Chas. F. Jones

 

 

President

 

 

 

 

Attest:

/s/ L. J. Weigle

 

 

Secretary

 

STATE OF TEXAS

)

 

 

)

ss.

COUNTY OF HARRIS

)

 

 

On February 24, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared Chas. F. Jones, known to me to be the President, and L. J. Weigle, known to me to be the Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Dwain Gay

 

Notary Public in and for said County and State

 

Dwain Gay

 

My Commission Expires June 1, 1965

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  461 S. Boylston Street

UNION OIL COMPANY OF CALIFORNIA

Los Angeles, California  90017

Field Contractor or Person Comprising Field Contractor

February 24, 1965

 

 

 

 

 

 

By

/s/ Fred L. Hartley

 

 

President

 

 

 

 

Attest:

/s/ H.F. Niven

 

 

Secretary

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On February 24, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared Fred L. Hartley, known to me to be the President, and H. F. Niven, known to me to be the Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Kathryn Alice Kelm

 

Notary Public in and for said County and State

 

KATHRYN ALICE KELM

 

My Commission Expires May 25, 1968

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 150 East 42 nd  Street

SOCONY MOBIL OIL COMPANY, INC.

New York, New York 10017

Field Contractor or Person Comprising Field Contractor

Feb. 26, 1965

 

 

 

 

 

 

By

/s/ Rawleigh Warner, Jr.

 

 

President

 

 

 

 

Attest:

/s/ A. M. Sherwood

 

 

Secretary

 

STATE OF NEW YORK

)

 

 

)

ss.

COUNTY OF NEW YORK

)

 

 

On February 26, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared Rawleigh Warner, Jr., known to me to be the President, and A. M. Sherwood, known to me to be the Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Elizabeth Conroy

 

Notary Public in and for said County and State

 

ELIZABETH CONROY

 

My Commission Expires March 30, 1966

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 50 West 50 th  Street

SHELL OIL COMPANY

New York, New York 10020

Field Contractor or Person Comprising Field Contractor

February 25, 1965

 

 

 

 

 

 

By

/s/ [Signature illegible]

 

 

President

 

 

 

 

Attest:

/s/ [Signature illegible]

 

 

Secretary

 

STATE OF NEW YORK

)

 

 

)

ss.

COUNTY OF NEW YORK

)

 

 

On February 25, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared [Signature illegible] , known to me to be the President, and [Signature illegible] , known to me to be the Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Florence J. Sylvestre

 

Notary Public in and for said County and State

 

FLORENCE J. SYLVESTRE

 

My Commission Expires March 30, 1966

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 10,000 Santa Monica Blvd.

PAULEY PETROLEUM INC.

Los Angeles, California 90067
March 2, 1965

Nonoperating Contractor with a ten percent (10%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ W. R. Pagen

 

 

President

 

 

 

 

Attest:

/s/ Orris R. Hedges

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF SACRAMENTO

)

 

 

On March 2, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared W. R. Pagen, known to me to be the President, and Orris R. Hedges, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Alice J. Clover

 

Notary Public in and for said County and State

 

ALICE J. CLOVER

 

My Commission Expires June 16, 1968

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 61 Broadway 

ALLIED CHEMICAL CORPORATION

New York, New York
March 2, 1965

Nonoperating Contractor with a ten percent (10%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ J. H. Munro

 

 

Vice President

 

 

 

 

Attest:

/s/ Victor Futter

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF SACRAMENTO

)

 

 

On March 2, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared J. H. Munro, known to me to be the Vice President, and Victor Futter, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Alice J. Clover

 

Notary Public in and for said County and State

 

ALICE J. CLOVER

 

My Commission Expires June 16, 1968

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 555 South Flower St.

Richfield Oil Corporation

Los Angeles, California
March 2, 1965

Nonoperating Contractor with a five percent (5%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ R. W. Ragland

 

 

Vice President

 

 

 

 

Attest:

/s/ R. G. Nelson

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On March 2, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared R. W. Ragland, known to me to be the Vice President, and R. G. Nelson, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Sue M. Mason

 

Notary Public in and for said County and State

 

SUE M. MASON

 

My Commission Expires May 4, 1968

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 225 Bush Street

Standard Oil Company of California

San Francisco, California
March 1, 1965

Nonoperating Contractor with a five percent (5%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ O. N. Miller

 

 

President

 

 

 

 

Attest:

/s/ E. A. Hansen

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

CITY AND

)

ss.

/COUNTY OF SAN FRANCISCO

)

 

 

On March 5, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared O. N. Miller, known to me to be the President, and E. A. Hansen, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Edmond Lee Kelly

 

Notary Public in and for said County and State

 

EDMOND LEE KELLY

 

My Commission Expires

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 555 South Flower St.

Richfield Oil Corporation

Los Angeles, California
March 2, 1965

Nonoperating Contractor with a two and one-half percent (2-1/2%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ R. W. Ragland

 

 

Vice President

 

 

 

 

Attest:

/s/ R. G. Nelson

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On March 2, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared R. W. Ragland, known to me to be the Vice President, and R. G. Nelson, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Sue M. Mason

 

Notary Public in and for said County and State

 

SUE M. MASON

 

My Commission Expires May 4, 1968

 

[Notary Seal]

 


 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 225 Bush Street

Standard Oil Company of California

San Francisco, California
March 1, 1965

Nonoperating Contractor with a two and one-half percent (2-1/2%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ O. N. Miller

 

 

President

 

 

 

 

Attest:

/s/ E. A. Hansen

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF SAN FRANCISCO

)

 

 

On March 5, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared O. N. Miller, known to me to be the President, and E. A. Hansen, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Edmond Lee Kelly

 

Notary Public in and for said County and State

 

EDMOND LEE KELLY

 

My Commission Expires

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 555 South Flower St.

Richfield Oil Corporation

Los Angeles, California
March 2, 1965

Nonoperating Contractor with a one and one-half percent (1-1/2%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ R. W. Ragland

 

 

Vice President

 

 

 

 

Attest:

/s/ R. G. Nelson

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On March 2, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared R. W. Ragland, known to me to be the Vice President, and R. G. Nelson, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Sue M. Mason

 

Notary Public in and for said County and State

 

SUE M. MASON

 

My Commission Expires May 4, 1968

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 225 Bush Street

Standard Oil Company of California

San Francisco, California
March 1, 1965

Nonoperating Contractor with a one and one-half percent (1-1/2%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ O. N. Miller

 

 

President

 

 

 

 

Attest:

/s/ E. A. Hansen

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

CITY AND

)

ss.

COUNTY OF SAN FRANCISCO

)

 

 

On March 5, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared O. N. Miller, known to me to be the President, and E. A. Hansen, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Edmond Lee Kelly

 

Notary Public in and for said County and State

 

EDMOND LEE KELLY

 

My Commission Expires

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 555 South Flower St.

Richfield Oil Corporation

Los Angeles, California
March 2, 1965

Nonoperating Contractor with a one percent (1%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ R. W. Ragland

 

 

Vice President

 

 

 

 

Attest:

/s/ R. G. Nelson

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On March 2, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared R. W. Ragland, known to me to be the Vice President, and R. G. Nelson, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Sue M. Mason

 

Notary Public in and for said County and State

 

SUE M. MASON

 

My Commission Expires May 4, 1968

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE CONTRACTORS’ AGREEMENT, LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address 225 Bush Street

Standard Oil Company of California

San Francisco, California
March 1, 1965

Nonoperating Contractor with a one percent (1%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

 

By

/s/ O. N. Miller

 

 

President

 

 

 

 

Attest:

/s/ E. A. Hansen

 

 

Assistant Secretary

 

STATE OF CALIFORNIA

)

 

CITY AND

)

ss.

COUNTY OF SAN FRANCISCO

)

 

 

On March 5, 1965, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared O. N. Miller, known to me to be the President, and E. A. Hansen, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Edmond Lee Kelly

 

Notary Public in and for said County and State

 

EDMOND LEE KELLY

 

My Commission Expires

 

[Notary Seal]

 



 

Amendments

 

Contractors’ Agreement
Long Beach Unit
Wilmington Oil Field, California

 



 

FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT

 

LONG BEACH UNIT

 

WILMINGTON OIL FIELD, CALIFORNIA.

 

RECITALS

 

This is the First Amendment to the Contractors’ Agreement entered into by and between the City of Long Beach, a municipal corporation, and the Contractors named in said Contractors’ Agreement, which agreement became effective April 1, 1965.

 

As of the date hereof, Exxon Corporation has succeeded to all of the rights and obligations of Humble Oil & Refining Company under said Contractors’ Agreement, Pauley Petroleum, Inc. has succeeded to all of the rights and obligations of Allied Chemical Corporation under said Contractors’ Agreement, Atlantic Richfield Company has succeeded to all of the rights and obligations of Richfield Oil Corporation under said Contractors’ Agreement, and Socony Mobil Oil Company, Inc. has changed its name to Mobil Oil Corporation.

 

The purpose of this First Amendment is to set forth the revised rights and obligations of the City of Long Beach and the Contractors with respect to the treatment, processing and handling of gas, and to set forth the respective rights and obligations of the City of Long Beach and the Contractors with respect to insurance which cannot be obtained or the cost of obtaining of which appears to be unreasonably high.

 

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements herein contained, it is agreed as follows:

 

1.                                       Section 1.i. of Article 1. DEFINITIONS of said Contractors’ Agreement is revised to read, in its entirety, as follows:

 

i.                                           Current Operating Profits attributable to any Contractor for any calendar month

 

(1)                                 Through June 30, 1972 means the excess of the Value of Oil Allocated to such Contractor during such month plus the Value of Wet Gas Products Attributable to such Contractor during such month over and above such Contractor’s Percentage of the Operating Costs attributable to Tract No. 1 during such month;

 

1



 

(2)                                 From and after July 1, 1972, means the excess of the Value of Oil Allocated to such Contractor during such month plus the Value of Wet Gas Products Allocated to such Contractor during such month over and above such Contractor’s Percentage of the Operating Costs attributable to Tract No. 1 during such month.

 

2.                                       Section 1.o of Article 1. DEFINITIONS of said Contractors’ Agreement is revised to read, in its entirety, as follows:

 

o.                                       Payment, Contribution or Subsidy received by Field Contractor or any Nonoperating Contractor shall mean any amounts received by Field Contractor or any Nonoperating Contractor as payment, contribution, or subsidy in connection with operations under this agreement; excluding, however, any amounts which are not to be credited to Field Contractor’s or any Nonoperating Contractor’s Net Profits Account under the terms hereof, any amounts received by any Contractor as consideration for Oil Allocated to such Contractor, any amounts received by any Contractor as consideration for Wet Gas Products Attributable to such Contractor through June 30, 1972, any amounts received by any Contractor for Wet Gas Products Allocated to such Contractor from and after July 1, 1972, any amount received by any Contractor as consideration for any assignment hypothecation or pledge of its right to receive oil or Wet Gas Products hereunder made pursuant to Article 25 hereof, any compensation for processing Wet Gas Allocated to such Contractor, and any amount credited to such Contractor’s Net Profits Account other than as Payment, Contribution or Subsidy.

 

3.                                       Section l.ee. is added to Article 1. DEFINITIONS of said Contractors’ Agreement to read, in its entirety, as follows:

 

ee.                                  Wet Gas Products Allocated to any Contractor means such Contractor’s Participant Allocation of Wet Gas Products attributable to such Contractor’s Working Interest in Tract No. 1, or, stated otherwise,

 

2



 

such Contractor’s Percentage of the sum of the Participant Allocations of Wet Gas Product attributable to the Contract Lands.

 

4.                                       Section 1.ff. is added to Article 1. DEFINITIONS of said Contractors’ Agreement to read, in its entirety, as follows:

 

ff.                                    Value of Wet Gas Products Allocated to any Contractor means the value of Wet Gas Products Allocated to such Contractor, computed in accordance with the provisions of Article 10 hereof.

 

5.                                       Section 1.gg. is added to Article 1. DEFINITIONS of said Contractors’ Agreement to read, in its entirety, as follows:

 

gg.                                  Residue Dry Gas Allocated to any Contractor means such Contractor’s Participant Allocation of Residue Dry Gas attributable to such Contractor’s Working Interest in Tract No. 1, or, stated otherwise, such Contractor’s Percentage of the sum of the Participant Allocations of Residue Dry Gas attributable to the Contract Lands.

 

6.                                       Section 4. (a) (1) (b) of Article 4.  CONTRACTORS’ NET PROFITS of said Contractors’ Agreement is hereby revised to read, in its entirety, as follows:

 

(b)                                  Through June 30, 1972, the total Value of Wet Gas Products Attributable to such Contractor plus, from and after July 1, 1972, the total Value of Wet Gas Products Allocated to such Contractor.

 

7.                                       Article 10. GAS PROCESSING AND VALUE of said Contractors’ Agreement is hereby revised to read, in its entirety, as follows:

 

Article 10. GAS

 

The Long Beach Unit has heretofore by Determination undertaken to treat and is now treating all Wet Gas by processing such Wet Gas for the extraction of Wet Gas Products and hydrogen sulfide, and has allocated the Residue Dry Gas and Wet Gas Products remaining after such treatment of such Wet Gas to Participants of the Long Beach Unit.

 

From and after July 1, 1972, each Contractor shall no longer have the right or obligation to treat Wet Gas Allocated to such Contractor but the  City shall cause the Long Beach Unit to have the exclusive right and be obligated to treat all Wet Gas, including without limitation all Wet Gas

 

3



 

Allocated to each Contractor, by processing such Wet Gas for the extraction of Wet Gas Products, hydrogen sulfide and non-marketable contaminants, and shall further cause the Long Beach Unit to allocate Residue Dry Gas and Wet Gas Products remaining after such treatment of such Wet Gas to Participants as provided in Article 10 of the Unit Operating Agreement. From and after July 1, 1972, each Contractor Shall deliver to the City, or the City’s order, at no cost to such Contractor, all Residue Dry Gas Allocated to such Contractor, at the regular delivery point or points therefor in the Field (as provided in the Unit Agreement) where such Contractor has the right and obligation to accept such gas in kind currently as available for delivery and at the same moment in time, pressure, quality and condition as such Contractor accepts such gas. None of such Residue Dry Gas or such Wet Gas shall ever become the property of any Contractor at any time nor shall it be credited to any Contractor’s Net Profit Account, but this sentence shall have no application to Wet Gas Products Allocated to any Contractor. Any such Residue Dry Gas, or other dry gas equivalent thereto, necessary for Unit Operations shall be caused by the City to be returned to the Unit Operator in accordance with the Unit Agreement at no cost to any Contractor.

 

From and after duly 1, 1972, each Contractor shall have the exclusive right to take and shall be obligated to take and to account for all Wet Gas Products Allocated to such Contractor. All Wet Gas Products Allocated to each Contractor shall be valued and accounted for on the basis of the highest price posted or paid in the Field for natural gasoline of like grade and like quality on the day of taking, and the prevailing market price for other liquid or liquefied hydrocarbon products of like grade and like quality in the Field on the day of taking.

 

8.                                       Section 31.(b)  Insurance of Article 31. INDEMNITY  AND INSURANCE of said Contractors’ Agreement is hereby revised to read, in its entirety, as follows:

 

4


 

(b)           Insurance

 

Field Contractor shall procure and maintain in full force and effect during the term of this agreement a policy, or policies, of public liability and property damage insurance from a company, or companies, authorized to do business in the State, with minimum limits of One Million Dollars ($1,000,000.00) for death or bodily injury or property damage sustained in any one occurrence. The policy shall either contain a provision for a broad form of contractual liability or there shall be attached thereto an endorsement providing for such coverage. The policy shall further provide that the same shall not he cancelled until a ten (10) day notice of cancellation has been served upon the City. Field Contractor shall coincidentally with the execution of this agreement, deliver such policies of insurance, or certified or exact image copies thereof, to the City Manager and the State for approval, including approval as to the maximum amount of such policy or policies, and to the City Attorney for approval as to form. The cost of such insurance shall be paid when due by the Contractors in proportion to their respective Contractors’ Percentages, and each Contractor’s proportionate share of such cost, when so paid, shall he charged to such Contractor’s Net Profits Account. If directed by the City Manager, Field Contractor shall make full initial payment for such insurance, and in such event, each Nonoperating Contractor shall pay over to Field Contractor such Nonoperating Contractor’s Percentage of such Payment within five (5) days’ notice of such payment by the Field Contractor or the City Manager.

 

If Field Contractor desires to self-insure such risk, or any portion thereof, it may include such risk under its self-insurance program subject to the approval and consent of the City Manager and the approval of the State; and in that event, each Nonoperating Contractor shall Pay to Field Contractor, upon five (5) days’ notice by the Field Contractor or the City Manager, a percentage of the fair and reasonable cost of such self-insurance (as fixed by the City Manager) equal to such Nonoperating

 

5



 

Contractor’s Contractor’s Percentage. Each Contractor’s (including Field Contractor’s) Contractor’s Percentage of such cost shall be charged to such Contractor’s Net Profits Account. In no event shall the cost of such self-insurance exceed the amount at which like insurance could be obtained from outside sources.

 

If upon determination by the City that the Field Contractor cannot obtain any portion of the full amount and coverage of the insurance policy described in the first paragraph of this Article 31.(b), or that the cost of obtaining any portion of the full amount and coverage of such policy appears to the City to be unreasonably high, the Field Contractor may, with the approval and consent of the City and the approval of the State, treat such portion of the full amount and coverage of such policy that it cannot obtain, or the cost of obtaining of which appears to be unreasonably high, on an unfunded self-insurance basis as if such portion had been provided by the insurance policy then current in effect and approved as described in the first paragraph of this Article 31.(b) and subject to the dollar limits, conditions, limitations and provisions thereof; and in that event, each Contractor shall pay a percentage, equal to such Contractor’s Contractor’s Percentage, of all costs and expenses of handling and defending, and settling or discharging, any claim, demand, suit, action or judgment relating thereto, to the extent and as if such portion had been provided by the insurance policy then currently in effect and approved as described in the first paragraph of this Article 31.(b) and subject to the dollar limits, conditions, limitations and provisions thereof.  Each Contractor’s (including Field Contractor’s) Contractor’s Percentage of such costs and expenses shall be charged to such Contractor’s Net Profit Account.

 

In addition, Field Contractor shall procure and maintain in full force and effect the insurance required of the Unit Operator in the Unit Operating Agreement. Such insurance shall name the persons insured as required by the Unit Operating Agreement, and Field Contractor shall also

 

6



 

require any and all independent contractors performing work or services hereunder to carry insurance required by the Unit Operating Agreement. Since the cost of the insurance provided for in this paragraph will be paid as Unit Expense, it shall not otherwise be shared by Contractors and shall not otherwise be charged to any Contractor’s Net Profits Account.

 

The procuring of policies of insurance or the self-insurance of such risk as provided in this Article 31 shall not be construed to be a limitation upon Field Contractor’s liability, or as a full performance on its part of the indemnification provisions of this contract, Field Contractor’s obligations being, notwithstanding said policies of insurance or self-insurance, for the full and total amount of any damage, injury or loss covered by such indemnification provisions (over and above that covered by insurance) sustained in any one occurrence.

 

This First Amendment may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument and as if all of the parties to the aggregate counterparts had signed the same instrument. The signature pages of this First Amendment may be detached by the City from any counterpart of this First Amendment without impairing the legal effect of any signatures thereon and may be attached to another counterpart of this First Amendment identical in form hereto by having attached to it one or more additional signature Pages.

 

This First Amendment is effective as of July 1, 1972 as to items 1 through 7, and is effective as of May 25, 1971 as to item 8.

 

IN WITNESS WHEREOF each party hereto has executed this First Amendment upon the date set opposite its name.

 

7



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  303 City Hall

CITY OF LONG BEACH, a municipal corporation

Long Beach, CA  90802

 

July 19, 1973

By:

/s/ John R. Mansell

 

Title:

City Manager

 

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On July 19, 1973, before me, the undersigned, a Notary Public in and for the County of Sacramento, State of California, personally appeared JOHN R. MANSELL, known to me to be the City Manager of the City of Long Beach, and known to me to be the person who executed the within instrument on behalf of said City of Long Beach.

 

IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official seal on the day and year in this certificate first above written.

 

 

 

/s/ Sally Valinski

 

Notary Public in and for the County

 

of Los Angeles, State of California

 

SALLY VALINSKI

 

My Commission Expires June 14, 1976

 

[Notary Seal]

 

The First Amendment to Contractors’ Agreement, Long Beach Unit, Wilmington Oil Field, Los Angeles County, California, is hereby approved as to form this 18 th  day of July, 1973.

 

 

LEONARD PUTNAM, City Attorney

 

 

 

By

/s/ [Illegible Signature]

 

 

Chief Deputy

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  3350 Wilshire Blvd.

TEXACO Inc.

Los Angeles, Calif.  90010

Field Contractor or Person Comprising Field Contractor

April 27, 1973

 

 

By

/s/ H. O. Woodruff

 

 

Sr. Vice President

 

 

 

 

Attest:

/s/ Heleyne Pauling

 

 

Asst. Secretary

 

 

STATE OF California

)

 

 

)

ss.

COUNTY OF Los Angeles

)

 

 

On April 27, 1973, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared H. O. Woodruff, known to me to be the Senior Vice President, and Heleyne Pauling, known to me to be the Asst. Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Esther V. Bozanich

 

Notary Public in and for said County and State

 

ESTHER V. BOZANICH

 

Commission Expires September 1, 1974

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  461 S. Boylston Street

UNION OIL COMPANY OF CALIFORNIA

Los Angeles, California  90017

Field Contractor or Person Comprising Field Contractor

May 8, 1973

 

 

By

/s/ John R. Fraser

 

 

Its Attorney in Fact

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On May 8, 1973, before me, the undersigned, a Notary Public in and for said State, personally appeared John R. Fraser, known to me to be the person whose name is subscribed to the within instrument, as the Attorney-in-Fact for Union Oil Company of California, and acknowledged to me that he subscribed the name of Union Oil Company of California thereto as principal and his own name as Attorney-in-Fact.

 

WITNESS my hand and official seal

 

 

 

/s/ M. I. Young

 

Notary Public in and for said County and State

 

M. I. YOUNG

 

My Commission Expires July 20, 1974

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  150 East 42 nd  Street

MOBIL OIL COMPANY, INC.

New York, N.Y.  10017

Field Contractor or Person Comprising Field Contractor

April 9 th , 1973

 

 

By

/s/ H. K. Holland

 

 

Vice President

 

 

 

 

Attest:

/s/ G. D. Frost

 

 

Asst. Secretary

 

 

STATE OF NEW YORK

)

 

 

)

ss.

COUNTY OF NEW YORK

)

 

 

On April 9 th , 1973, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared H. K. Holland, known to me to be the Vice President, and G. D. Frost, known to me to be the Asst. Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Joseph Zolnowski

 

Notary Public in and for said County and State

 

JOSEPH ZOLNOWSKI

 

My Commission Expires March 30, 1974

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  1008 W. Sixth Street

SHELL OIL COMPANY

Los Angeles, California  90017

Field Contractor or Person Comprising Field Contractor

April 2, 1973

 

 

By

/s/ H. R. Thompson

 

 

General Manager

 

 

 

 

Attest:

/s/ B. G. Warren

 

 

Assistant Secretary

 

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On April 2, 1973, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared H. R. Thompson, known to me to be the General Manager, West Coast Division, and B. G. Warren, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Christel H. Mintz

 

Notary Public in and for said County and State

 

CHRISTEL H. MINTZ

 

My Commission Expires Oct. 29, 1974

 

[Notary Seal]

 



 

 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  10,000 Santa Monica Blvd.

PAULEY PETROLEUM INC.

Los Angeles, California 90067

April 27, 1973

Nonoperating Contractor with a ten percent (10%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ W. R. Pagen

 

 

President

 

 

 

 

Attest:

/s/ Edward Kliewer, Jr.

 

 

Secretary

 

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF LOS ANGELES

)

 

 

On April 27, 1973, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared W. R. Pagen, known to me to be the President, and Edward Kliewer, Jr., known to me to be the Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Jean J. Myers

 

Notary Public in and for said County and State

 

JEAN J. MYERS

 

My Commission Expires Jan. 26, 1977

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  225 Bush Street

STANDARD OIL COMPANY OF CALIFORNIA

San Francisco, California

April, 1973

Nonoperating Contractor with a five percent (5%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ K. T. Derr

 

 

Vice President

 

 

 

 

Attest:

/s/ D. N. Maytum

 

 

Assistant Secretary

 

 

STATE OF CALIFORNIA

)

 

CITY AND

)

ss.

/COUNTY OF SAN FRANCISCO

)

 

 

On April 11, 1973, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared K. T. Derr, known to me to be the Vice President, and D. N. Maytum, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Edmond Lee Kelly

 

Notary Public in and for said County and State

 

EDMOND LEE KELLY

 

My Commission Expires Jan. 22, 1976

 

[Notary Seal]

 


 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  P.O. Box 147

Atlantic Richfield Company

Bakersfield, CA  93302

                              , 1973

Nonoperating Contractor with a five percent (5%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ R. O. Pollard

 

 

Its Attorney in Fact

 

 

 

 

Attest:

 

 

 

Secretary

 

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF KERN

)

 

 

On April 13, 1973 before me, the undersigned, a Notary Public in and for said State, personally appeared R. O. Pollard, known to me to be the person whose name is subscribed to the within instrument, as the Attorney-in-Fact of Atlantic Richfield Company, and acknowledged to me that he subscribed the name of Atlantic Richfield Company thereto as principal and his own name as Attorney-in-Fact.

 

WITNESS my hand and official seal.

 

 

 

/s/ Mary Pauly

 

Notary Public in and for said County and State

 

MARY PAULY

 

My Commission Expires September 14, 1974

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  225 Bush Street

STANDARD OIL COMPANY OF CALIFORNIA

San Francisco, California

April                     , 1973

Nonoperating Contractor with a two and one-half percent (2-1/2%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ K. T. Derr

 

 

Vice President

 

 

 

 

Attest:

/s/ D. N. Maytum

 

 

Assistant Secretary

 

 

STATE OF CALIFORNIA

)

 

CITY AND

)

ss.

/COUNTY OF SAN FRANCISCO

)

 

 

On April 11, 1973, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared K. T. Derr, known to me to be the Vice President, and D. N. Maytum, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Edward Lee Kelly

 

Notary Public in and for said County and State

 

EDWARD LEE KELLY

 

My Commission Expires Jan. 22, 1976

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  P.O. Box 147

Atlantic Richfield Company

Bakersfield, CA  93302

                                , 1973

Nonoperating Contractor with a two and one-half percent (2-1/2%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ R. O. Pollard

 

 

Vice President

 

 

 

 

Attest:

 

 

 

Secretary

 

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF KERN

)

 

 

On April 13, 1973, before me, the undersigned, a Notary Public in and for said State, personally appeared R. O. Pollard, known to me to be the person whose name is subscribed to the within instrument, as the Attorney-in-Fact of Atlantic Richfield Company, and acknowledged to me that he subscribed the name of Atlantic Richfield Company thereto as principal and his own name as Attorney-in-Fact.

 

WITNESS my hand and official seal.

 

 

 

/s/ Mary Pauly

 

Notary Public in and for said County and State

 

MARY PAULY

 

My Commission Expires September 14, 1974

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  225 Bush Street

STANDARD OIL COMPANY OF CALIFORNIA

San Francisco, California

April, 1973

Nonoperating Contractor with a one and one-half percent (1-1/2%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ E. D. Kane

 

 

Vice President

 

 

 

 

Attest:

/s/ D. N. Maytum

 

 

Assistant Secretary

 

 

STATE OF CALIFORNIA

)

 

CITY AND

)

ss.

/COUNTY OF SAN FRANCISCO

)

 

 

On April 11, 1973, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared E. D. Kane, known to me to be the Vice President, and D. N. Maytum, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Edmond Lee Kelly

 

Notary Public in and for said County and State

 

EDMOND LEE KELLY

 

My Commission Expires Jan. 22, 1976

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  P.O. Box 147

Atlantic Richfield Company

Bakersfield, CA  93302

                                , 1973

Nonoperating Contractor with a one and one-half percent (1-1/2%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ R. O. Pollard

 

 

Vice President

 

 

 

 

Attest:

 

 

 

Secretary

 

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF KERN

)

 

 

On April 13, 1973, before me, the undersigned, a Notary Public in and for said State, personally appeared R. O. Pollard, known to me to be the person whose name is subscribed to the within instrument, as the Attorney-in-Fact of Atlantic Richfield Company, and acknowledged to me that he subscribed the name of Atlantic Richfield Company thereto as principal and his own name as Attorney-in-Fact.

 

WITNESS my hand and official seal.

 

 

 

/s/ Mary Pauly

 

Notary Public in and for said County and State

 

MARY PAULY

 

My Commission Expires September 14, 1974

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  225 Bush Street

STANDARD OIL COMPANY OF CALIFORNIA

San Francisco, California

April                         , 1973

Nonoperating Contractor with a one percent (1%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ E. D. Kane

 

 

Vice President

 

 

 

 

Attest:

/s/ D. N. Maytum

 

 

Assistant Secretary

 

 

STATE OF CALIFORNIA

)

 

CITY AND

)

ss.

/COUNTY OF SAN FRANCISCO

)

 

 

On April 11, 1973, before me, the undersigned, a Notary Public in and for the said County and State, personally appeared E. D. Kane, known to me to be the Vice President, and D. N. Maytum, known to me to be the Assistant Secretary of the corporation that executed the within instrument, known to me to be the persons who executed the within instrument on behalf of the corporation therein named, and acknowledged to me that such corporation executed the within instrument pursuant to its bylaws or a resolution of its Board of Directors.

 

 

 

/s/ Edmond Lee Kelly

 

Notary Public in and for said County and State

 

EDMOND LEE KELLY

 

My Commission Expires Jan. 22, 1976

 

[Notary Seal]

 



 

ATTACHED TO AND MADE A PART OF

 

THE FIRST AMENDMENT TO CONTRACTORS’ AGREEMENT,

 

LONG BEACH UNIT,

 

WILMINGTON OIL FIELD, CALIFORNIA

 

Address  P.O. Box 147

Atlantic Richfield Company

Bakersfield, CA  93302

                                , 1973

Nonoperating Contractor with a one percent (1%) Contractor’s Percentage or Person Comprising such Nonoperating Contractor

 

 

 

By

/s/ R. O. Pollard

 

 

Its Attorney-in-Fact

 

 

 

 

Attest:

 

 

 

Secretary

 

 

STATE OF CALIFORNIA

)

 

 

)

ss.

COUNTY OF KERN

)

 

 

On April 13, 1973, before me, the undersigned, a Notary Public in and for said State, personally appeared R. O. Pollard, known to me to be the person whose name is subscribed to the within instrument, as the Attorney-in-Fact of Atlantic Richfield Company, and acknowledged to me that he subscribed the name of Atlantic Richfield Company thereto as principal and his own name as Attorney-in-Fact.

 

WITNESS my hand and official seal.

 

 

 

/s/ Mary Pauly

 

Notary Public in and for said County and State

 

MARY PAULY

 

My Commission Expires September 14, 1974

 

[Notary Seal]

 




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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION

Table of Contents


Exhibit 99.1

                    , 2014
Dear Occidental Petroleum Corporation Stockholder:

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

        The spin-off will be completed by way of a pro rata distribution on                    , 2014 of at least 80.1% of CRC's outstanding common stock to Occidental stockholders of record as of the close of business on                    , 2014, the spin-off record date. Each Occidental stockholder will receive            shares of CRC common stock for each share of Occidental common stock held by such stockholder on the record date. The distribution of these shares will be made in book-entry form, which means that no physical share certificates will be issued. Following the spin-off, stockholders may request that their shares of CRC common stock be transferred to a brokerage or other account at any time. No fractional shares of CRC common stock will be issued. If you would otherwise have been entitled to a fractional common share in the distribution, you will receive the net cash proceeds of the sale of such fractional share instead.

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

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

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

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

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

Yours sincerely,

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


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                    , 2014
Dear California Resources Corporation Stockholder:

        It is our pleasure to welcome you as a stockholder of our company, California Resources Corporation. We are an independent oil and natural gas exploration and production company focused on high-growth, high-return conventional and unconventional assets exclusively in California. We are the largest producer in California on a gross-operated basis and believe we have established the largest privately-held mineral acreage position in the state.

        As an independent, publicly-traded company, we believe we can more effectively focus on our objectives and satisfy the capital needs of our company, and thus bring more value to you as a stockholder.

        Our common stock is expected to be listed on the New York Stock Exchange under the ticker symbol "CRC" in connection with the distribution of our common stock by Occidental Petroleum Corporation.

        We invite you to learn more about California Resources Corporation by reviewing the enclosed information statement. We look forward to our future as an independent, publicly-traded company and to your support as a holder of our common stock.

Very truly yours,

Todd A. Stevens
President and Chief Executive Officer
California Resources Corporation

"Energy for California by Californians"


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

PRELIMINARY INFORMATION STATEMENT
(Subject to Completion, Dated August 20, 2014)

INFORMATION STATEMENT

California Resources Corporation

Common Stock

(par value $0.01 per share)

        This information statement is being sent to you in connection with the separation of California Resources Corporation ("CRC") from Occidental Petroleum Corporation ("Occidental"), following which CRC will be an independent, publicly traded company. As part of the separation, Occidental will distribute at least 80.1% of the outstanding shares of CRC common stock on a pro rata basis to the holders of Occidental's common stock. We refer to this pro rata distribution as the "distribution" and we refer to the separation, including the restructuring transactions (which will precede the separation) and the distribution, as the "spin-off." We expect that the spin-off will be tax-free to Occidental stockholders for U.S. federal income tax purposes, except to the extent of cash received in lieu of fractional shares. Each Occidental stockholder will receive                        shares of CRC common stock for each share of Occidental common stock held by such stockholder as of the close of business on                        , 2014, the record date for the distribution. The distribution of shares will be made in book-entry form. Occidental will not distribute any fractional shares of CRC common stock. Instead, the distribution agent will aggregate fractional shares into whole shares, sell the whole shares in the open market at prevailing market prices and distribute the aggregate net cash proceeds from the sales pro rata to each holder who would otherwise have been entitled to receive a fractional share in the spin-off. See "The Spin-Off—Treatment of Fractional Shares." As discussed under "The Spin-Off—Trading Prior to the Distribution Date," if you sell your Occidental common stock in the "regular-way" market after the record date and before the distribution date, you also will be selling your right to receive shares of CRC common stock in connection with the spin-off. If you sell your Occidental common stock in the "ex-distribution" market after the record date and before the distribution date, you will still receive shares of our common stock in the spin-off. The distribution will be effective as of 11:59 p.m., Eastern Time, on                        , 2014. Immediately after the distribution becomes effective, CRC will be an independent, publicly traded company.

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

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

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

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

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

The date of this information statement is                        , 2014.

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


Table of Contents


TABLE OF CONTENTS

 
  Page  

SUMMARY

    1  

RISK FACTORS

    28  

FORWARD-LOOKING STATEMENTS

    44  

THE SPIN-OFF

    46  

TRADING MARKET

    57  

DIVIDEND POLICY

    59  

CAPITALIZATION

    59  

SELECTED HISTORICAL COMBINED FINANCIAL DATA

    60  

UNAUDITED PRO FORMA COMBINED FINANCIAL DATA

    61  

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

    67  

BUSINESS

    82  

MANAGEMENT

    121  

EXECUTIVE COMPENSATION

    125  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    156  

ARRANGEMENTS BETWEEN OCCIDENTAL AND OUR COMPANY

    157  

OTHER RELATED PARTY TRANSACTIONS

    163  

DESCRIPTION OF MATERIAL INDEBTEDNESS

    164  

DESCRIPTION OF CAPITAL STOCK

    165  

WHERE YOU CAN FIND MORE INFORMATION

    170  

GLOSSARY OF TECHNICAL TERMS

    171  

INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION

    F-1  

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

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SUMMARY

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

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

Overview

        California Resources Corporation will, following its spin-off from Occidental, be an independent oil and natural gas exploration and production company focused on high-growth, high-return conventional and unconventional assets exclusively in California. California is one of the most prolific oil and natural gas producing regions in the world and is the third largest oil producing state in the nation. It has five of the 12 largest fields in the lower 48 states based on estimated proved reserves as of 2009, and our portfolio includes interests in four of these fields. We are the largest producer in California on a gross operated basis and we believe we have established the largest privately-held mineral acreage position in the state, consisting of approximately 2.3 million net acres spanning the state's four major oil and gas basins. We have developed a sizable inventory of over 17,500 identified drilling locations and, as an independent company, we intend to exploit our significant portfolio of conventional and unconventional opportunities to generate double-digit production growth over the longer-term. We produced approximately 154,000 Boe/d net in 2013 and, as of December 31, 2013, we had proved reserves of 744 MMBoe, with approximately 69% proved developed and 72% proved oil reserves and an aggregate PV-10 value of $14.0 billion. For an explanation of the non-GAAP financial measure PV-10 and a reconciliation of PV-10 to Standardized Measure, the most directly comparable GAAP financial measure, see "—Summary Combined Historical Operating and Reserve Data—Non-GAAP Financial Measure and Reconciliations."

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

 

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        We believe that over the last several decades the oil and gas industry has focused significantly less effort on utilizing modern development and exploration processes and technologies in California relative to other prolific U.S. basins. We believe this is largely due to other oil companies' limited capital spending in California, focus on shallow zone thermal projects or investments in other assets within their global portfolios. As an independent company focused exclusively on California, we expect to drive strong production growth through increased application of modern technologies and increased capital spending on development of the significant potential in our portfolio.

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

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

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

 
   
   
   
   
   
   
   
  2014
Projected
Gross
Development
Wells
Drilled(2)
  2014
Projected
Development
Drilling
Capital
($MM)(3)
 
 
  Acreage
(in millions)
   
   
   
  Identified
Drilling
Locations(1)
 
 
  Gross
Acreage
Held in
Fee (%)
   
  Average
Working
Interest
(%)
 
 
  Producing
Wells,
gross
 
 
  Gross   Net   Gross   Net  

San Joaquin basin(4)

    1.8     1.5     59 %   5,764     90 %   12,836     11,127     969   $ 942  

Los Angeles basin(5)

    <0.1     <0.1     73 %   1,382     95 %   1,537     1,478     201     384  

Ventura basin

    0.3     0.3     77 %   780     98 %   2,310     1,716     32     56  

Sacramento basin

    0.6     0.5     36 %   729     100 %   1,008     864     3     8  
                                       

Total

    2.7     2.3     56 %   8,655     92 %   17,691     15,185     1,205   $ 1,390  
                                       
                                       

(1)
Our total identified drilling locations include 2,141 gross (2,024 net) locations associated with proved undeveloped reserves as of December 31, 2013 and 2,344 gross (2,251 net) injector well locations associated with our waterflood and steamflood projects. Our total identified drilling locations excludes 6,400 gross (5,300 net) prospective resource drilling locations. Please see "Business—Our Reserves and Production Information—Determination of Identified Drilling Locations" for more information regarding the processes and criteria through which we identified our drilling locations. Of our total identified drilling locations, we believe approximately 75% are attributable to acreage owned or held by production.

(2)
Includes 207 injection wells expected to be drilled in connection with our waterflood and steamflood projects.

 

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(3)
Includes drilling and completion expenditures of $173 million associated with injection wells. Our 2014 capital budget of $2.1 billion also includes spending on support equipment, facilities, workovers and exploration.

(4)
Excluding Elk Hills, our average working interest in the San Joaquin basin is 97%.

(5)
We currently hold approximately 27,173 gross (20,817 net) acres in the Los Angeles basin. Our Los Angeles basin operations are concentrated with pad drilling.

        We currently have 26 drilling rigs employed in California with 17 drilling in the San Joaquin basin, 8 in the Los Angeles basin, and 1 rig in the Ventura basin. During the first half of the year, we drilled over 700 gross development wells with roughly 583 in San Joaquin basin, 114 in the Los Angeles basin, 11 in Ventura basin and 3 in Sacramento basin. We expect our pace of drilling to improve slightly in the second half of the year as we receive additional permits and will add an additional rig in the San Joaquin basin during the 3 rd  quarter.

        In 2013, oil represented 58% of our net production. We expect the percentage of oil production to continue to increase over time and favorably impact our overall margins as we anticipate directing virtually all of our capital expenditures towards oil-weighted opportunities in 2014 and beyond to the extent the current oil to gas price relationship continues. Approximately 42% of our 2013 production was generated from our growth-oriented fields through a combination of unconventional and conventional primary, waterflood and steamflood projects with attractive returns. The remaining 58% was generated by our world-class Elk Hills and Wilmington fields, each of which is ranked in the top 20 onshore fields in the lower 48 states based on 2009 proved reserves. Over the last three years, we grew our total production 6% on a compound annual basis, from 138 MBoe/d in 2011 to 154 MBoe/d in 2013, while the proportionate share of liquids production grew from 69% to 71%. We intend to accelerate our production growth by significantly increasing our capital investments and focusing on higher-growth opportunities in our extensive drilling inventory. Our 2014 capital budget of $2.1 billion represents an increase of approximately 26% over the $1.7 billion we spent in 2013. After the spin-off, we intend to reinvest substantially all of our operating cash flow in our capital program for the foreseeable future as we will no longer be required to distribute cash to Occidental. We expect to increase our production by 6-9% on a compound annual basis in 2015 and 2016 with a 15% compound annual increase in our oil production for the same period. Over 90% of our expected production for this period is from currently producing fields where we have existing or permitted capacity in our production facilities.

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

        The table below summarizes our proved reserves as of December 31, 2013 and production for the six months ended June 30, 2014 in each of California's four major oil and gas basins.

 
   
   
   
   
   
   
  Average Net Daily
Production for the
six months
ended June 30,
2014
   
 
 
  Proved Reserves as of December 31, 2013    
 
 
  Oil
(MMBbl)
  NGLs
(MMBbl)
  Natural
Gas
(Bcf)
  Total
(MMBoe)
  Oil
(%)
  Proved
Developed
(%)
  R/P Ratio
(Years)(1)
 
 
  (MBoe/d)   Oil (%)  

San Joaquin basin

    331     68     669     511     65 %   68 %   109     57 %   12.9  

Los Angeles basin

    156         17     159     98 %   70 %   28     100 %   15.5  

Ventura basin

    45     4     35     55     82 %   64 %   9     67 %   16.4  

Sacramento basin

            117     19     %   100 %   9     %   6.4  
                                       

Total operations

    532     72     838     744     72 %   69 %   155     62 %   13.2  
                                       
                                       

(1)
Calculated as total proved reserves as of December 31, 2013 divided by annualized Average Net Daily Production for the six months ended June 30, 2014.

 

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Portfolio Management and 2014 Capital Budget

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

        We have a 2014 capital expenditure budget of $2.1 billion for projects targeting investments in the San Joaquin, Los Angeles and Ventura basins, as compared to $1.7 billion in 2013. Virtually all of our 2014 capital budget is being directed towards oil-weighted production consistent with 2013. Of the total 2014 capital budget, approximately $1.4 billion is allocated to well drilling and completions, $200 million to workovers, $180 million to surface support equipment to handle higher production, $100 million to additional steam generation capacity expansion, $95 million to exploration and the rest to maintenance capital, HES projects and other items. As a result of recent investments in infrastructure, we do not anticipate any substantial spending on new infrastructure during the next several years. We believe the absence of such significant expenditures should support strong cash flows. The table below sets forth the expected allocation of our 2014 capital expenditure budget as compared to the allocation of our 2013 capital expenditures and actual 2014 capital expenditures through June 30, 2014.

 
  2014 Capital
Expenditures
through
June 30, 2014
  Total
2014 Capital
Expenditure
Budget
  2013 Capital
Expenditures
 
 
  (in millions)
 

Conventional:

                   

Primary recovery

  $ 157   $ 342   $ 266  

Waterfloods

    298     787     480  

Steamfloods

    219     343     375  
               

Total conventional

    674     1,472     1,121  
               

Unconventional

    272     543     457  

Exploration

    57     95     91  
               

Total

  $ 1,003   $ 2,110   $ 1,669  
               
               

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

Our Business Strategy

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

 

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Our Competitive Strengths

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

 

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Other Information

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

 

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information statement is a part, and you should not consider information on our website as part of this information statement or such registration statement on Form 10.

The Spin-Off

        On February 14, 2014, Occidental announced that its board of directors had authorized management to pursue the spin-off of the California business into a standalone, publicly traded company. Immediately following the distribution, Occidental stockholders as of the record date will own at least 80.1% of the outstanding shares of our common stock.

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

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

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

Questions and Answers About the Spin-Off

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

 

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Q:
What is the spin-off?

A:
In this information statement, when we refer to the "spin-off," we are referring to the separation of Occidental's California business from the remaining business of Occidental through a series of transactions, including the restructuring transactions, that will result in the California business being owned by us, and Occidental's pro rata distribution of at least 80.1% of our outstanding shares to its stockholders. Following the spin-off, we will be a separate and independent company from Occidental. The number of shares of Occidental common stock you own will not change as a result of the spin-off. Your proportionate direct interest in CRC, however, will be lower than your proportionate direct interest in Occidental, due to the fact that Occidental will continue to hold up to 19.9% of our outstanding shares (the "Retained Securities") for up to 18 months following the spin-off.

Q:
What will I receive in the spin-off?

A:
As a holder of Occidental stock, you will retain your Occidental shares and will receive            shares of our common stock for each share of Occidental common stock you hold as of the record date. Your proportionate interest in Occidental will not change as a result of the spin-off.

Q:
What is CRC?

A:
CRC is currently a wholly-owned subsidiary of Occidental whose shares will be distributed to Occidental stockholders if the spin-off is completed. After the spin-off is completed, CRC will be an independent publicly traded company and will own and operate the California business.

Q:
When is the record date for the distribution, and when will the distribution occur?

A:
The record date for determining Occidental stockholders entitled to receive our shares in the distribution will be the close of business of the New York Stock Exchange (the "NYSE") on                , 2014. The distribution will occur on                , 2014.

Q:
What are the reasons for and benefits of separating us from Occidental?

A:
Our separation from Occidental and the distribution of our common stock will provide you with equity investments in two separate companies that are intended to be more focused and competitive industry leaders. The spin-off will enable each company to pursue strategies tailored to the respective needs of their businesses. For a more detailed discussion of the reasons for and benefits of the spin-off, see "The Spin-Off—Reasons for the Spin-Off."

Q:
What are the risks associated with the spin-off?

A:
There are a number of risks associated with the spin-off and resultant ownership of our common stock. These risks are discussed under "Risk Factors" beginning on page 28.

Q:
Why is the separation of CRC structured as a spin-off as opposed to a sale?

A:
Occidental believes that a tax-free distribution of our common stock is an efficient way to separate us from Occidental in a manner that will improve flexibility, benefit both Occidental and CRC and create long-term value for stockholders of both Occidental and CRC.

Q:
What is being distributed in the spin-off?

A:
Approximately            shares of our common stock will be distributed in the spin-off, based on the number of shares of Occidental common stock expected to be outstanding as of the record date of                        , 2014. The actual number of shares of our common stock to be distributed will be calculated on            , 2014, the record date. The shares of our common stock to be distributed by Occidental will constitute at least 80.1% of the issued and outstanding shares of our common stock

 

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Q:
What will the relationship be between Occidental and CRC after the spin-off?

A:
Following the spin-off, CRC will be an independent, publicly traded company and Occidental will hold the Retained Securities for a maximum of 18 months. In connection with the spin-off, we will enter into a Separation and Distribution Agreement and several other agreements with Occidental for the purpose of allocating between us and Occidental various assets, liabilities and obligations relating to the California business. These agreements will also provide arrangements for employee matters, tax matters and some other liabilities and obligations attributable to periods before and, in some cases, after the spin-off. These agreements will also include arrangements with respect to transition services. We will also have an Area of Mutual Interest Agreement with Occidental that provides Occidental the right to acquire        % of certain oil and gas properties we acquire in the United States outside of the state of California. Occidental will determine the principal terms of these agreements and the allocation between us and Occidental of Occidental's assets, liabilities and obligations, with the assets, liabilities and obligations relating to the California business generally allocated to us.

Q:
What will Occidental do with the Retained Securities?

A:
Occidental expects to dispose of all of the Retained Securities by making one or more offers to exchange such Retained Securities for outstanding shares of Occidental common stock. For each share of Occidental common stock tendered for exchange, the holder of such Occidental common stock will receive a number of shares of CRC common stock based on an exchange ratio to be determined by Occidental. Any Retained Securities Occidental does not dispose of through such exchanges will be distributed pro rata to Occidental shareholders no later than 18 months after the spin-off.

Q:
How will equity-based and other long-term incentive compensation awards held by Occidental employees be affected as a result of the spin-off?

A:
We currently anticipate that equity-based and long-term incentive compensation awards from Occidental held by employees who will be employed by us and our subsidiaries following the spin-off will be converted into awards under our equity and long-term incentive compensation programs and that such awards held by others who do not transfer will remain outstanding pursuant to the applicable plans maintained by Occidental, with corresponding adjustments made to the number of shares of Occidental common stock subject to such awards and the reference price of such awards. For additional information regarding the expected treatment of equity-based and long-term incentive compensation awards, see "Treatment of Long-Term Incentive Awards for Current and Former Employees."

Q:
What do I have to do to participate in the spin-off?

A:
You are not required to take any action, although you are urged to read this entire document carefully. No stockholder approval of the spin-off is required and none is being sought. You are not being asked for a proxy. No action is required on your part to receive your shares of our common stock. You will neither be required to pay anything for the new shares nor to surrender any shares of Occidental common stock to participate in the spin-off.

Q:
How will fractional shares be treated in the spin-off?

A:
Fractional shares of our common stock will not be distributed. Fractional shares of our common stock to which Occidental stockholders of record would otherwise be entitled will be aggregated and sold in the public market by the distribution agent. The aggregate net cash proceeds of the sales will be

 

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Q:
What are the U.S. federal income tax consequences of the spin-off?

A:
The spin-off is conditioned on the receipt by Occidental of a private letter ruling from the Internal Revenue Service (the "IRS") substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates. The distribution is further conditioned on Occidental's tax counsel issuing an opinion in form and substance acceptable to Occidental, which may rely on the effectiveness of the private letter ruling with respect to certain issues, that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off qualifies generally as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (the "Code"). See "The Spin-Off—Conditions to the Spin-Off." Assuming that the spin-off will qualify as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code, for U.S. federal income tax purposes, except for gain realized on the receipt of cash paid in lieu of fractional shares, no gain or loss will generally be recognized by an Occidental shareholder, and no amount generally will be included in such Occidental shareholder's taxable income, as a result of the spin-off. You should, however, consult your own tax advisor as to the particular consequences to you. The U.S. federal income tax consequences of the distribution are described in more detail under "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off."

Q:
Will our common stock be listed on a stock exchange?

A:
Yes. Although there is currently no public market for our common stock, we intend to apply to list our common stock on the NYSE under the symbol "CRC."

It is anticipated that trading of our common stock will commence on a "when-issued" basis on or shortly before the record date. When-issued trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. When-issued trades generally settle within four trading days after the distribution date. On the first trading day following the distribution date, any when-issued trading with respect to our common stock will end and "regular-way" trading will begin. "Regular-way" trading refers to trading after a security has been issued and typically involves a transaction that settles on the third full trading day following the date of the transaction. See "Trading Market."

Q:
Will my shares of Occidental common stock continue to trade?

A:
Yes. Occidental common stock will continue to be listed and traded on the NYSE under the symbol "OXY."

Q:
If I sell, on or before the distribution date, shares of Occidental common stock that I held on the record date, am I still entitled to receive shares of CRC common stock distributable with respect to the shares of Occidental common stock I sold?

A:
Beginning on or shortly before the record date and continuing through the distribution date for the spin-off, Occidental's common stock will begin to trade in two markets on the NYSE: a "regular-way" market and an "ex-distribution" market. If you are a holder of record of shares of Occidental common stock as of the record date for the distribution and choose to sell those shares in the regular-way

 

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Q:
Will the spin-off affect the trading price of my Occidental stock?

A:
Yes, the trading price of shares of Occidental common stock immediately following the distribution is expected to be lower than immediately prior to the distribution because of the dividend to Occidental common stockholders in the form of our common stock and the fact that the Occidental common stock trading price will no longer reflect the value of the California business, partially offset by the value of the cash we will distribute to Occidental. We cannot provide you with any assurance as to the price at which shares of Occidental common stock will trade following the spin-off.

Q:
What indebtedness will CRC have following the spin-off?

A:
We intend to enter into new financing arrangements in anticipation of the spin-off. We expect to incur up to $6.065 billion in new debt, which may include long-term notes, term loans or borrowings under a revolving credit facility or a combination thereof. At separation, we intend to make a cash distribution of approximately $6.0 billion to Occidental. The amount of the cash distribution to be paid by us to Occidental will be determined by Occidental after consideration of several factors, including our resulting capital structure and anticipated credit ratings. Our capital structure will be designed to provide us with the financial flexibility to maintain our current level of operations and the ability to invest substantially all of our future cash flow in growing our California oil and gas operations. We expect that our revolving credit facility will be available for our immediate working capital needs and for general corporate purposes including issuance of letters of credit. See "Description of Material Indebtedness" included elsewhere in this information statement.

Following the spin-off, our debt obligations could restrict our business and may adversely impact our financial condition, results of operations or cash flows. In addition, our separation from Occidental's other businesses may increase the overall cost of debt funding and decrease the overall debt capacity and commercial credit available to us. Our business, financial condition, results of operations and cash flows could be harmed by a deterioration of our credit profile or by factors adversely affecting the credit markets generally. See "Risk Factors—Risks Related to the Spin-Off—We will have significant indebtedness and may incur more debt. Higher levels of indebtedness could make us more vulnerable to economic downturns and adverse developments in our business."

Q:
What will our dividend and share repurchase policy be after the spin-off?

A:
We intend to pay a cash dividend of $0.01 per share per quarter, or $0.04 per share per year. We do not anticipate increasing the dividend on our common stock in the foreseeable future as we currently intend to retain the remainder of our future earnings to support the growth and development of our business. In addition, we will be authorized to implement a share repurchase program if circumstances warrant. The payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our capital investment program, financial condition, results of operations, capital requirements and development expenditures, future business prospects and any restrictions imposed by future debt instruments. For more information, see "Dividend Policy."

 

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Q:
If I was enrolled in an Occidental dividend reinvestment plan, will I automatically be enrolled in the CRC dividend reinvestment plan?

A:
Yes. If you elected to have your Occidental cash dividends applied toward the purchase of additional Occidental shares, the CRC shares you receive in the distribution will be automatically enrolled in the                        sponsored by American Stock Transfer & Trust Company, LLC ("AST") (CRC's transfer agent and registrar), unless you notify AST that you do not want to reinvest any CRC cash dividends in additional CRC shares. Contact information for AST is provided on page 169 of this Information Statement.

Q:
What are the anti-takeover effects of the spin-off?

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

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

Q:
Where can I get more information?

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

American Stock Transfer & Trust Company, LLC
6201 15 th Avenue
Brooklyn, NY 11219
Phone: (800) 937-5449

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

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

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

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

 

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Summary of the Spin-Off

Distributing Company

  Occidental Petroleum Corporation, a Delaware corporation. After the distribution, Occidental will hold the Retained Securities for up to 18 months.

Distributed Company

 

California Resources Corporation, a Delaware corporation and a wholly-owned subsidiary of Occidental. After the spin-off, we will be an independent, publicly owned company.

Distributed Securities

 

Occidental will distribute at least 80.1% of the outstanding shares of CRC common stock. Based on approximately            shares of Occidental common stock outstanding as of                        , 2014 and assuming distribution of 80.1% of our common stock and applying the distribution ratio, approximately            shares of our common stock will be distributed.

Retained Securities

 

Occidental expects to dispose of all of the Retained Securities by making one or more offers to exchange such Retained Securities for outstanding shares of Occidental common stock. For each share of Occidental common stock tendered for exchange, the holder of such Occidental common stock will receive a number of shares of CRC common stock based on an exchange ratio to be determined by Occidental. Any Retained Securities Occidental does not dispose of through such exchanges will be distributed pro rata to Occidental shareholders no later than 18 months after the spin-off.

Record Date

 

The record date for the distribution is the close of business of the NYSE on                        , 2014.

Distribution Date

 

The distribution date is                        , 2014.

Restructuring Transactions

 

As part of the spin-off, Occidental will generally contribute and transfer to us the assets, liabilities and obligations related to the California business and we will amend and restate our certificate of incorporation and bylaws.

Distribution Ratio

 

Each Occidental stockholder will receive            shares of our common stock for each share of Occidental common stock held by such stockholder on the record date.

Distribution Method

 

Our common stock will be issued only by direct registration in book-entry form. Registration in book-entry form is a method of recording stock ownership when no physical paper certificates are issued to stockholders, as is the case in this distribution.

 

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Fractional Shares

 

The distribution agent will not distribute any fractional shares of our common stock to Occidental stockholders. Fractional shares of our common stock to which Occidental stockholders of record would otherwise be entitled will be aggregated and sold in the public market by the distribution agent. The aggregate net cash proceeds of the sales will be distributed ratably to those stockholders who would otherwise have received fractional shares of our common stock. Proceeds from these sales will generally result in a taxable gain or loss to those stockholders. Each stockholder entitled to receive cash proceeds from these shares should consult his, her or its own tax advisor as to the stockholder's particular circumstances. The tax consequences of the distribution are described in more detail under "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off."

Conditions to the Spin-Off

 

The spin-off is subject to the satisfaction or waiver by Occidental, in its sole discretion, of the following conditions, as well as other conditions described in this information statement in "The Spin-Off—Conditions to the Spin-Off":

 

the Securities and Exchange Commission ("SEC") shall have declared effective our registration statement on Form 10, of which this information statement is a part, under the Exchange Act of 1934, as amended (the "Exchange Act"); no stop order suspending the effectiveness of the registration statement shall be in effect; and no proceedings for such purpose shall be pending before or threatened by the SEC;

 

any required actions and filings with regard to state securities and blue sky laws of the U.S. (and any comparable laws under any foreign jurisdictions) shall have been taken and, where applicable, have become effective or been accepted;

 

our common stock shall have been authorized for listing on the NYSE, or another national securities exchange approved by Occidental, subject to official notice of issuance;

 

Occidental shall have received a private letter ruling from the IRS to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates, and such private letter ruling shall not have been revoked or modified in any material respect;

 

Occidental shall have received an opinion of its tax counsel, in form and substance acceptable to Occidental and which shall remain in full force and effect, that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off generally qualifies as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code;

 

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no order, injunction, decree or regulation issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the distribution will be in effect;

 

the completion of our new financing arrangements;

 

no other events or developments shall have occurred or exist that, in the judgment of the board of directors of Occidental, in its sole discretion, makes it inadvisable to effect the distribution or other transactions contemplated by the Separation and Distribution Agreement;

 

each of the ancillary agreements contemplated by the Separation and Distribution Agreement shall have been executed by each party thereto; and

 

any government approvals and other material consents necessary to consummate the distribution will have been obtained and remain in full force and effect.

 

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

Trading Market and Symbol

 

We intend to apply to list our common stock on the NYSE under the ticker symbol "CRC." We anticipate that, on or shortly before the record date, trading of shares of our common stock will begin on a "when-issued" basis and will continue up to and including the distribution date, and we expect "regular-way" trading of our common stock will begin the first trading day after the distribution date. We also anticipate that, on or shortly before the record date, there will be two markets in Occidental common stock: a "regular-way" market on which shares of Occidental common stock will trade with an entitlement to shares of our common stock to be distributed pursuant to the distribution, and an "ex-distribution" market on which shares of Occidental common stock will trade without an entitlement to shares of our common stock. For more information, see "Trading Market."

 

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Tax Consequences

 

The distribution is conditioned on the receipt by Occidental of a private letter ruling from the IRS substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates. The distribution is further conditioned on Occidental's tax counsel issuing an opinion in form and substance acceptable to Occidental, which may rely on the effectiveness of the private letter ruling with respect to certain issues, that for U.S. federal income tax purposes, (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off generally qualifies as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code.

 

Assuming that the spin-off will qualify as a tax-free transaction for U.S. federal income tax purposes, except for gain realized on the receipt of cash paid in lieu of fractional shares, no gain or loss will generally be recognized by an Occidental stockholder, and no amount generally will be included in such Occidental stockholder's taxable income, as a result of the spin-off.

 

For a more detailed description of the U.S. federal income tax consequences of the spin-off, see "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off."

 

Each stockholder is urged to consult his, her or its tax advisor as to the specific tax consequences of the spin-off to such stockholder, including the effect of any state, local or non-U.S. tax laws and of changes in applicable tax laws.

 

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Relationship with Occidental after the Spin-Off

 

We will enter into a Separation and Distribution Agreement and other ancillary agreements with Occidental related to the spin-off. These agreements will provide for the allocation between us and Occidental of Occidental's assets, liabilities and obligations, and we will generally be allocated those assets, liabilities and obligations relating to the California business. These agreements will also govern certain interactions between us and Occidental after the separation (including with respect to employee matters, tax matters and intellectual property matters). We and Occidental will also enter into a Transition Services Agreement that will provide for, among other matters, assistance to us or Occidental as needed. We also intend to enter into an Employee Matters Agreement that will set forth the agreements between Occidental and us concerning certain employee compensation and benefit matters. Further, we intend to enter into a Tax Sharing Agreement with Occidental regarding the respective rights, responsibilities, and obligations of Occidental and us with respect to the payment of taxes, filing of tax returns, reimbursements of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes. We will also enter into an Area of Mutual Interest Agreement with Occidental, which will provide Occidental with the right to acquire an interest in and rights with respect to certain oil and gas properties in the United States (excluding the state of California). Occidental will determine the principal terms of these agreements. We describe these and other arrangements in greater detail under "Arrangements Between Occidental and Our Company," and describe some of the risks of these arrangements under "Risk Factors—Risks Related to the Spin-Off."

Indemnities

 

We will indemnify Occidental under the Tax Sharing Agreement for taxes incurred as a result of the failure of the spin-off 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, to the extent caused by our breach of any representations or covenants made in the Tax Sharing Agreement or made in connection with the private letter ruling or the tax opinion or by certain other actions taken by us. 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. See "Arrangements Between Occidental and Our Company—Tax Sharing Agreement." In addition, under the Separation and Distribution Agreement, we and Occidental will indemnify each other and certain of our respective subsidiaries against claims and liabilities relating to the past operation of our business. See "Arrangements Between Occidental and Our Company."

 

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Dividend Policy

 

We intend to pay a cash dividend of $0.01 per share per quarter, or $0.04 per share per year. We do not anticipate increasing the dividend on our common stock in the foreseeable future as we currently intend to retain the remainder of our future earnings to support the growth and development of our business. In addition, we will be authorized to implement a share repurchase program if circumstances warrant. See "Dividend Policy."

Transfer Agent

 

American Stock Transfer & Trust Company, LLC will be the transfer agent and registrar for the shares of our common stock.

Summary Risk Factors

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

Risks Related to our Business

 

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Risks Related to the Spin-Off

 

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Risks Related to our Common Stock

 

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SUMMARY COMBINED HISTORICAL AND PRO FORMA FINANCIAL DATA

        Set forth below is a summary of our combined historical and pro forma financial data for the periods indicated. The historical unaudited combined financial data for the six months ended June 30, 2014 and 2013 and the balance sheet data as of June 30, 2014 have been derived from our unaudited condensed combined financial statements included elsewhere in this information statement. The unaudited condensed combined financial statements have been prepared on the same basis as our audited combined financial statements, except as stated in the related notes thereto, and include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial condition and results of operations for such periods. The results of operations for the six months ended June 30, 2014 presented below are not necessarily indicative of results for the entire fiscal year. The historical financial data for the years ended December 31, 2013, 2012 and 2011 and the balance sheet data as of December 31, 2013 and 2012 have been derived from our audited combined financial statements included elsewhere in this information statement.

        The unaudited pro forma financial data have been derived from our historical combined financial statements included in this information statement. While the historical combined financial statements reflect the past financial results of the California business, these pro forma statements give effect to the separation of those operations into a stand-alone, publicly traded company in the spin-off. The pro forma adjustments are based on available information and assumptions that we believe are reasonable; however, such adjustments are subject to change based on the finalization of the terms of the spin-off and the related separation and distribution agreements, as well as our expected debt offering. We have attempted to include recurring costs of operating as a stand-alone company, although only the additional costs we have determined to be factually supportable are included as pro forma adjustments, and there could be incremental costs not reflected in the unaudited pro forma combined financial statements. However, we expect the costs of operating as a stand-alone public company, other than the debt-related costs, will be generally comparable to the costs reported in the historical combined financial statements. Additionally, such adjustments are estimates and may not prove to be accurate. The adjustments include certain costs associated with the spin-off related to certain management actions which are either in the balance sheet or income statement, as appropriate. Subject to the terms of the Separation and Distribution Agreement, nonrecurring third-party costs and expenses related to the separation, other than the debt-related costs, and incurred prior to the separation date will generally be paid by Occidental. We expect such nonrecurring amounts to include costs to separate and/or duplicate information technology systems, outside legal and accounting fees, and similar costs. The pro forma adjustments, including related tax effects, to reflect the spin-off include the following:

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

        You should read the following summary financial data in conjunction with "Selected Historical Combined Financial Data," "Unaudited Pro Forma Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our audited combined financial

 

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statements, unaudited interim combined condensed financial statements and the notes to those statements included in this information statement.

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

 
   
   
   
   
   
  Pro Forma  
 
  Six Months
Ended
June 30,
   
   
   
 
 
  Year Ended December 31,   Six Months
Ended
June 30,
2014
   
 
 
  Year Ended
December 31,
2013
 
 
  2014   2013   2013   2012   2011  
 
  (in millions)
 

Statement of Income Data:

                                           

Net sales, including to related parties

  $ 2,262   $ 2,098   $ 4,285   $ 4,072   $ 3,938   $ 2,262   $ 4,285  

Income before income taxes

  $ 782   $ 703   $ 1,447   $ 1,181   $ 1,641   $ 636   $ 1,155  

Net income

  $ 469   $ 422   $ 869   $ 699   $ 971   $ 381   $ 693  

Other Financial Data:

                                           

EBITDAX(1)

  $ 1,410   $ 1,308   $ 2,707   $ 2,255   $ 2,430   $ 1,410   $ 2,707  

(1)
For more information, please read "—Non-GAAP Financial Measures and Reconciliations" below.

 
   
   
   
  Pro Forma  
 
   
  December 31,  
 
  June 30,
2014
  June 30,
2014
 
 
  2013   2012  
 
  (in millions)
 

Balance Sheet Data:

                         

Property, plant and equipment, net

  $ 14,434   $ 14,008   $ 13,499   $ 14,434  

Net investment

  $ 10,274   $ 9,989   $ 9,860   $ 4,657  

 

 
  Six Months
Ended
June 30,
  Year Ended December 31,  
 
  2014   2013   2013   2012   2011  
 
  (in millions)
 

Statement of Cash Flows Data:

                               

Net cash provided by operating activities

  $ 1,234   $ 1,177   $ 2,476   $ 2,223   $ 2,456  

Net cash used by investing activities

  $ (1,038 ) $ (768 ) $ (1,713 ) $ (2,755 ) $ (3,565 )

Net cash (used) provided by financing activities

  $ (196 ) $ (409 ) $ (763 ) $ 532   $ 1,106  

Capital expenditures

  $ (1,003 ) $ (737 ) $ (1,669 ) $ (2,331 ) $ (2,164 )

Payments for purchases of assets and businesses, and other

  $ (35 ) $ (31 ) $ (48 ) $ (427 ) $ (1,405 )

 

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SUMMARY COMBINED HISTORICAL OPERATING AND RESERVE DATA

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

 
  At December 31,  
 
  2013   2012  

Estimated Proved Reserves and Other Information:

             

Oil (MMBbl)

    532     497  

NGLs (MMBbl)

    72     62  

Natural Gas (Bcf)

    838     928  

Total (MMBoe)

    744     714  

PV-10 (in millions)(1)

  $ 14,018   $ 13,773  

Standardized Measure of Discounted Future Net Cash Flows (in millions)(1)

  $ 9,223   $ 9,073  

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

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

 
  Six Months Ended
June 30,
  Year Ended December 31,  
 
  2014   2013   2013   2012   2011  

Production Data:

                               

Oil (MBbl/d)

    96     88     90     88     80  

NGLs (MBbl/d)

    18     20     20     17     15  

Natural gas (MMcf/d)

    243     262     260     256     260  

Average daily combined production (MBoe/d)(1)

    155     152     154     148     138  

Total combined production (MMBoe)(1)

    28     28     56     54     50  

Average realized prices:

   
 
   
 
   
 
   
 
   
 
 

Oil (per Bbl)

  $ 103.43   $ 105.21   $ 104.16   $ 104.02   $ 103.80  

NGLs (per Bbl)

  $ 54.86   $ 47.90   $ 50.43   $ 52.76   $ 70.03  

Natural gas (per Mcf)

  $ 4.67   $ 3.82   $ 3.73   $ 2.94   $ 4.31  

Average costs per Boe:

   
 
   
 
   
 
   
 
   
 
 

Production costs

  $ 20.59   $ 19.12   $ 18.99   $ 24.34   $ 21.30  

Other operating expenses

  $ 4.80   $ 4.15   $ 4.38   $ 4.04   $ 3.89  

Depreciation, depletion and amortization

  $ 20.73   $ 20.47   $ 20.38   $ 17.15   $ 13.38  

Taxes other than on income

  $ 3.80   $ 3.97   $ 3.29   $ 3.09   $ 2.84  

(1)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per Bbl and $3.66 per Mcf, respectively, resulting in an oil-to-gas ratio of over 25 to 1.

 

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Non-GAAP Financial Measures and Reconciliations

EBITDAX

        We define EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; and exploration expense. 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 provided in addition to, and not as an alternative for income and liquidity measures calculated in accordance with GAAP, and 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:

 
   
   
   
   
   
  Pro Forma  
 
  Six Months
Ended
June 30,
   
   
   
 
 
  Year Ended December 31,   Six Months
Ended
June 30,
2014
   
 
 
  Year Ended
December 31,
2013
 
 
  2014   2013   2013   2012   2011  
 
  (in millions)
 

Net income

  $ 469   $ 422   $ 869   $ 699   $ 971   $ 381   $ 693  

Interest expense

  $   $   $   $   $   $ 146   $ 292  

Provision for income taxes

  $ 313   $ 281   $ 578   $ 482   $ 670   $ 255   $ 462  

Depreciation, depletion and amortization

  $ 582   $ 565   $ 1,144   $ 926   $ 675   $ 582   $ 1,144  

Exploration expense

  $ 46   $ 40   $ 116   $ 148   $ 114   $ 46   $ 116  
                               

EBITDAX

  $ 1,410   $ 1,308   $ 2,707   $ 2,255   $ 2,430   $ 1,410   $ 2,707  
                               
                               

        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:

 
  Six Months
Ended June 30,
  Year Ended December 31,  
 
  2014   2013   2013   2012   2011  

Net cash provided by operating activities

  $ 1,234   $ 1,177   $ 2,476   $ 2,223   $ 2,456  

Interest expense

                     

Cash income taxes

    135     155     318     (121 )   84  

Cash exploration expenses

    14     16     44     20     40  

Changes in operating assets and liabilities

    48     (13 )   (102 )   202     (123 )

Asset impairments and related items

                (41 )    

Other, net

    (21 )   (27 )   (29 )   (28 )   (27 )
                       

EBITDAX

  $ 1,410   $ 1,308   $ 2,707   $ 2,255   $ 2,430  
                       
                       

Net cash used by investing activities

  $ (1,038 ) $ (768 ) $ (1,713 ) $ (2,755 ) $ (3,565 )
                       
                       

Net cash (used) provided by financing activities

  $ (196 ) $ (409 ) $ (763 ) $ 532   $ 1,106  
                       
                       

 

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PV-10

        PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future income. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an asset value measure to compare against our past reserve bases and the reserve bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the taxpaying status of the entity.

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

 
  At December 31,  
 
  2013   2012  
 
  (in millions)
 

PV-10

  $ 14,018   $ 13,773  

Present value of future income tax discounted at 10%

    (4,795 )   (4,700 )
           

Standardized Measure of Discounted Future Net Cash Flows

  $ 9,223   $ 9,073  
           
           

 

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RISK FACTORS

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

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

Risks Related to Our Business

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

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

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

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

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

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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 gas, in which case the value of our undeveloped acreage may decline and could be impaired.

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

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

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

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

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

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 all oil, gas and NGLs production in California. Although the proposals have not become law, well-funded campaigns by various interest groups could lead to future oil and gas severance taxes. The imposition of such a tax could severely reduce our profit margins and cash flow and

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

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

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

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

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

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

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

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

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

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

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

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

        Following our separation from Occidental, we expect to have total outstanding debt of approximately $6.065 billion, including $5.0 billion in senior notes and a $1.0 billion term loan credit facility. Revolving commitments from our bank group are expected to total $2.0 billion, of which approximately $1.935 billion is expected to remain available to be borrowed.

        Indebtedness outstanding under our credit facility bears interest at a variable rate, so a rise in interest rates will generate greater interest expense to the extent we do not purchase interest rate hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business because we would be required to use a greater proportion of our cash flow to pay interest and principal. Following the separation and incurrence of $6.065 billion of debt, we could incur $1.935 billion in additional indebtedness in compliance with the terms of our debt facilities. In addition, we can incur obligations that do not constitute indebtedness under the indenture or credit facility.

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

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

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

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

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

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

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.

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

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

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

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

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

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

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

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

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

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

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

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

        Climate change, the costs that may be associated with its effects and the regulation of greenhouse gases ("GHGs") may affect our business in many ways, including increasing the costs to provide our products and services, and reducing demand for, and consumption of, our products and services. In addition, legislative and regulatory responses to climate change may increase our operating costs. In 2006, California adopted Assembly Bill ("AB") 32, known as the "California Global Warming Solutions Act of 2006," which establishes a statewide cap on GHG emissions, including on the oil and natural gas production industry, and a "cap-and-trade" program. In December 2010, the California Air Resources Board adopted regulations to implement AB 32 that commenced on January 1, 2012, and require us to obtain GHG emissions allowances corresponding to our reported GHG emissions. In 2013, we incurred approximately $34 million of costs for GHG emissions allowances in California. We estimate costs for GHG emissions allowances in 2014 to be consistent with 2013, at approximately $34 million.

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

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

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

        In connection with our acquisitions, we are often only able to perform limited due diligence. Successful acquisitions of oil and gas properties require an assessment of a number of factors, including

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estimates of recoverable reserves, the timing for recovering the reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact and incomplete, and we may be unable to make these assessments with a high degree of accuracy.

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

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

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

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

Cyber attacks could significantly affect us.

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

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

        Our ability to market our production of oil, gas and NGLs depends on a number of factors, including the proximity of production fields to pipelines and terminal facilities, competition for capacity on such facilities and the ability of such facilities to gather, transport or process our commodities. If our access to markets for commodities we produce is restricted, our costs could increase and our expected production growth 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:

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

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

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

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

        The historical and pro forma financial information included in this information statement has been derived from Occidental's accounting records and may not reflect what our financial position, results of operations or cash flows would have been had we been an independent, stand-alone entity during the periods presented or those that we will achieve in the future. Occidental did not account for us, and we were not operated, as a separate, stand-alone company 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: (1) executive oversight, accounting, procurement, engineering, drilling, exploration, finance, internal audit, legal, risk management, tax, treasury, information technology, government relations, investor relations, public relations, financial reporting, human resources, marketing, ethics and compliance, and certain other shared services; (2) certain employee benefits and incentives; and (3) share-based compensation, that may be different from the comparable expenses that we would have incurred had we operated as a stand-alone company. We have allocated these expenses in our historical financial information on the basis of direct usage when identifiable, with the remainder allocated based on estimated time spent by Occidental personnel, headcount or our relative size compared to Occidental and its subsidiaries. In addition, we have attempted to include recurring costs of operating as a stand-alone company in our pro forma financial statements, although only the additional costs we have determined to be factually supportable are included as pro forma adjustments. We expect the costs of operating as a stand-alone public company, other than the debt-related costs, will be comparable to the costs reported in the historical combined financial statements. These estimates may not prove to be accurate. Our capital expenditure requirements, including acquisitions, historically have been satisfied as part of the companywide cash management practices of Occidental. Following the spin-off, we will 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 is not sufficient to fund our capital expenditure requirements.

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

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Operations" and our financial statements and related notes included elsewhere in this information statement.

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

        Upon completion of the spin-off, we will have an aggregate of approximately            shares of our common stock outstanding. All of those shares (other than those held by our "affiliates") will be freely tradable without restriction. Shares held by our affiliates, which include our directors and executive officers, can be sold subject to volume, manner of sale and notice provisions. We estimate that our affected directors and executive officers will beneficially own approximately            shares of our common stock immediately following the distribution. We are unable to predict whether large amounts of our common stock will be sold in the open market following the spin-off. We are also unable to predict whether a sufficient number of buyers will be in the market at that time. Occidental stockholders may sell the shares of our common stock they receive in the distribution for various reasons. For example, such stockholders may not believe our business profile or level of market capitalization as an independent company fits their investment objectives. A change in the level of analyst coverage following the spin-off could also negatively impact demand for our shares. In addition, following the distribution, Occidental will retain ownership of up to 19.9% of our common stock. Occidental expects to dispose of all of the Retained Securities by making one or more offers to exchange such Retained Securities for outstanding shares of Occidental common stock. For each share of Occidental common stock tendered for exchange, the holder of such Occidental common stock will receive a number of shares of CRC common stock based on an exchange ratio to be determined by Occidental. Any Retained Securities Occidental does not dispose of through such exchanges will be distributed pro rata to Occidental shareholders no later than 18 months after the spin-off. In connection with the spin-off, we are entering into a Stockholder's and Registration Rights Agreement with Occidental, pursuant to which we will agree that, upon the request of Occidental, we will use our best efforts to effect the registration under applicable securities laws of the disposition of shares of common stock retained by Occidental and to cooperate with Occidental to facilitate its disposition of the Retained Securities through one or more exchanges for Occidental common stock. Any disposition by Occidental, or any other significant shareholder, of our common stock in the public market, or the perception that such dispositions may occur, could adversely affect prevailing market prices for our common stock.

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

        Pursuant to the Separation and Distribution Agreement and other agreements with Occidental, Occidental will agree to indemnify us for certain liabilities, and we will agree to indemnify Occidental for certain liabilities, in each case for uncapped amounts, as discussed further in "Arrangements Between Occidental and Our Company." 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 distribution. Third parties could also seek to hold us responsible for any of the liabilities that Occidental has agreed to retain. Further, there can be no assurance that the indemnity from Occidental will be sufficient to protect us against the full amount of such liabilities, or that Occidental will be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from Occidental any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.

Our costs 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.

        Historically, our operations have been fully integrated within Occidental, and we have relied on Occidental to provide certain corporate functions. As a stand-alone public company, we may incur

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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 have been able to enjoy certain benefits from Occidental's scale and purchasing power. As an independent, publicly traded company, we will not have similar negotiating leverage.

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

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

        Certain administrative services required by us for the operation of our business are currently provided by Occidental and its subsidiaries, including, executive oversight, accounting, procurement, engineering, drilling, exploration, finance, internal audit, legal, risk management, tax, treasury, information technology, government relations, investor relations, public relations, financial reporting, human resources, ethics and compliance, marketing and certain other shared services. Prior to the completion of the separation, we will enter into agreements with Occidental related to the separation of our business operations from Occidental, including a Transition Services Agreement. We believe it is helpful for Occidental to provide transitional assistance for us under the Transition Services Agreement to facilitate the efficient operation of our business as we transition to becoming a stand-alone public company. While these services are being provided to us by Occidental, our operational flexibility to modify or implement changes with respect to such services or the amounts we pay for them will be limited. After the expiration or termination of the Transition Services Agreement, we may not be able to replace these services or enter into appropriate third-party agreements on terms and conditions, including cost, comparable to those that we will receive from Occidental under the Transition Services Agreement. Although we intend to replace portions of the services currently provided by Occidental, we may encounter difficulties replacing certain services or be unable to negotiate pricing or other terms as favorable as those we currently have in effect. See "Arrangements Between Occidental and Our Company—Transition Services Agreement."

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

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

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

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

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

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

        For any tax periods (or portion thereof) in which Occidental owns at least 80% of the total voting power and value of our common stock, we and our subsidiaries will be included in Occidental's consolidated group for federal income tax purposes. In addition, we or one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of Occidental or one or more of its subsidiaries for state or local income tax purposes. Under the Tax Sharing Agreement, for each period in which we or any of our subsidiaries are consolidated or combined with Occidental for purposes of any tax return, and with respect to which such tax return has not yet been filed, Occidental will prepare a pro forma tax return for us as if we filed our own consolidated, combined or unitary return, except that such pro forma tax return will generally include current income, deductions, credits and losses from us (with certain exceptions) and will not include any carryovers or carrybacks of losses or credits. We will reimburse Occidental for any taxes shown on the pro forma tax returns, subject to certain adjustments. In addition, by virtue of Occidental's controlling ownership and the Tax Sharing Agreement, Occidental will effectively control all of our tax decisions in connection with any consolidated, combined or unitary income tax returns in which we (or any of our subsidiaries) are included. The Tax Sharing Agreement provides that Occidental will have sole authority to respond to and conduct all tax proceedings (including tax audits) relating to us, to prepare and file all consolidated, combined or unitary income tax returns in which we are included on our behalf (including the making of any tax elections), and to determine the reimbursement amounts in connection with any pro forma tax returns. This arrangement may result in conflicts of interest between Occidental and us. For example, under the Tax Sharing Agreement, Occidental will be able to choose to contest, compromise or settle any adjustment or deficiency proposed by the relevant taxing authority in a manner that may be beneficial to Occidental and detrimental to us. See "Arrangements Between Occidental and Our Company—Tax Sharing Agreement."

        Moreover, notwithstanding the Tax Sharing Agreement, federal law provides that each member of a consolidated group is liable for the group's entire tax obligation. Thus, to the extent Occidental or other members of Occidental's consolidated group fail to make any federal income tax payments required by law, we could be liable for the shortfall with respect to periods in which we were a member of Occidental's

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consolidated group. Similar principles may apply for state or local income tax purposes where we file combined, consolidated or unitary returns with Occidental or its subsidiaries for federal, foreign, state or local income tax purposes. Pursuant to the Tax Sharing Agreement, Occidental has agreed to indemnify us for any taxes attributable to Occidental that we are required to pay as a result of our membership in the Occidental consolidated group during such period.

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 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.

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

        The separation is conditioned on Occidental's receipt of a private letter ruling from the IRS substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the separation will not cause the distribution to be taxable to Occidental or its affiliates. The separation is further conditioned on Occidental's tax counsel issuing an opinion in form and substance acceptable to Occidental that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off generally qualifies as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code. The private letter ruling and opinion will rely on facts, assumptions, representations and undertakings from Occidental and us regarding the past and future conduct of the companies' respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied, Occidental may not be able to rely on the private letter ruling or the opinion of its tax advisor and could be subject to significant tax liabilities. In addition, an opinion of counsel is not binding upon the IRS, so, notwithstanding the opinion of Occidental's tax advisor, the IRS could conclude upon audit that the separation is taxable in full or in part. The IRS may determine that the separation is taxable for other reasons, including as a result of certain significant changes in the stock ownership of Occidental or us after the separation. If the separation is determined to be taxable for U.S. federal income tax purposes, Occidental or its stockholders could incur significant income tax liabilities, and we could incur significant liabilities. For a discussion of the potential tax consequences to Occidental stockholders if the separation is determined to be taxable, see "The Spin-Off—U.S. Federal Income Tax Consequences of the Spin-Off." For a description of the sharing of such liabilities between Occidental and us, see "Arrangements Between Occidental and Our Company—Tax Sharing Agreement."

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

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

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

        The separation is subject to review under various state and federal fraudulent conveyance laws. Under these laws, if a court in a lawsuit by an unpaid creditor or an entity vested with the power of such creditor

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

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

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

Risks Related to Our Common Stock

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

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

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

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

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

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

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

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

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

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

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

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

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FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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THE SPIN-OFF

Background

        As part of a strategic review to streamline and focus operations, Occidental's board of directors reviewed the possibility and advisability of separating its California business from Occidental's other businesses. On February 14, 2014, Occidental announced that its board of directors had authorized management to pursue the spin-off of its California business into a standalone, publicly traded company. On                    , 2014, Occidental announced that its board of directors had unanimously approved the spin-off and the distribution of at least 80.1% of the stock of the new company to Occidental's shareholders as of the record date of                    , 2014. This authorization is subject to the satisfaction or waiver by Occidental, in its sole discretion, of the conditions described below under "—Conditions to the Spin-Off." Following our spin-off from Occidental, we will be an independent, publicly owned company.

        To complete the spin-off on the Closing Date, Occidental will, following the restructuring transactions, distribute to its stockholders at least 80.1% of the shares of our common stock. The distribution will occur on the distribution date, which is                    , 2014. Each holder of Occidental common stock will receive            shares of our common stock for each share of Occidental common stock held by such stockholder at the close of business on                    , 2014, the record date. After completion of the spin-off, we will own and operate the California business as an independent publicly traded company.

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

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

Reasons for the Spin-Off

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

Manner of Effecting the Spin-Off

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

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

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

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

Occidental Retained Shares of CRC Common Stock

        Occidental expects to dispose of all of the Retained Securities by making one or more offers to exchange such Retained Securities for outstanding shares of Occidental common stock. For each share of Occidental common stock tendered for exchange, the holder of such Occidental common stock will receive a number of shares of CRC common stock based on an exchange ratio to be determined by Occidental. Any Retained Securities Occidental does not dispose of through such exchanges will be distributed pro rata to Occidental shareholders no later than 18 months after the spin-off.

Treatment of Fractional Shares

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

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U.S. Federal Income Tax Consequences of the Spin-Off

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

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

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

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

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

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

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

Tax-free Status of the Distribution

        Occidental has requested (i) a private letter ruling substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates and (ii) an opinion from its tax counsel regarding, among other things, that the spin-off generally qualifies as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code. Assuming that the distribution qualifies as a tax-free distribution,

        The private letter ruling and tax opinion of counsel will rely on certain facts, assumptions, representations and undertakings from Occidental and us regarding the past and future conduct of the companies' respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied, Occidental may not be able to rely on the private letter ruling or the opinion of its tax advisor. In addition, an opinion of counsel is not binding on the IRS, so, notwithstanding the opinion of Occidental's tax advisor, the IRS could conclude upon audit that the distribution is taxable if it disagrees with the conclusions in the opinion or for other reasons. There can be no assurance that the IRS or the courts will not challenge the qualification of the distribution as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code or that such challenge would not prevail.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Information Reporting for Significant Stockholders

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

Indemnification

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

Results of the Spin-Off

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

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

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        Before our separation from Occidental, we and Occidental will enter into a Separation and Distribution Agreement and several other agreements to effect the spin-off. These agreements will provide for the allocation between us and Occidental of Occidental's assets, liabilities and obligations, and we will generally be allocated those assets, liabilities and obligations relating to the California business. These agreements will also govern certain interactions between us and Occidental after the separation (including with respect to employee matters, tax matters and intellectual property matters). We and Occidental will also enter into a Transition Services Agreement that will provide for, among other matters, assistance to us or Occidental as needed. For a more detailed description of these agreements, see "Arrangements Between Occidental and Our Company."

Trading Prior to the Distribution Date

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

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

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

Treatment of Long-Term Incentive Awards for Current and Former Employees

        We currently anticipate that equity-based and long-term incentive compensation awards from Occidental held by employees who will be employed by us and our subsidiaries following the spin-off ("transferred employees") will generally be converted into awards with respect to our common stock under our equity and long-term incentive compensation programs, with the number of such awards determined based upon the relative trading prices of our common stock and Occidental common stock in a manner intended to preserve the value of such awards. Generally, the corresponding award granted under our long-term incentive plan will be similar to the award the transferred employee held under Occidental's long-term incentive plan, except that restricted stock units and cash-based long-term incentive awards will be converted instead into awards of restricted shares of our common stock. In addition, the converted awards will cease to be subject to the prior-established performance-based vesting requirements and will

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instead vest based upon the same service-based vesting requirements and such performance-based vesting requirements, if any, as are determined by the Occidental Compensation Committee as of the spin-off.

        Equity-based and long-term incentive compensation awards from Occidental that are held by employees who will stay with Occidental will remain outstanding pursuant to the applicable plans maintained by Occidental, with corresponding adjustments made to the number of shares of Occidental common stock subject to such awards and the reference price of such awards based upon the relative pre-spin-off and post-spin-off trading prices of Occidental common stock in a manner intended to preserve the value of such awards.

        The treatment of certain phantom unit awards held by current and former employees of us and Occidental has not yet been finally determined.

Conditions to the Spin-Off

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

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

Reasons for Furnishing this Information Statement

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

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TRADING MARKET

Market for Our Common Stock

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

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

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

Transferability of Shares of Our Common Stock

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

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

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

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

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

        Except for our common stock distributed in the distribution and the Retained Securities, none of our equity securities will be outstanding on or immediately after the spin-off and, except for the Stockholder's and Registration Rights Agreement with Occidental with respect to the Retained Securities, there are no registration rights agreements existing with respect to our common stock.

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DIVIDEND POLICY

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


CAPITALIZATION

        The following table sets forth (i) our historical capitalization as of June 30, 2014 and (ii) our adjusted capitalization assuming the distribution, the incurrence of debt and other matters (as discussed in "The Spin-Off") were effective as of June 30, 2014. The table below should be read in conjunction with "Summary Combined Historical and Pro Forma Financial Data," "Unaudited Pro Forma Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our audited combined financial statements, unaudited interim combined condensed financial statements and the notes to those statements included elsewhere in this information statement.

 
  As of June 30, 2014  
 
  Historical   As Adjusted  
 
  (Unaudited)
 
 
  (in millions)
 

Debt Outstanding

             

Short-term debt

  $   $  

Long-term debt

   
   
6,065
 
           

Total debt

        6,065  
           

Net Investment / Stockholders' Equity

             

Common stock

             

Par value

           

Additional paid-in capital

   
       
           

Net Investment/Stockholders' Equity

    10,274     4,657  
           

Total Capitalization

  $ 10,274   $ 10,722  
           
           

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SELECTED HISTORICAL COMBINED FINANCIAL DATA

        The following tables set forth selected historical combined financial data for the periods indicated. The historical unaudited combined financial data for the six months ended June 30, 2014 and 2013 and balance sheet data as of June 30, 2014 have been derived from our unaudited condensed combined financial statements included elsewhere in this information statement. The unaudited condensed combined financial statements have been prepared on the same basis as our audited combined financial statements, except as stated in the related notes thereto, and include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial condition and result of operations for such periods. The results of operations for the six months ended June 30, 2014 and 2013 presented below are not necessarily indicative of results for the entire fiscal year. Our selected historical combined financial data as of December 31, 2013 and 2012 and for the fiscal years ended December 31, 2013, 2012 and 2011 have been derived from our audited historical combined financial statements included elsewhere in this information statement. Our historical combined financial data as of December 31, 2011, 2010 and 2009 and for the years ended December 31, 2010 and 2009 have been derived from our unaudited accounting records not included in this information statement.

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

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

 
  Six Months
Ended
June 30,
  Year Ended December 31,  
 
  2014   2013   2013   2012   2011   2010   2009  
 
  (in millions)
 

Statement of Income Data:

                                           

Net sales, including to related parties

  $ 2,262   $ 2,098   $ 4,285   $ 4,072   $ 3,938   $ 2,916   $ 2,221  

Income before taxes

  $ 782   $ 703   $ 1,447   $ 1,181   $ 1,641   $ 1,129   $ 659  

Net income

  $ 469   $ 422   $ 869   $ 699   $ 971   $ 719   $ 401  

 

 
  As of
June 30,

  As of December 31,  
 
  2014   2013   2012   2011   2010   2009  
 
  (in millions)
 

Balance Sheet Data:

                                     

Property, plant and equipment, net

  $ 14,434   $ 14,008   $ 13,499   $ 11,778   $ 8,823   $ 7,832  

Net investment

  $ 10,274   $ 9,989   $ 9,860   $ 8,624   $ 6,557   $ 6,099  

 

 
  Six Months
Ended
June 30,
  Year Ended December 31,  
 
  2014   2013   2013   2012   2011   2010   2009  
 
  (in millions)
 

Statement of Cash Flows Data:

                                           

Net cash provided by operating activities

  $ 1,234   $ 1,177   $ 2,476   $ 2,223   $ 2,456   $ 1,751   $ 1,056  

Capital expenditures

  $ (1,003 ) $ (737 ) $ (1,669 ) $ (2,331 ) $ (2,164 ) $ (1,056 ) $ (650 )

Payments for purchases of assets and businesses, and other

  $ (35 ) $ (31 ) $ (48 ) $ (427 ) $ (1,405 ) $ (448 ) $ (516 )

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UNAUDITED PRO FORMA COMBINED FINANCIAL DATA

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

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

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

        The unaudited pro forma combined statements of income for the year ended December 31, 2013 and the six months ended June 30, 2014 have been prepared as though the spin-off occurred as of January 1, 2013. The unaudited pro forma combined balance sheet at June 30, 2014 has been prepared as though the spin-off occurred on June 30, 2014. The pro forma adjustments are based on available information and assumptions that we believe are reasonable; however, such adjustments are subject to change based on the final terms of the spin-off and the related separation and distribution agreements, as well as our expected debt offering. Additionally, such adjustments are estimates and may not prove to be accurate.

        Management has attempted to include recurring costs of operating as a stand-alone company, including executive oversight, accounting, procurement, engineering, drilling, exploration, marketing, finance, internal audit, legal, risk management, tax, treasury, information technology, government relations, investor relations, public relations, financial reporting, human resources, ethics and compliance, and certain other shared services related to being a stand-alone company. Only costs we have determined to be factually supportable are included as pro forma adjustments, including the items described above. We expect the costs of operating as a stand-alone public company, other than debt-related costs, will be generally comparable to the costs reported in the historical combined financial statements. Additionally, such costs are estimates and there could be additional incremental costs not reflected in the unaudited pro forma combined financial statements. Subject to the terms of the Separation and Distribution Agreement, nonrecurring third-party costs and expenses related to the separation, other than the debt-related costs, and incurred prior to the separation date will generally be paid by Occidental. We expect such nonrecurring amounts to include costs to separate and/or duplicate information technology systems, outside legal and accounting fees, and similar costs.

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

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

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CALIFORNIA RESOURCES CORPORATION
Unaudited Pro Forma Combined Statements of Income
Six Months Ended June 30, 2014

 
  Historical   Pro Forma
Adjustments
   
  Pro Forma  
 
  (in millions, except per share amounts)
 

Revenues:

                       

Net sales to related parties

  $ 2,206   $ (2,206 ) (a)   $  

Net sales to third parties

    56     2,206   (a)     2,262  

Other income

    (1 )           (1 )
                   

    2,261             2,261  
                   

Costs and expenses:

                       

Production costs

    578             578  

Selling, general and administrative expenses

    166             166  

Depreciation, depletion and amortization

    582             582  

Taxes other than on income

    107             107  

Exploration expense

    46             46  

Interest and debt expense, net

        146   (b)     146  
                   

    1,479     146         1,625  
                   

Income before income taxes

    782     (146 )       636  

Provision for income taxes

    (313 )   58   (c)     (255 )
                   

Net income

  $ 469   $ (88 )     $ 381  
                   
                   

Pro forma earnings per share(d):

                       

Basic

                  $    

Diluted

                  $    

Pro forma shares outstanding(d):

                       

Basic

                       

Diluted

                       

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

 
  Historical   Pro Forma
Adjustments
   
  Pro Forma  
 
  (in millions, except per share amounts)
 

Revenues and other income:

                       

Net sales to related parties

  $ 4,174   $ (4,174 ) (a)   $  

Net sales to third parties

    111     4,174   (a)     4,285  

Other income

    (1 )           (1 )
                   

    4,284             4,284  
                   

Costs and expenses:

                       

Production costs

    1,066             1,066  

Selling, general and administrative expenses

    326             326  

Depreciation, depletion and amortization

    1,144             1,144  

Taxes other than on income

    185             185  

Exploration expense

    116             116  

Interest and debt expense, net

        292   (b)     292  
                   

    2,837     292         3,129  
                   

Income before income taxes

    1,447     (292 )       1,155  

Provision for income taxes

    (578 )   116   (c)     (462 )
                   

Net income

  $ 869   $ (176 )     $ 693  
                   
                   

Pro forma earnings per share(d):

                       

Basic

                  $    

Diluted

                  $    

Pro forma shares outstanding(d):

                       

Basic

                       

Diluted

                       

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CALIFORNIA RESOURCES CORPORATION
Unaudited Pro Forma Combined Balance Sheets
As of June 30, 2014

 
  Historical   Pro Forma
Adjustments
   
  Pro Forma  
 
  (in millions)
 

Current assets:

                       

Cash and cash equivalents

  $   $   (e)   $  

Trade receivables, net

    21     401   (f)     422  

Inventories

    72             72  

Other current assets

    185     4   (f)     189  
                   

Total current assets

    278     405         683  
                   

Property, plant and equipment, net

    14,434             14,434  

Other assets

    34     65   (e)     99  
                   

Total assets

  $ 14,746   $ 470       $ 15,216  
                   
                   

Current liabilities:

                       

Accounts payable

  $ 504   $       $ 504  

Accrued liabilities

    175     12   (f)     187  
                   

Total current liabilities

    679     12         691  
                   

Long-term debt, net

        6,065   (e)     6,065  

Deferred income taxes

    3,293     (6 ) (f)     3,287  

Deferred credits and other liabilities

    500     16   (f)     516  

Net Investment/Stockholders' Equity:

                       

Common stock

          (g)      

Additional paid-in capital

          (h)      

Net investment

    10,296     (6,000 ) (e)     4,679  

          383   (f)        

Accumulated other comprehensive income (loss)

    (22 )           (22 )
                   

Total net investment/stockholders' equity

    10,274     (5,617 )       4,657  
                   

Total liabilities and net investment/stockholder's equity

  $ 14,746   $ 470       $ 15,216  
                   
                   

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CALIFORNIA RESOURCES CORPORATION
Notes to Unaudited Pro Forma Combined Financial Statements

        (a)   After the spin-off, we do not expect to have sales to Occidental. The adjustment reflects the reclassification of "net sales to related parties" to "net sales to third parties."

        (b)   Reflects the following adjustments to interest and debt expense resulting from the assumed incurrence of $6.065 billion of indebtedness in connection with the spin-off:

 
  Six Months
Ended
June 30,
2014
  Year Ended
December 31,
2013
 
 
  (in millions)
 

Interest expense on $6.065 billion of newly incurred indebtedness

  $ 137   $ 273  

Amortization of debt issuance costs

    4     9  

Commitment fee on revolving credit facility

    5     10  
           

Total pro forma adjustment

  $ 146   $ 292  
           
           

        Pro forma interest expense was calculated based on an assumed blended interest rate of 4.5% using market rates on an assumed borrowing amount of $6.065 billion. Interest expense also includes estimated amortization on approximately $65 million of debt issuance costs related to our anticipated debt, including the revolving credit facility. Such costs are amortized over the terms of the associated debt. Interest expense also includes an estimated 0.5% commitment fee on the anticipated new $2.0 billion revolving credit facility. Actual interest expense may be higher or lower depending on fluctuations in interest rates. A one percent change in interest rates would result in an $11 million change in annual interest expense.

        (c)   Represents the tax effect of pro forma adjustments to income before income taxes using a statutory tax rate of 40% for both the six months ended June 30, 2014 and the year ended December 31, 2013. Our effective tax rate could be different (either higher or lower) depending on activities subsequent to the spin-off.

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

        (e)   Represents the financing transactions, the dividend to be paid to Occidental and their effects on cash, as follows (in millions):

Cash received from borrowings

  $ 6,065  

Debt issuance costs

    (65 )

Dividend to Occidental

    (6,000 )
       

Cash pro forma adjustment

  $  
       
       

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        (f)    Represents the following adjustments to the respective balance sheet line items (in millions):

Trade receivables, net

  $ 401  

Other current assets

    4  

Accrued liabilities

    (12 )

Deferred income taxes

    6  

Deferred credits and other liabilities

    (16 )
       

  $ 383  
       
       

        The adjustment to trade receivables represents the receivables CRC would carry as it starts marketing its own products as a stand-alone company. Historically, Occidental marketed CRC's products and collected the proceeds. As a result, the historical financial statements do not reflect any receivables. The adjustments to accrued liabilities and deferred credits and other liabilities represent employee-related liabilities that we will assume from Occidental for certain employees and executives who will transfer to CRC. For additional information, see "Arrangements between Occidental and Our Company." The adjustments to other current assets and deferred income taxes represent the tax effects of temporary differences related to the liability adjustments reflected above.

        (g)   Represents the issuance of approximately                shares of our common stock at a par value of $0.01 per share.

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

Reclassification of Occidental Petroleum Corporation's net investment in us

  $    

New liabilities recorded on our books (see note (f))

       

Distributions to Occidental (see note (e))

       
       

Total additional paid-in capital

  $    
       
       

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

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

         Except when the context otherwise requires or where otherwise indicated, (1) all references to "CRC," the "Company," "we," "us" and "our" refer to California Resources Corporation and its subsidiaries or, as the context requires, the California business, (2) all references to the "California business" refer to Occidental's California oil and gas exploration and production operations and related assets, liabilities and obligations, which we will assume in connection with the spin-off, and (3) all references to "Occidental" refer to Occidental Petroleum Corporation, our parent company, and its subsidiaries, other than us.

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

The Separation and Spin-off

        On February 14, 2014, Occidental announced that its board of directors had authorized management to pursue the spin-off of the California business into a standalone, publicly traded company. The spin-off is being executed in accordance with a Separation and Distribution Agreement between us and Occidental. The spin-off is intended to be tax-free to the stockholders of Occidental and to Occidental and us for U.S. federal income tax purposes. Occidental intends to distribute, on a pro rata basis, at least 80.1% of our common stock to the Occidental stockholders as of the record date for the spin-off. Upon completion of the spin-off, we and Occidental will each be independent, publicly traded companies and will have separate public ownership, boards of directors and management. The spin-off is, among other things, subject to final approval by Occidental's board of directors and the satisfaction or waiver by Occidental, in its sole discretion, of certain conditions to the spin-off, including the, receipt of a private letter ruling from the IRS and an opinion of tax counsel, with respect to the tax-free nature of the spin-off for federal income tax purposes.

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

Basis of Presentation

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

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

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

        The combined statements of income also include expense allocations for certain functions and centrally-located activities historically performed by Occidental. These functions include executive oversight, accounting, procurement, engineering, drilling, exploration, marketing, internal audit, legal, risk management, finance, tax, treasury, information technology, government relations, investor relations, public relations, financial reporting, human resources, ethics and compliance, and certain other shared services. These allocations are based primarily on specific identification of time or activities associated with us, employee headcount or our relative size compared to Occidental. Our management believes the assumptions underlying the combined financial statements, including the assumptions regarding allocating expenses from Occidental, are reasonable. However, the combined financial statements may not include all of the actual expenses that would have been incurred, may include duplicative costs and may not reflect our combined results of operations, financial position and cash flows had we operated as a stand-alone public company during the periods presented. We have attempted to include recurring costs of operating as a stand-alone company in our pro forma financial statements, although only the additional costs we have determined to be factually supportable are included as pro forma adjustments, and there could be incremental costs not reflected in the unaudited pro forma combined financial statements. However, we expect the costs of operating as a stand-alone public company, other than debt-related costs, will be generally comparable to the costs reported in the historical combined financial statements. These estimates may not prove to be accurate. Actual costs that would have been incurred if we had been a stand-alone public company would depend on multiple factors, including organizational structure and strategic and operating decisions. Subject to the terms of the Separation and Distribution Agreement, nonrecurring third-party costs and expenses related to the separation, other than the debt-related costs, and incurred prior to the separation date will generally be paid by Occidental. We expect such nonrecurring amounts to include costs to separate and/or duplicate information technology systems, outside legal and accounting fees, and similar costs. See "Unaudited Pro Forma Combined Financial Data."

        We have historically participated in Occidental's corporate treasury management program and have not incurred any debt. Excess cash generated by our business has been distributed to Occidental, and likewise our cash needs have been provided by Occidental, in the form of an investment. Accordingly, we have not included debt or related interest expense in our combined financial statements because there was no specifically identifiable debt associated with our operations. We intend to enter into new financing arrangements in connection with the spin-off. We expect to incur up to $6.065 billion in new debt and make a cash distribution of approximately $6.0 billion to Occidental. As a result, the capitalization for our business will be different and we will incur cash interest expenses as well as amortization of financing costs.

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 prices and differentials may fluctuate significantly, generally as a result of changes in supply and demand and other market-related uncertainties. These and other factors make it impossible to predict realized prices reliably. We respond to economic conditions primarily by adjusting our capital expenditures to be in line with current economic conditions, including adjusting the size and allocation of our capital program. We have only occasionally hedged our commodity price risk and do not expect to have a significant hedging program in the future. A significant portion of our oil production is

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typically linked to international waterborne-based prices that in the recent past have been at a premium to in-land U.S. crude prices such as West Texas Intermediate ("WTI") for comparable grades. We believe that the limited crude transportation infrastructure from other parts of the country to California will allow us to continue to realize strong margins as a result. The following table presents the average daily WTI, Brent and NYMEX gas prices for 2013, 2012 and 2011:

 
  2013   2012   2011  

WTI oil ($/Bbl)

  $ 97.97   $ 94.21   $ 95.12  

Brent oil ($/Bbl)

  $ 108.76   $ 111.70   $ 110.90  

NYMEX gas ($/Mcf)

  $ 3.66   $ 2.81   $ 4.11  

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

 
  2013   2012   2011  

Oil as a percentage of average WTI

    106 %   110 %   109 %

NGLs as a percentage of average WTI

    51 %   56 %   74 %

Gas as a percentage of NYMEX

    102 %   105 %   105 %

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

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

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

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

Seasonality

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

Operations

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

        Our share of production and reserves from operations in Long Beach, California are subject to contractual arrangements similar to production-sharing contracts and are in effect through the economic

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life of the assets. Under such contracts, we record a share of production and reserves to recover all capital and production costs and an additional share for profit. These contractual arrangements obligate us to fund all capital and production costs and have established base production volumes for each period. The contracts do not differentiate between capital and production costs. In accordance with the terms of these contracts, our portion of the production represents: (1) volumes to recover our partners' share of capital and production costs we incur on their behalf and all costs associated with base production, (2) volumes for our defined share of base production and (3) volumes for our defined share of production in excess of amounts related to base production 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 run through the end of the economic lives of the related assets. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline. Overall, our net economic benefit from these contracts is greater when product prices are higher. Production under these contracts represented 19% of our revenues for the year ended December 31, 2013.

        The following table sets forth our production volumes of oil, NGLs and natural gas per day for the six-month periods ended June 30, 2014 and 2013 and each of the three years in the period ended December 31, 2013.

 
  Six months
ended
June 30,
  Year ended
December 31,
 
 
  2014   2013   2013   2012   2011  

Oil (MBbl/d)

                               

San Joaquin Basin

    62     57     58     58     56  

Los Angeles Basin

    28     25     26     24     19  

Ventura Basin

    6     6     6     6     5  

Sacramento Basin

                     
                       

Total

    96     88     90     88     80  
                       
                       

NGLs (MBbl/d)

                               

San Joaquin Basin

    17     19     19     16     14  

Los Angeles Basin

                     

Ventura Basin

    1     1     1     1     1  

Sacramento Basin

                     
                       

Total

    18     20     20     17     15  
                       
                       

Natural gas (MMcf/d)

                               

San Joaquin Basin

    177     185     182     204     220  

Los Angeles Basin

            2     3     1  

Ventura Basin

    12     12     11     12     12  

Sacramento Basin

    54     65     65     37     27  
                       

Total

    243     262     260     256     260  
                       
                       

Total Production (MBoe/d)(a)

    155     152     154     148     138  
                       
                       

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 energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per barrel and $3.66 per Mcf, respectively, resulting in an oil-to-gas ratio of over 25 to 1.

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        The following table sets forth the average realized prices for our products:

 
  Six months ended
June 30,
  Year ended December 31,  
 
  2014   2013   2013   2012   2011  

Oil Prices ($ per Bbl)

  $ 103.43   $ 105.21   $ 104.16   $ 104.02   $ 103.80  

NGLs Prices ($ per Bbl)

  $ 54.86   $ 47.90   $ 50.43   $ 52.76   $ 70.03  

Gas Prices ($ per Mcf)

  $ 4.67   $ 3.82   $ 3.73   $ 2.94   $ 4.31  

Income Taxes

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

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

 
  Six months
ended
June 30,
  Year ended December 31,  
 
  2014   2013   2013   2012   2011  
 
  (in millions)
 

Pre-tax income

  $ 782   $ 703   $ 1,447   $ 1,181   $ 1,641  

Income tax expense

    (313 )   (281 )   (578 )   (482 )   (670 )
                       

Net income

  $ 469   $ 422   $ 869   $ 699   $ 971  
                       
                       

Effective tax rate

    40 %   40 %   40 %   41 %   41 %

Income Statement Analysis

 
  Six months
ended June 30,
  Years ended December 31,  
 
  2014   2013   2013   2012   2011  
 
  (in millions)
 

Net sales (including related parties)

  $ 2,262   $ 2,098   $ 4,285   $ 4,072   $ 3,938  

Other income

    (1 )       (1 )   1     (4 )

Production costs

    (578 )   (527 )   (1,066 )   (1,314 )   (1,074 )

Selling, general and administrative expenses

    (166 )   (154 )   (326 )   (296 )   (287 )

Depreciation, depletion and amortization

    (582 )   (565 )   (1,144 )   (926 )   (675 )

Asset impairments and related items

                (41 )    

Taxes other than on income

    (107 )   (109 )   (185 )   (167 )   (143 )

Exploration expense

    (46 )   (40 )   (116 )   (148 )   (114 )

Provision for income taxes

    (313 )   (281 )   (578 )   (482 )   (670 )
                       

Net income

    469     422     869     699     971  
                       
                       

EBITDAX(1)

  $ 1,410   $ 1,308   $ 2,707   $ 2,255   $ 2,430  

(1)
We define EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; and exploration expense. 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 provided in addition to, and not as an alternative for income and liquidity measures calculated in accordance with GAAP, and

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    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:

 
  Six Months
Ended
June 30,
  Year Ended December 31,  
 
  2014   2013   2013   2012   2011  
 
  (in millions)
 

Net income

  $ 469   $ 422   $ 869   $ 699   $ 971  

Interest expense

  $   $   $   $   $  

Provision for income taxes

  $ 313   $ 281   $ 578   $ 482   $ 670  

Depreciation, depletion and amortization

  $ 582   $ 565   $ 1,144   $ 926   $ 675  

Exploration expense

  $ 46   $ 40   $ 116   $ 148   $ 114  
                       

EBITDAX

  $ 1,410   $ 1,308   $ 2,707   $ 2,255   $ 2,430  
                       
                       

Six Months Ended June 30, 2014 vs. June 30, 2013

        Net sales increased 8%, or $164 million, for the six months ended June 30, 2014, compared to the same period of 2013. Of this increase, $144 million was attributable to higher oil volumes and $41 million and $27 million were attributable to higher realized prices for gas and NGLs, respectively. The increase was partially offset by decreases of $23 million and $16 million, respectively, attributable to lower NGLs and gas volumes, and $20 million of lower realized oil prices. Our daily oil production increased by 8,000 barrels while our daily NGLs and natural gas production decreased by 2,000 barrels and 19 MMcf (or 3,000 Boe), respectively. The increase in oil production primarily reflected our strategy to increase our overall capital expenditure program with a focus on oil drilling while reducing drilling capital for natural gas in light of higher oil prices and lower gas prices in recent years.

        Production costs for the six months ended June 30, 2014 increased 10%, or $51 million, compared to the same period of 2013, mainly due to $41 million in higher costs for natural gas used in our steamflood operations and $7 million in higher energy costs.

        Selling, general and administrative expenses increased 8%, or $12 million, for the six months ended June 30, 2014, compared to the same period of 2013, predominantly due to higher employee related costs.

        Depreciation, depletion and amortization ("DD&A") expense increased 3% or $17 million for the six months ended June 30, 2014, compared to the same period of 2013, and reflected additional capital investments.

        Taxes other than on income for the six months ended June 30, 2014 were comparable to the same period of 2013.

        Exploration expense increased by $6 million, or 15%, for the six months ended 2014, compared to the same period of 2013, due to higher dry hole expenses of $8 million.

        Provision for income taxes increased by $32 million, or 11%, due to the effect of higher pre-tax income of $79 million.

Year Ended December 31, 2013 vs. 2012

        Net sales increased 5%, or $213 million, in 2013, compared to 2012. Of this increase, $47 million was attributable to higher oil and gas volumes, $77 million was attributable to higher oil and gas prices, $63 million was attributable to higher volumes for NGLs and $41 million was attributable to higher power

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sales. 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 1,000 Boe. The increase in liquids production primarily reflected our strategy to increase our overall capital expenditure program with a focus on oil drilling while reducing drilling capital for natural gas in light of higher oil prices and lower gas prices in recent years. The slight increase in our natural gas production reflected increased production from acquisitions made in 2012 and associated gas produced from oil drilling, partially offset by lower gas production due to reduced investment in natural gas drilling in 2013.

        Production costs decreased by $248 million to $18.99 per Boe in 2013, compared to $24.34 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 10%, or $30 million, in 2013, compared to 2012, mostly due to higher compensation and employee related costs of approximately $25 million, 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 $3.23 per Boe increase in the DD&A rate, which was a result of additional capital investments throughout our asset base. In recent years, we have been systematically increasing our investments in IOR and EOR recovery assets and facilities. Significant investment on the front end of these projects is necessary, which has caused an increase in our DD&A rate.

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

        Taxes other than on income increased 11%, 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.

        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.

Year Ended December 31, 2012 vs. 2011

        Net sales increased 3%, or $134 million, in 2012 compared to 2011. Of this increase, $325 million was attributable to higher oil volumes, $7 million was attributable to higher oil prices and $40 million was attributable to higher NGL volumes. The increase was partially offset by $124 million attributable to lower gas prices, $6 million attributable to lower gas volumes, $94 million attributable to lower NGL prices and $14 million attributable to lower power sales. Our daily liquids production increased by 10,000 Boe, while our daily natural gas production decreased by 4 MMcf, or less than 1,000 Boe. The increase in production volumes from 2011 to 2012, in particular the growth in our liquids production, was a result of production from acreage acquired in 2011 and increased capital expenditures in 2012 compared to 2011.

        Production costs in 2012 increased 22%, or $240 million, compared to 2011, mainly due to $92 million of higher downhole maintenance and $125 million of increased field support costs.

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        Selling, general and administrative expenses increased 3%, or $9 million, in 2012, compared to 2011, mainly due to higher employee related costs.

        DD&A expense increased by $251 million. Of this increase, $190 million was attributable to a $3.77 per Boe increase in the DD&A rate, reflecting additional capital investments, largely in the San Joaquin and Sacramento basin operations, and $61 million was attributable to asset acquisitions and higher volumes.

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

        Taxes other than on income increased 17%, or $24 million, in 2012, compared to 2011, almost entirely due to higher property taxes.

        Exploration expense increased by 30%, or $34 million, in 2012 due to higher dry hole expense of $29 million in the Los Angeles basin and $23 million in the Sacramento basin and higher lease rentals of $5 million as compared to 2011, partially offset by lower seismic and geological and geophysical expenses of $23 million.

        Provision for income taxes decreased by $188 million in 2012, compared to 2011, due to the effect of $460 million in lower pre-tax income.

Liquidity and Capital Resources

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

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

        We expect the term debt and revolving credit facility to bear interest at LIBOR plus a margin and the senior notes at fixed or variable rates, all of which will depend on market conditions and our credit rating.

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Cash Flow Analysis

 
  Six months
ended June 30,
  Years ended December 31,  
 
  2014   2013   2013   2012   2011  
 
  (in millions)
 

Net cash flows provided by operating activities

  $ 1,234   $ 1,177   $ 2,476   $ 2,223   $ 2,456  

Net cash flows used in investing activities

  $ (1,038 ) $ (768 ) $ (1,713 ) $ (2,755 ) $ (3,565 )

Net cash flows (used in) provided by financing activities

  $ (196 ) $ (409 ) $ (763 ) $ 532   $ 1,106  

EBITDAX(1)

  $ 1,410   $ 1,308   $ 2,707   $ 2,255   $ 2,430  

(1)
We define EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; and exploration expense. 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 provided in addition to, and not as an alternative for income and liquidity measures calculated in accordance with GAAP, and should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.


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:

 
  Six Months
Ended June 30,
  Year Ended December 31,  
 
  2014   2013   2013   2012   2011  

Net cash provided by operating activities

  $ 1,234   $ 1,177   $ 2,476   $ 2,223   $ 2,456  

Interest expense

                     

Cash income taxes

    135     155     318     (121 )   84  

Cash exploration expenses

    14     16     44     20     40  

Changes in operating assets and liabilities

    48     (13 )   (102 )   202     (123 )

Asset impairments and related items

                (41 )    

Other, net

    (21 )   (27 )   (29 )   (28 )   (27 )
                       

EBITDAX

  $ 1,410   $ 1,308   $ 2,707   $ 2,255   $ 2,430  
                       
                       

Six months ended June 30, 2014 vs. June 30, 2013

        Our net cash provided by operating activities increased by $57 million from $1,177 million in 2013 to $1,234 million in 2014 consistent with the $47 million increase in our net income over the same period. The increase in operating cash flows also reflected higher non-cash items such as deferred taxes of $52 million and DD&A of $17 million, partially offset by a decrease in working capital of $61 million.

        Our cash flow used in investing activities increased by $270 million for the six months ended June 30, 2014 to $1,038 million, compared to the same period of 2013. The increase mainly consisted of $266 million of higher capital expenditures for development and exploration activities, in line with our strategy of increasing our focus on oil drilling.

        Our cash flow used in financing activities decreased by $213 million for the six months ended June 30, 2014, compared to the same period of 2013, reflecting lower excess cash flow distributed to Occidental.

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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 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 expenditures in 2013 by approximately $660 million primarily due to approximately 20% lower drilling costs and lower capital needs for the Elk Hills Cryogenic gas plant, which was completed during 2012. Further, our 2013 acquisitions of $50 million were approximately $380 million lower than the 2012 acquisition amount.

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

Year Ended December 31, 2012 vs. 2011

        Our operating cash flows in 2012 decreased by approximately $230 million compared to 2011. The decrease reflected $240 million of higher operating expenses in 2012, lower revenues of approximately $225 million from lower gas and NGLs prices and $15 million of higher other costs, offset by higher revenues of approximately $325 million due to increased oil volumes, $40 million of higher NGLs volumes and lower tax payments of $205 million. Additionally, working capital changes used an additional $320 million in 2012 compared to 2011.

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

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

Acquisitions

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

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

        During the year ended December 31, 2011, we acquired approximately $1.4 billion of various oil and gas assets. We paid $720 million for producing and non-producing assets within the San Joaquin basin. We

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also acquired producing and non-producing assets in the Los Angeles Basin for $330 million and certain assets in the Sacramento basin for $190 million.

2014 Capital Expenditures

        We have a 2014 capital budget of $2.1 billion for projects targeting investments in the San Joaquin, Los Angeles and Ventura basins, as compared to $1.7 billion in 2013. We allocated approximately $340 million of our 2014 capital budget to primary recovery projects, approximately $790 million to waterfloods and approximately $340 million to steamfloods. Approximately $545 million of our 2014 capital budget will be deployed to develop resources from unconventional plays. Virtually all of our 2014 capital budget will be directed towards oil-weighted production consistent with 2013. In addition, we expect to continue an active exploration program in California and have allocated approximately $95 million of the 2014 capital budget for exploration spending. Assuming current market conditions and drilling success rates comparable to our historical performance, we expect to fund our entire 2014 capital program with cash flow from our operations.

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."

Contractual Obligations

        The table below summarizes and cross-references our contractual obligations. This summary indicates on- and off-balance-sheet obligations as of December 31, 2013. There were no material changes to the amounts between December 31, 2013 and June 30, 2014.

 
  Payments Due by Year  
Contractual Obligations(a)
  Total   2014   2015 and 2016   2017 and 2018   2019 and thereafter  
 
  (in millions)
 

On-Balance Sheet

                               

Long-term liabilities(b)

  $ 117   $   $ 7   $ 8   $ 102  

Off-Balance Sheet

                               

Operating leases

    33     9     11     9     4  

Purchase obligations(c)

    653     247     123     260     23  
                       

Total

  $ 803   $ 256   $ 141   $ 277   $ 129  
                       
                       

(a)
Includes contractual obligations entered into by us or our subsidiaries or by an Occidental subsidiary on behalf of us or our subsidiaries (which obligation will be assumed by us as of our separation from Occidental).

(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 drilling rigs and services. Long-term purchase contracts are discounted using our estimated borrowing rate.

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Lawsuits, Claims and Contingencies

        In the normal course of business, we or certain of our subsidiaries are involved in lawsuits, claims and other contingencies that seek, among other things, compensation for alleged personal injury, breach of contract, property damage or other losses, punitive damages, civil penalties, or injunctive or declaratory relief. We accrue reserves for currently outstanding lawsuits, claims and proceedings when it is probable that a liability has been incurred and the liability can be reasonably estimated. Reserve balances at June 30, 2014 and December 31, 2013 and 2012 were not material to our balance sheets. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on the balance sheet would not be material to our financial position or results of operations.

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

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.

    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.

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

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

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

        The most significant ongoing financial statement effect from a change in our oil and gas reserves or impairment of our proved properties would be to the DD&A rate. For example, a 5% increase or decrease in the amount of oil and gas reserves would change the DD&A rate by approximately $1.15 per Bbl, which would increase or decrease pre-tax income by approximately $65 million annually based on production rates for the year ended December 31, 2013.

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

        We perform impairment tests on our infrastructure assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management's plans change with respect to those assets.

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    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 risk-adjusted discount rate.

    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 and Contingencies" for additional information.

Significant Accounting and Disclosure Changes

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

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

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Qualitative and Quantitative Disclosures about Market Risk

Commodity Price Risk

    General

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

    Cash-Flow Hedges

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

Credit Risk

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

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

Concentration of Credit Risk

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

Interest Rate Risk

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

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BUSINESS

Our Company and Vision

        Following the spin-off from Occidental, we will be an independent oil and natural gas exploration and production company focused on high-growth, high-return conventional and unconventional assets, which are conducted exclusively in California. California is one of the most prolific oil and natural gas producing regions in the world and is the third largest oil producing state in the nation. It has five of the 12 largest fields in the lower 48 states based on estimated proved reserves as of 2009, and our portfolio includes interests in four of these fields. We are the largest producer in California on a gross operated basis and we believe we have established the largest privately-held mineral acreage position in the state, consisting of approximately 2.3 million net acres spanning the state's four major oil and gas basins. We have developed a sizable inventory of over 17,500 identified drilling locations and, as an independent company, we intend to exploit our significant portfolio of conventional and unconventional opportunities to generate double-digit production growth over the longer-term. We produced approximately 154,000 Boe/d net in 2013 and, as of December 31, 2013, we had proved reserves of 744 MMBoe, with approximately 69% proved developed and 72% proved oil reserves and an aggregate PV-10 value of $14.0 billion. For an explanation of the non-GAAP financial measure PV-10 and a reconciliation of PV-10 to Standardized Measure, the most directly comparable GAAP financial measure, see "Summary—Summary Combined Historical Operating and Reserve Data—Non-GAAP Financial Measure and Reconciliations."

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

        We believe that over the last several decades the oil and gas industry has focused significantly less effort on utilizing modern development and exploration processes and technologies in California relative to other prolific U.S. basins. We believe this is largely due to other oil companies' limited capital spending in California, focus on shallow zone thermal projects or investments in other assets in their global portfolios. As an independent company focused exclusively on California, we expect to drive strong production growth through increased application of modern technologies and increased capital spending on development of the significant potential in our portfolio.

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

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

        We also have a large portfolio of lower-risk, high-growth conventional opportunities in each of California's four major oil and gas basins with approximately 71% of our proved reserves associated with conventional opportunities. Conventional reservoirs are capable of natural flow. We have a proven track record of successful exploration and development using primary, waterflood and steamflood recovery methods. In 2014, we anticipate that approximately 70% of our capital expenditures will target conventional development, primarily low-risk waterflood and steamflood projects that we expect to generate significant near-term production and cash flow growth. For example, our Lost Hills and Kern Front steamflood projects and our Huntington field waterflood project are expected to deliver combined production growth of over 35% compounded annually through 2016 from their combined 2013 production of 15,000 Boe/d.

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

 
   
   
   
   
   
   
   
   
  2014
Projected
Development
Drilling
Capital
($MM)(3)
 
 
  Acreage
(in millions)
   
   
   
  Identified
Drilling
Locations(1)
  2014
Projected
Gross
Development
Wells(2)
 
 
  Gross
Acreage
Held in
Fee (%)
   
  Average
Working
Interest
(%)
 
 
  Producing
Wells,
gross
 
 
  Gross   Net   Gross   Net  

San Joaquin basin(4)

    1.8     1.5     59 %   5,764     90 %   12,836     11,127     969   $ 942  

Los Angeles basin(5)

    <0.1     <0.1     73 %   1,382     95 %   1,537     1,478     201     384  

Ventura basin

    0.3     0.3     77 %   780     98 %   2,310     1,716     32     56  

Sacramento basin

    0.6     0.5     36 %   729     100 %   1,008     864     3     8  
                                       

Total

    2.7     2.3     56 %   8,655     92 %   17,691     15,185     1,205   $ 1,390  
                                       
                                       

(1)
Our total identified drilling locations include 2,141 gross (2,024 net) locations associated with proved undeveloped reserves as of December 31, 2013 and 2,344 gross (2,251 net) injector well locations associated with our waterflood and steamflood projects. Our total identified drilling locations excludes 6,400 gross (5,300 net) prospective resource drilling locations. Please see "—Our Reserves and Production Information—Determination of Identified Drilling Locations" for more information regarding the processes and criteria through which we identified our drilling locations. Of our total identified drilling locations, we believe approximately 75% are attributable to acreage owned or held by production.

(2)
Includes 207 injection wells expected to be drilled in connection with our waterflood and steamflood projects.

(3)
Includes drilling and completion expenditures of $173 million associated with injection wells. Our 2014 capital budget of $2.1 billion also includes spending on support equipment, facilities, workovers and exploration.

(4)
Excluding Elk Hills, our average working interest in the San Joaquin basin is 97%.

(5)
We currently hold approximately 27,173 gross (20,817 net) acres in the Los Angeles basin. Our Los Angeles basin operations are concentrated with pad drilling.

        We currently have 26 drilling rigs employed in California with 17 drilling in the San Joaquin basin, 8 in the Los Angeles basin, and 1 rig in the Ventura basin. During the first half of the year, we drilled over 700 gross development wells with roughly 583 in San Joaquin basin, 114 in the Los Angeles basin, 11 in Ventura basin and 3 in Sacramento basin. We expect our pace of drilling to improve slightly in the second half of the year as we receive additional permits and will add an additional rig in the San Joaquin basin during the 3 rd  quarter.

        In 2013, oil represented 58% of our net production. We expect the percentage of oil production to continue to increase over time and favorably impact our overall margins as we anticipate directing virtually all of our capital expenditures towards oil-weighted opportunities in 2014 and beyond to the extent the current oil to gas price relationship continues. Approximately 42% of our 2013 production was generated from our growth-oriented fields through a combination of unconventional and conventional primary, waterflood and steamflood projects with attractive returns. The remaining 58% was generated by our world-class Elk Hills and Wilmington fields, each of which is ranked in the top 20 onshore fields in the

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lower 48 states based on 2009 proved reserves. Over the last three years, we grew our total production 6% on a compound annual basis, from 138 MBoe/d in 2011 to 154 MBoe/d in 2013, while the proportionate share of liquids production grew from 69% to 71%. We intend to accelerate our production growth by significantly increasing our capital investments and focusing on higher-growth opportunities in our extensive drilling inventory. Our 2014 capital budget of $2.1 billion represents an increase of approximately 26% over the $1.7 billion we spent in 2013. After the spin-off, we intend to reinvest substantially all of our operating cash flow in our capital program for the foreseeable future as we will no longer be required to distribute cash to Occidental. We expect to increase our production by 6-9% on a compound annual basis in 2015 and 2016 with a 15% compound annual increase in our oil production for the same period. Over 90% of our expected production for this period is from currently producing fields where we have existing or permitted capacity in our production facilities.

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

        The table below summarizes our proved reserves as of December 31, 2013, and production for the six months ended June 30, 2014 in each of California's four major oil and gas basins.

 
   
   
   
   
   
   
  Average Net Daily
Production for
the six
months ended
June 30, 2014
   
 
 
  Proved Reserves as of December 31, 2013    
 
 
  Oil
(MMBbl)
  NGLs
(MMBbl)
  Natural
Gas
(Bcf)
  Total
(MMBoe)
   
  Proved
Developed
(%)
  R/P Ratio
(Years)(1)
 
 
  Oil (%)   (MBoe/d)   Oil (%)  

San Joaquin basin

    331     68     669     511     65 %   68 %   109     57 %   12.9  

Los Angeles basin

    156         17     159     98 %   70 %   28     100 %   15.5  

Ventura basin

    45     4     35     55     82 %   64 %   9     67 %   16.4  

Sacramento basin

            117     19     %   100 %   9     %   6.4  
                                       

Total operations

    532     72     838     744     72 %   69 %   155     62 %   13.2  
                                       
                                       

(1)
Calculated as total proved reserves as of December 31, 2013 divided by annualized Average Net Daily Production for the six months ended June 30, 2014.

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. It has five of the 12 largest fields in the lower 48 states based on proved reserves as of 2009, and our portfolio includes interests in four of these fields. California is also the nation's largest state economy, with significant energy demands that exceed local supply. California imports approximately 62% of its oil, mostly from foreign locations, and 90% of its natural gas. Because of limited crude transportation infrastructure from other parts of the country to California, the California market is generally isolated from the rest of the nation, which allows California producers to typically receive a premium to WTI-based prices. Our operations span the four major oil and gas basins in California and include 130 fields with 8,655 gross active wellbores as of December 31, 2013. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.3 million net acres, and the largest land owner in each of the states' four major oil and gas basins. Approximately 60% of our total mineral interest position is held in fee. A majority of our interests are in producing properties located in reservoirs characterized by what we believe to be long-lived production profiles with repeatable development opportunities. These reservoirs generally have been developed over a long period of time, typically decades. Observing the performance of these fields over many years has helped us develop a greater understanding of production and reservoir characteristics and, we believe, makes our future performance more predictable.

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GRAPHIC


*
Production is for the six months ended June 30, 2014. Proved reserves are as of December 31, 2013. Our total gross identified drilling locations are as of December 31, 2013. Please see "—Our Reserves and Production Information—Determination of Identified Drilling Locations" for more information regarding the processes and criteria through which we identified all of our drilling locations.

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

San Joaquin Basin

        Approximately 69% of our estimated proved reserves as of December 31, 2013 and approximately 70% of our average daily net production for the six months ended June 30, 2014 were located in the San Joaquin basin. We actively operate and develop 42 fields in this basin consisting of conventional primary, IOR, EOR and unconventional project types. We currently hold approximately 1.5 million net acres in the San Joaquin basin, approximately 63% of which we hold in fee.

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

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

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

    Elk Hills

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

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

Los Angeles Basin

        Approximately 21% of our estimated proved reserves as of December 31, 2013 and approximately 18% of our average daily net production for the six months ended June 30, 2014 were located in the Los Angeles basin. We actively operate and develop 10 fields in this urban, coastal basin consisting of conventional primary, IOR, EOR and unconventional project types. We have a leading acreage position within the Los Angeles basin and over 50% of the basin's production comes from the fields we operate. We currently hold 27,173 gross (20,817 net) acres in the Los Angeles basin.

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

    Wilmington Oil Field

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

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Ventura Basin

        Approximately 7% of our estimated proved reserves as of December 31, 2013 and approximately 6% of our average daily net production for the six months ended June 30, 2014 were located in the Ventura basin. We actively operate and develop 25 fields (nearly 40% of the fields) in this basin consisting of conventional primary, IOR, EOR and unconventional project types. We currently hold approximately 0.3 million net acres in the Ventura basin, approximately 83% of which we hold in fee.

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

        The first fields discovered in the Ventura basin were near the Ojai field in the town of Santa Paula in 1861. Since then, approximately 100 oil and gas fields have been discovered. Multiple source rocks are present with Miocene-age (Monterey and Rincon formations) and Eocene-age (Anita and Cozy Dell formations) sediments. Complex stratigraphy and structural geology enhance the exploration potential in the basin. Only limited use of modern drilling and completion techniques and limited seismic surveys have occurred since the late 1960s, with virtually no exploration drilling. In 2013, we completed the acquisition of, and are currently processing, the first ever 3D seismic survey in the Ventura basin. We believe this 3D seismic data gives us a competitive advantage in exploring this basin.

Sacramento Basin

        Approximately 3% of our estimated proved reserves as of December 31, 2013 and approximately 6% of our average daily net production for the six months ended June 30, 2014 were located in the Sacramento basin. We actively operate and develop 53 fields in this basin primarily consisting of dry gas production. We currently hold approximately 0.5 million net acres in the Sacramento basin, approximately 36% of which we hold in fee. We believe our significant acreage position in the Sacramento basin gives us the option for future development and rapid production growth in an attractive gas price environment. We produced approximately 84% of the produced gas in the Sacramento basin during 2013.

        The Sacramento basin is a deep, elongated northwest-trending basin located in northern California covering around 12,000 square miles and forming the northern part of California's Central Valley. It contains a thick sequence of sedimentary rocks that range in age from lower Cretaceous to Neogene sediments in an area that is approximately 200 miles long and 45 miles wide. Producing reservoirs range from upper Cretaceous-age to Pliocene-age. The main reservoirs are the Cretaceous Starkey, Winters, Forbes, Kione, and the Eocene Domengine sands. Exploration in the basin started in 1918 and was focused on seeps and topographic highs. In the 1970s, the use of multifold 2D seismic led to large discoveries in the basin. The acquisition of 3D seismic surveys in the mid-1990s helped define trapping mechanisms and reservoir geometries. The Sacramento basin has been extensively explored for petroleum resources, and more than 10 Tcf of natural gas have been produced.

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

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

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

GRAPHIC

Our Business Strategy

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

    Accelerate development of high-growth unconventional drilling opportunities.   Over the longer term, we expect substantial production growth to come from unconventional reservoirs such as tight sandstones and shales. We hold mineral interests in approximately 1.1 million net acres with unconventional potential and have identified 4,682 drilling locations on this acreage. As a result of our increased focus on these reservoirs over the past few years, more than one-third of our production now comes from unconventional assets, an increase of approximately 160% since the acquisition of our Elk Hills field properties in 1998. As of December 31, 2013, we had proved reserves of 217 MMBoe associated with our unconventional properties, of which approximately 30% was proved undeveloped. We have been building a growing technical understanding of these reservoirs through our successful development of portions of our acreage. For example, we have developed seven discrete, productive intervals within the Monterey formation, primarily within the upper Monterey, with a nearly 100% commercial success rate on our development wells. We are now applying the knowledge acquired from these successes to operations in other unconventional

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      reservoirs, such as the Kreyenhagen and Moreno shale formations, which we believe offer significant development opportunities due to similar reservoir characteristics with multiple potentially productive zones in each well bore.

    Drive significant production growth from high-return, low-risk conventional assets.   In the near term, we intend to increase our capital spending and generate significant production and cash flow growth from proven IOR methods, such as waterflooding, and EOR methods, such as steamflooding. The oil and gas industry has observed that primary recovery methods typically produce less than 10% of the oil volume initially in place and that subsequent waterfloods and steamfloods typically increase recovery to a range of 20% to 60%. Our Lost Hills and Kern Front steamflood projects and our Huntington field waterflood project are expected to deliver combined production growth of over 35% compounded annually through 2016 and together account for approximately 60% of our projected 6-9% annual production growth through 2016. We believe these projects are substantially derisked as they are currently producing and we have existing or permitted capacity in our production facilities sufficient to develop these projects through 2016. We have significant additional low-risk conventional opportunities like these with over 13,009 identified drilling locations, 52% of which are associated with IOR and EOR projects. The remaining 48% are associated with primary recovery methods, many of which we expect will develop into IOR and EOR projects in the future.

    Aggressively apply modern technologies to enhance production growth.   Over the last several decades, the oil and gas industry has focused significantly less effort on utilizing modern development and exploration processes and technologies in California relative to other prolific U.S. basins. We believe this is largely due to other oil companies' limited capital spending in California, focus on shallow zone thermal projects or investments in other assets within their global portfolios. As an independent company focused exclusively on California, we intend to make significant use of modern technologies in drilling and completing wells, which we expect will substantially increase both our cost-efficiency and production growth over time. We are well positioned to execute on this strategy as we have developed an extensive 3D seismic library, which covers over 4,250 square miles, representing approximately 90% of the 3D seismic data available for California, and have tested and successfully implemented various exploration, drilling, completion and IOR and EOR technologies in the state. As a result of our long, successful operating history, our geographically broad exploration drilling programs and exceptional 3D seismic library, we believe we have developed a leading understanding of the geology, petroleum systems and hydrocarbon potential in the basins in which we operate. Our unique and proprietary stratigraphic and structural models of the subsurface geology allow us to recognize new development and exploration areas in each of our basins, and identify the applicable modern drilling and completion technologies needed to enhance recoveries and returns. For example, we recently applied rigorous seismic, stratigraphic and reservoir analyses to discover unconventional resources in a new field in the Monterey zone in the San Joaquin basin. This area was previously tested from the 1940s to the 1970s with six wells drilled by major oil companies, but hydrocarbon resources were not recognized until our 2012 discovery, following our seismic evaluation and application of our unique and proprietary subsurface models. We have already increased production five-fold to over 1,400 Bbls/d from first quarter production in 2012 and have identified an additional 150 drilling locations in the field.

    Generate strong cash flows through a focus on high-margin crude oil in order to internally fund our capital budget . We intend to focus on increasing cost-efficiency and developing profitable opportunities in our portfolio in order to achieve self-funded growth in any foreseeable market or regulatory environment. We intend to reinvest substantially all of our operating cash flow in our capital program for the foreseeable future as we will no longer be required to distribute cash to Occidental. In 2013, we generated cash flow from operations of approximately $763 million after capital spending of approximately $1.7 billion. We believe we will continue to generate a substantial

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      amount of free cash flow in 2014 after planned capital spending of $2.1 billion. Almost all our 2014 capital budget will be focused on oil producing projects and we expect this emphasis to continue in a high oil price environment. As of December 31, 2013, crude oil represented 72% and 58%, respectively, of our total reserves and production which positions us well to grow our oil production. In addition, we believe we have significant potential upside in a more favorable natural gas price environment, particularly with respect to our Sacramento basin acreage, where we had identified 1,008 gross (864 net) drilling locations as of December 31, 2013. Given our large acreage position and drilling inventory across both oil and natural gas opportunities, we expect to generate strong production and cash flow growth in different commodity price environments.

      We sell all of our crude oil into the California refining markets at prices we believe are among the most favorable in the United States. California refiners typically purchase crude oil at international waterborne-based prices at a premium to WTI-based prices. For example, our 2013 realized price averaged across all grades of crude oil reflected a 6% premium to WTI index prices. We believe that the limited crude transportation infrastructure from other parts of the country to California will allow us to continue to realize strong cash margins as a result. The figure below shows our operating cash margin per Boe for 2013 of approximately $50/Bbl or 65% of our average realized price.


GRAPHIC


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

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

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

Our Competitive Strengths

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

    Largest acreage position in a world-class oil province.   California is one of the most prolific oil and natural gas producing regions in the world and is the third largest oil producing state in the nation. It has five of the top 12 largest fields in the lower 48 states based on estimated proved reserves as of 2009, and our portfolio includes interests in four of these fields. We believe we are the largest private oil and natural gas mineral acreage holder in California, with interests in approximately 2.3 million net acres that contain attractive conventional and unconventional drilling opportunities using primary, IOR and EOR methods. Our large and diverse acreage position, approximately 60% of which we hold in fee, allows us to prioritize projects by value and risk to achieve strong returns and maintain strong reserve replacement and production growth rather than drill simply to hold leases. A significant percentage of our opportunities are oil-weighted, with approximately 90% of our identified drilling locations associated with oil production. For the year ended December 31, 2013, we were the largest producer in the state on a combined gross operated basis with approximately 188,000 Boe/d of production, 59% of which was oil. As of December 31, 2013, we had total combined reserves of over 744 MMBoe, of which approximately 72% was oil and 81% was liquids.

    Significant growth potential from opportunity-rich drilling portfolio.   Our drilling inventory at December 31, 2013 consisted of 17,691 identified well locations, including 4,682 gross (4,264 net) unconventional drilling locations and 13,009 gross (10,921 net) conventional drilling locations. We

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      believe we can achieve significant production growth through the development of unconventional reservoirs. Over the last five years, we have drilled and completed over 570 unconventional development wells, primarily in the upper Monterey formation, with an almost 100% commercial success rate. Our successful unconventional drilling program has demonstrated the productive potential of seven stacked pay zones within the Monterey formation, primarily within the upper Monterey, and we believe that these successes are repeatable in other formations such as the Kreyenhagen formation, which has similar geologic attributes. We also have a large inventory of conventional development opportunities that will provide low-risk, near-term production growth with attractive returns. We believe that a significant portion of our production growth over the next two to three years will be driven by IOR and EOR projects, many of which are already being implemented. Over 90% of our expected 6-9% production growth through 2016 is expected to come from currently producing fields. As we develop our sizable inventory of drilling locations, the majority of which are vertical drilling locations with thousands of feet of stacked pay, and utilize horizontal drilling techniques, we expect that we will achieve double-digit production growth over the longer term.

    Unique ability to drive high returns and growth in different commodity price environments.   Our current drilling inventory comprises a diversified portfolio of oil and natural gas locations, which allows us to target drilling projects that are the most economically compelling depending on the prevailing commodity price outlook. Approximately 90% of our drilling inventory is associated with oil-rich projects, primarily located in the San Joaquin, Los Angeles and Ventura basins, and the remaining inventory is associated with natural gas properties in the Sacramento, San Joaquin and Ventura basins. We have operating control over 97% of our properties, enabling us to determine all aspects of our development program, including the selection of specific drilling locations, the timing of the development and the drilling and completion techniques used. Our retention of operating control coupled with our diversified portfolio provides us with the flexibility to invest our capital in the highest return projects and control operating costs to drive strong production and cash flow growth in different commodity price environments as well as to adapt to any changes in regulatory and market conditions. Approximately 26% of our production for the six months ended June 30, 2014 was natural gas. If conditions change and gas prices become more favorable, we believe that we have the ability to significantly increase our gas production within a few years through accelerated capital investment in gas projects currently in our portfolio. In addition to our drilling opportunities, we have made significant investments in infrastructure, including our state-of-the-art Elk Hills cryogenic gas plant and our 550 megawatt Elk Hills power plant, which increase our operational flexibility and ability to maximize returns in any commodity price environment.

    Strong free cash flow and premium margins driven by deficit California energy market.   We sell almost all of our crude oil into the California refining markets at prices we believe are among the most favorable in the United States. California, the largest state economy in the United States, imports approximately 62% of its oil and approximately 90% of its natural gas. Oil is imported via rail or supertanker. As a result, California refiners have typically purchased crude oil at international waterborne-based prices that exceed WTI-based prices for comparable grades. Our 2013 realized price averaged across all grades of crude oil reflected a 6% premium to WTI index prices. We believe that the limited crude transportation infrastructure from other parts of the country to California will allow us to continue to realize strong cash margins. In addition, we own the fee minerals on approximately 60% of our acreage position. The returns on developed mineral fee acreage are greatly enhanced because we do not pay royalties and other lease payments. We expect the resulting substantial operating cash flow to fund our growth while allowing us to maintain ample liquidity.

    Proven management and technical teams with extensive experience operating in California.   Our experienced management team and technical staff have a proven track record of applying the leading technologies and operating methods to develop our assets. The members of our

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      management and technical teams have an average of over    years' experience in the oil and natural gas industry, with an average of    years focused on California oil and gas operations. We believe this focused experience gives us an inherent competitive advantage. As a result of our long operating history in the state, our team of geoscientists and engineers has developed a growing understanding of the geology and can quickly identify and apply suitable recovery methods, as well as drilling, completion and other relevant technologies, to increase production and reserves. For example, our technical team has extensive experience developing unconventional opportunities and growing large, world-class fields, such as Elk Hills and Wilmington. Our cumulative production and year end proven reserves from these fields are twice the proved reserves originally purchased and we continue to find additional reserves in these fields. In addition, production from unconventional reservoirs within these fields now account for over 50% of our 2013 daily combined production for these fields. We are applying the expertise gained through re-developing Elk Hills and Wilmington to many of the other fields we operate. In addition, we believe that our team has established a favorable reputation among regulators and other stakeholders for our commitment to safety and demonstrated sensitivity to the environment. We believe that our favorable record and reputation with communities and regulators sustains our operations, and gives us an important advantage when we seek to acquire and develop opportunities throughout California.

Portfolio Management and 2014 Capital Budget

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

        We have a 2014 capital expenditure budget of $2.1 billion for projects targeting investments in the San Joaquin, Los Angeles and Ventura basins, as compared to $1.7 billion in 2013. Virtually all of our 2014 capital budget is being directed towards oil-weighted production consistent with 2013. Of the total 2014 capital budget, approximately $1.4 billion is allocated to well drilling and completions, $200 million to workovers, $180 million to surface support equipment to handle higher production, $100 million to additional steam generation capacity expansion, $95 million to exploration and the rest to maintenance capital, HES projects and other items. As a result of recent investments in infrastructure, we do not anticipate any substantial spending on new infrastructure during the next several years. We believe the absence of such significant expenditures should support strong cash flows. The table below sets forth the expected allocation of our 2014 capital expenditure budget as compared to the allocation of our 2013 capital expenditures and actual 2014 capital expenditures through June 30, 2014.

 
  2014 Capital
Expenditures through
June 30, 2014
  Total 2014 Capital
Expenditure Budget
  2013 Capital
Expenditures
 
 
  (in millions)
 

Conventional:

                   

Primary recovery

  $ 157   $ 342   $ 266  

Waterfloods

    298     787     480  

Steamfloods

    219     343     375  
               

Total conventional

    674     1,472     1,121  
               

Unconventional

    272     543     457  

Exploration

    57     95     91  
               

Total

  $ 1,003   $ 2,110   $ 1,669  
               
               

        Assuming current market conditions and a drilling success rate comparable to our historical performance, we believe we will be able to fund our entire 2014 capital program with our cash flow from

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operations. We have a significant inventory of high-quality drilling locations to support higher spending. We expect our 2015 capital budget to increase further from 2014 levels to a range of $2.3 billion to $2.5 billion as we reinvest substantially all of our increased cash flow in our capital program.

Conventional Reservoir Recovery Methods

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

Primary Recovery

        Primary recovery methods are the first techniques we use to develop a reservoir. These methods consist of drilling and producing wells without supplementing the natural reservoir energy. Our successful exploration program continues to provide us with primary recovery opportunities in new reservoirs or through extensions of existing fields. In 2013, 22% of our production came from primary production in conventional reservoirs. We continued to expand our conventional primary recovery programs in 2013, and with our 2014 development plans, we expect this growth pattern to continue. We are planning to drill 113 wells in 2014 that will be produced using conventional primary recovery methods. Our conventional development programs set up future opportunities to convert these reservoirs to waterfloods or steamfloods after their primary production phase.

Waterfloods

        Waterflooding works by repressurizing a reservoir through water injection and displacing or "sweeping" oil to producing wellbores. Waterfloods are low-cost operations with attractive margins and returns in the current price environment. These operations typically have low and predictable production declines and allow us to extend the productive life of a reservoir and significantly increase our incremental recovery after primary depletion. We use waterfloods extensively in the San Joaquin, Los Angeles and Ventura basins where they have allowed us to reduce production decline or modestly grow our production from mature fields such as Elk Hills and Wilmington. Since 2011, we have achieved 32% production growth from waterflood projects and we expect this growth pattern to continue. We spent $480 million on waterfloods in 2013, drilling 196 wells including 146 producing wells. We plan to increase our capital spending on waterfloods in 2014 by 64% to $787 million and to drill 309 wells.

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

    Long Beach Unit

        Upon acquiring the right to serve as operating contractor to the City of Long Beach in April 2000, we implemented a development drilling program to expand operations in this mature reservoir. Since April 2000, we have drilled 434 oil producing wells and 200 water injecting wells at a cost of $930 million. An additional $193 million was invested in facilities repairs and upgrades to support incremental production and injection. Our cumulative production and year end proved reserves from the unit is over twice the proved reserves originally purchased and we continue to find additional reserves. As of December 31, 2013, we have identified over 500 development drilling locations.

    Tidelands

        Recognizing the success of our Long Beach Unit waterflood efforts, we executed new contracts with the State of California and City of Long Beach to facilitate the development of Tidelands properties.

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These agreements are similar to our contractual arrangement in the Long Beach Unit and support development drilling in this mature property. In the ten years preceding execution of these new contracts, drilling on the Tidelands properties was limited to replacing failed wells or relocating wells to accommodate projects of the Port of Long Beach. As a result of executing these new contractual arrangements, we began development drilling on the Tidelands property in January 2011. Since January 2011, we have drilled 125 oil production wells and 50 water injection wells at a cost of $254 million. An additional $102 million was invested in facilities repairs and upgrades to support incremental production and injection. Tidelands gross oil production has increased by more than 50% from 6,400 Bbls/d in January 2010 to 9,800 Bbls/d today. As of December 31, 2013, over 400 development drilling projects have been identified to further develop the Tidelands waterflood.

Steamfloods

        Steamfloods work by lowering the viscosity of the oil, causing it to flow more easily to wells. Our steamflood properties have seen some of the highest growth in our portfolio over the last year. We have steamflood projects in the San Joaquin and Ventura basins where we produce heavy oil, primarily in Kern County and in fields such as Kern Front and Lost Hills with demonstrated steamflood results. We have gradually increased our capital allocated to steamfloods over the years and expect to continue doing so for as long as the current oil versus gas price spread continues. Our steamfloods are highly profitable in this price environment, allowing us to use inexpensive gas to generate steam, which is then injected into the reservoir to produce oil. Full development of these steamfloods is a multi-year endeavor that involves upfront infrastructure construction for steam and water processing facilities and follow-on development drilling. These steam projects are generally shallower in depth (300-2,500 ft) than our other programs and the wells are relatively inexpensive to drill. Therefore, we can normally implement a drilling program quickly with attractive rates of return. We spent $375 million on steamfloods in 2013, drilling 387 wells, including 304 producing wells. We expect our total capital spending on steamfloods for 2014 to be slightly lower than 2013, although our total drilling capital expenditures are expected to be slightly higher in 2014, with 614 wells expected to be drilled in 2014 as compared to 387 wells in 2013. In 2013, our total production from steamfloods was 25,000 Boe/d gross and we injected an average of 95,000 BS/d gross in our operated fields. We expect to nearly triple our 2013 injection rate by around 2020. We have already made significant infrastructure investments to support the bulk of this planned expansion.

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

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 1.1 million net acres with unconventional potential and have identified 4,682 gross (4,264 net) unconventional drilling locations on this acreage. Over the last five years, we have drilled and completed over 570 unconventional development wells, primarily in the upper Monterey formation, with a nearly 100% commercial success rate. As a result of focusing more on these reservoirs over the past few years, approximately 39% of our 2013 production was from unconventional reservoirs, an increase of approximately 160% since the acquisition of our Elk

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Hills field properties in 1998. As of December 31, 2013, we had proved reserves of 217 MMBoe associated with our unconventional properties, with approximately 30% proved undeveloped.

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

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

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

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

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

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

Play
  Depth
(ft)
  Thickness
(gross ft)
  Porosity
(%)
  Permeability
(mD)
  Total Organic
Carbon
(%)
  Thermal
Maturity
(%Ro)
 

Upper Monterey(1)

    3,500' - 12,000'     250' - 3,500'     5 - 30     <0.0001 - 2     1 - 12     0.7 - 1.0  

Lower Monterey(1)

    9,000' - 16,000'     200' - 500'     5 - 12     <0.001 - 0.05     2 - 18     0.8 - 1.0  

Kreyenhagen(1)

    8,000' - 16,000'     200' - 350'     5 - 15     <0.001 - 0.1     1 - 6     0.7 - 1.2  

Moreno(1)

    8,000' - 16,000'     200' - 300'     5 - 10     <0.001 - 0.1     2 - 6     0.7 - 1.3  

Bakken

    3,000' - 11,000'     6' - 145'     2 - 12     0.05     8 - 21     <1  

Barnett

    5,400' - 9,500'     100' - 500'     4.0 - 9.6     <0.0001 - 0.1     4 - 8     0.8 - 2.0  

Eagle Ford

    5,000' - 12,000'     100' - 250'     3.4 - 14.6     0.13     2 - 9     1.0 - 1.45  

(1)
Reservoir characteristics were internally generated based on regional 2D seismic data, 3D seismic data, open hole and mud log data, cores and other reservoir engineering data.

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        While we have not yet developed sufficient information to reliably predict success rates across our entire portfolio, our continued investment in unconventional projects is allowing us to develop a pattern of success across these different reservoirs in addition to improving our overall cycle time from project identification to development. As a result of our increased understanding of these reservoirs, we believe we will be able to better direct our capital to higher success projects allowing us to strategically increase our investment levels on unconventional drilling. We expanded our unconventional programs in 2013, and plan to continue this expansion by drilling 150 wells in 2014, all of which will target oil. With continued successful development and expansion, we believe that the unconventional production from these assets will become a significant portion of our production.

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

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

        In 2014, we expect to spend approximately 5% of our total capital, or $95 million, on exploration projects with a continued focus on prospects that can generate near-term returns. Slightly more than half of this amount will target unconventional reservoirs. We expect exploration capital in the future to be focused in the San Joaquin, Ventura and Sacramento basins, and weighted toward programs where we have a proven track record of success. In addition, our program also includes exploration prospects in several high-potential resource plays, where we are the largest holder of unconventional acreage in the state. Success in these plays could generate significant longer-term production growth. We currently expect the portion of our exploration budget targeting such projects to increase following the spin-off.

Our Infrastructure

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

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

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

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

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

Marketing Arrangements

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

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

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

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

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

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

Our Principal Customers

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

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

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 2013 disclosures, the calculated average WTI oil price was $96.94 per Bbl. The calculated average NYMEX gas price for 2013 disclosures was $3.65 per MMBtu. The realized prices used for the 2013 disclosures were $102.67 per Bbl for oil $50.53 per Bbl for NGLs and $3.84 per Mcf for natural gas.

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

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

 
  At December 31, 2013  
 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  

Proved developed reserves:

                               

Oil (MMBbl)

    225     109     29         363  

NGLs (MMBbl)

    47         2         49  

Natural Gas (Bcf)

    459     11     25     116     611  
                       

Total (MMBoe)(1)(2)

    349     111     35     19     514  
                       
                       

Proved undeveloped reserves:

                               

Oil (MMBbl)

    106     47     16         169  

NGLs (MMBbl)

    21         2         23  

Natural Gas (Bcf)

    210     6     10     1     227  
                       

Total (MMBoe)(2)

    162     48     20         230  
                       
                       

Total proved reserves:

                               

Oil (MMBbl)

    331     156     45         532  

NGLs (MMBbl)

    68         4         72  

Natural Gas (Bcf)

    669     17     35     117     838  
                       

Total (MMBoe)(2)

    511     159     55     19     744  
                       
                       

(1)
Approximately 11% of proved developed oil reserves, 2% of proved developed NGLs reserves, 8% of proved developed natural gas reserves and 9% of total proved developed reserves are non-producing.

(2)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per Bbl and $3.66 per Mcf, respectively, resulting in an oil-to-gas ratio of over 25 to 1.

PV-10 and Standardized Measure

 
  At December 31,
2013
 

PV-10 of proved reserves (in millions)(1)

  $ 14,018  

Standardized measure (in millions)

  $ 9,223  

(1)
PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future income. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an asset value measure to compare against our past reserve bases and the reserve bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the taxpaying status of the entity.

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Proved Reserve Additions

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

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  

Improved recovery:

                               

Oil (MMBbl)

    49     24     3         76  

NGLs (MMBbl)

    4                 4  

Natural Gas (Bcf)

    47     3     2         52  
                       

Total (MMBoe)

    61     25     3         89  
                       
                       

Extensions and discoveries:

                               

Oil (MMBbl)

                     

NGLs (MMBbl)

                     

Natural Gas (Bcf)

                     
                       

Total (MMBoe)

                     
                       
                       

Revisions of previous estimates:

                               

Oil (MMBbl)

    (8 )   3     (3 )       (8 )

NGLs (MMBbl)

    13                 13  

Natural Gas (Bcf)

    (4 )   (4 )   (1 )   (38 )   (47 )
                       

Total (MMBoe)

    4     2     (3 )   (6 )   (3 )
                       
                       

Total proved reserve additions:

                               

Oil (MMBbl)

    41     27             68  

NGLs (MMBbl)

    17                 17  

Natural Gas (Bcf)

    43     (1 )   1     (38 )   5  
                       

Total (MMBoe)

    65     27         (6 )   86  
                       
                       

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

    Improved Recovery

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

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    Revisions of Previous Estimates

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

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

Proved Undeveloped Reserves

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

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

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  

Improved recovery:

                               

Oil (MMBbl)

    40     20     3         63  

NGLs (MMBbl)

    3                 3  

Natural Gas (Bcf)

    35     2     1         38  
                       

Total (MMBoe)

    49     20     3         72  
                       
                       

Extensions and discoveries:

                               

Oil (MMBbl)

                     

NGLs (MMBbl)

                     

Natural Gas (Bcf)

                     
                       

Total (MMBoe)

                     
                       
                       

Revisions of previous estimates:

                               

Oil (MMBbl)

    (1 )   (2 )   (1 )       (4 )

NGLs (MMBbl)

    4                 4  

Natural Gas (Bcf)

    (15 )           (21 )   (36 )
                       

Total (MMBoe)

        (2 )   (1 )   (3 )   (6 )
                       
                       

Transfers to proved developed reserves:

                               

Oil (MMBbl)

    (24 )   (7 )   (3 )       (34 )

NGLs (MMBbl)

    (3 )               (3 )

Natural Gas (Bcf)

    (30 )   (1 )   (2 )   (4 )   (37 )
                       

Total (MMBoe)

    (32 )   (7 )   (3 )   (1 )   (43 )
                       
                       

Proved undeveloped reserve additions, net of transfers:

                               

Oil (MMBbl)

    15     11     (1 )       25  

NGLs (MMBbl)

    4                 4  

Natural Gas (Bcf)

    (10 )   1     (1 )   (25 )   (35 )
                       

Total (MMBoe)

    17     11     (1 )   (4 )   23  
                       
                       

Reserves Evaluation and Review Process

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

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

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

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

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

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

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

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

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Determination of Identified Drilling Locations

    Proven Drilling Locations

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

    Unproven Drilling Locations

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

    Exploration Drilling Locations

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

    Prospective Resource Drilling Locations

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

    Well Spacing Determination

        Our well spacing determinations in the above categories of identified well locations are based on actual operational spacing within our existing producing fields, which we believe are reasonable for the particular recovery process employed (i.e., primary, waterflood, EOR). Due to the significant vertical thickness and multiple stacked reservoirs usually encountered by our drilling wells, typical well spacing is

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generally less than 20 acres and often 10 acres or less in the majority of our fields unless specified differently above. These parameters also meet the general well spacing restrictions imposed on certain oil and gas fields in California.

    Drilling Schedule

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

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

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

 
  Proven Drilling Locations   Total Identified Drilling Locations  
 
  Oil and
Natural Gas Wells
  Injection Wells   Oil and
Natural Gas Wells
  Injection Wells  

San Joaquin Basin

                         

Primary Conventional

    156         3,760      

Waterflood

    117     59     930     675  

Steamflood

    758     222     2,212     612  

Unconventional

    276         4,324     323  
                   

San Joaquin Basin subtotal

    1,307     281     11,226     1,610  
                   

Los Angeles Basin

                         

Primary Conventional

            37      

Waterflood

    287     132     1,000     500  

Steamflood

                 

Unconventional

                 
                   

Los Angeles Basin subtotal

    287     132     1,037     500  
                   

Ventura Basin

                         

Primary Conventional

    43         1,650      

Waterflood

    36     38     201     234  

Steamflood

    14         190      

Unconventional

    2         35      
                   

Ventura Basin subtotal

    95     38     2,076     234  
                   

Sacramento Basin

                         

Primary Conventional

    1         1,008      
                   

Sacramento Basin subtotal

    1         1,008      
                   

Total Identified Drilling Locations

    1,690     451     15,347     2,344  
                   
                   

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Production, Price and Cost History

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

        The following table sets forth information regarding production, realized and benchmark prices, and production costs for the years ended December 31, 2013, 2012 and 2011 and for the six months ended June 30, 2014 and 2013. For additional information on price calculations, see information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations."

 
  Six Months Ended
June 30,
  Year Ended December 31,  
 
  2014   2013   2013   2012   2011  

Production Data(a):

                               

Oil (MBbl/d)

    96     88     90     88     80  

NGLs (MBbl/d)

    18     20     20     17     15  

Natural gas (MMcf/d)

    243     262     260     256     260  

Average daily combined production (MBoe/d)(b)

    155     152     154     148     138  

Total combined production (MMBoe)(b)

    28     28     56     54     50  

Average realized prices(a):

   
 
   
 
   
 
   
 
   
 
 

Oil (per Bbl)

  $ 103.43   $ 105.21   $ 104.16   $ 104.02   $ 103.80  

NGLs (per Bbl)

  $ 54.86   $ 47.90   $ 50.43   $ 52.76   $ 70.03  

Natural gas (per Mcf)

  $ 4.67   $ 3.82   $ 3.73   $ 2.94   $ 4.31  

Average Benchmark prices:

   
 
   
 
   
 
   
 
   
 
 

WTI oil ($/Bbl)

  $ 100.84   $ 94.30   $ 97.97   $ 94.21   $ 95.12  

NYMEX gas ($/Mcf)

  $ 4.60   $ 3.68   $ 3.66   $ 2.81   $ 4.11  

Average costs per Boe:

   
 
   
 
   
 
   
 
   
 
 

Production costs(a)

  $ 20.59   $ 19.12   $ 18.99   $ 24.34   $ 21.30  

Other operating expenses

  $ 4.80   $ 4.15   $ 4.38   $ 4.04   $ 3.89  

Depreciation, depletion and amortization

  $ 20.73   $ 20.47   $ 20.38   $ 17.15   $ 13.38  

Taxes other than on income

  $ 3.80   $ 3.97   $ 3.29   $ 3.09   $ 2.84  

(a)
The following table sets forth information regarding production, realized prices, and production costs for our Elk Hills and Wilmington fields for the years ended December 31, 2013, 2012 and 2011.

   
  Elk Hills   Wilmington  
   
  2013   2012   2011   2013   2012   2011  
 

Production data:

                                     
 

Oil (MBbl/d)

    26     29     30     22     21     19  
 

NGLs (MBbl/d)

    18     15     14              
 

Natural gas (MMcf/d)

    145     168     174              
 

Average realized prices:

                                     
 

Oil (MBbl/d)

  $ 106.32   $ 101.19   $ 101.10   $ 103.29   $ 102.15   $ 102.37  
 

NGLs (MBbl/d)

  $ 49.62   $ 53.19   $ 69.67   $   $   $  
 

Natural gas (MMcf/d)

  $ 3.67   $ 2.86   $ 4.39   $   $   $  
 

Production costs per Boe:

  $ 12.34   $ 16.46   $ 12.14   $ 31.56   $ 35.13   $ 35.76  

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(b)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per Bbl and $3.66 per Mcf, respectively, resulting in an oil-to-gas ratio of over 25 to 1.

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

 
   
   
  Average Net Daily
Production(MBoe/d)
 
 
  Total Proved
Reserves (MMBoe)
  Oil (%)   Year Ended
December 31, 2013
  Six Months
Ended
June 30, 2014
 

San Joaquin basin

                         

Primary Conventional

    68     57 %   16     17  

Waterflood

    53     80 %   8     7  

Steamflood

    176     100 %   25     29  

Unconventional

    214     35 %   59     56  
                   

San Joaquin basin subtotal

    511     65 %   108     109  
                   

Los Angeles basin

                         

Primary Conventional

        %   1     1  

Waterflood

    159     98 %   25     27  

Steamflood

        %        

Unconventional

        %        
                   

Los Angeles basin subtotal

    159     98 %   26     28  
                   

Ventura basin

                         

Primary Conventional

    25     81 %   6     6  

Waterflood

    26     88 %   2     2  

Steamflood

    2     100 %        

Unconventional

    2     67 %   1     1  
                   

Ventura basin subtotal

    55     82 %   9     9  
                   

Sacramento basin

                         

Primary Conventional

    19     %   11     9  
                   

Sacramento basin subtotal

    19     %   11     9  
                   

Total

    744     72 %   154     155  
                   
                   

Productive Wells

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

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

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  

Oil

                                                             

Gross(a)(b)

    9,353     (1,066 )   1,562     (56 )   1,684     (32 )           12,599     (1,154 )

Net(a)(c)

    8,237     (833 )   1,459     (51 )   1,622     (31 )           11,318     (915 )

Gas

                                                             

Gross(a)(b)

    382     (104 )   8                 1,053     (52 )   1,443     (156 )

Net(a)(c)

    333     (87 )   8                 937     (46 )   1,278     (133 )

(a)
Numbers in parentheses indicate the number of wells with multiple completions.

(b)
The total number of wells in which interests are owned.

(c)
The sum of fractional interests.

Acreage

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

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  
 
  (in thousands)
 

Developed(1)

                               

Gross(2)

    409     11     63     268     751  

Net(3)

    375     11     60     246     692  

Undeveloped(4)

                               

Gross(2)

    1,383     16     234     365     1,998  

Net(3)

    1,110     10     196     288     1,604  

(1)
Acres spaced or assigned to productive wells.

(2)
Total acres in which we hold an interest.

(3)
Sum of fractional interests owned based on working interests or interests under arrangements similar to production-sharing contracts.

(4)
Acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether the acreage contains proved reserves.

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

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Participation in Exploratory and Development Wells Being Drilled

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

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  

Exploratory and development wells

                               

Gross

    23     10             33  

Net

    21     9             30  

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

Drilling Activity

        The following table describes our drilling activity for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Net wells represent the sum of fractional interests in wells in which we own an interest.

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  

2013

                               

Oil

                               

Exploratory

    2.0                 2.0  

Development

    543.1     125.7     18.8         687.6  

Natural Gas

                               

Exploratory

                     

Development

                7.7     7.7  

Dry

                               

Exploratory

    5.0         1.0     1.0     7.0  

Development

    2.5     0.9             3.4  

2012

                               

Oil

                               

Exploratory

    8.0         2.0         10.0  

Development

    485.7     121.4     63.9         671.0  

Natural Gas

                               

Exploratory

    1.0                 1.0  

Development

    2.5             3.0     5.5  

Dry

                               

Exploratory

    11.0                 11.0  

Development

    4.0                 4.0  

2011

                               

Oil

                               

Exploratory

    7.0         1.0         8.0  

Development

    472.2     68.8     43.3         584.3  

Natural Gas

                               

Exploratory

                     

Development

                4.0     4.0  

Dry

                               

Exploratory

    10.3                 10.3  

Development

                     

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        Since December 31, 2013, we have drilled 711 gross (644 net) wells, 436 of which were completed as producing wells and 118 of which are in various stages of completion.

Delivery Commitments

        We have made commitments to certain refineries and other buyers to deliver oil, natural gas and NGLs. In certain cases, an Occidental subsidiary entered into the commitment on our behalf and to the extent it exists as of the spin-off we will assume the commitment as of our separation from Occidental. As of December 31, 2013, the total amount contracted to be delivered is approximately 36 MBbls/d of oil under 60-day contracts, 3 Bcf of natural gas through 2014 and 1 MMBbl of NGLs through 2014. As of June 30, 2014, the total amount contracted to be delivered is approximately 36 MBbls/d of oil under 60-day contracts, 2 Bcf of natural gas through 2015 and 8 MMBbls of NGLs through 2015. The price for these deliveries is set at the time of delivery of the product at benchmark prices. We have significantly more production capacity than the amounts committed and have the ability to secure additional volumes in case of a shortfall. None of the commitments in any given year is expected to have a material impact on our financial statements.

Title to Properties

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

Competition

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

Regulation of the Oil and Natural Gas Industry

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

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Regulation of Environmental, Safety and Health Matters

    General

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

    require various permits and approvals before drilling, workovers, production, underground fluid injection, or solid and hazardous waste disposal commences, or before facilities are constructed or put into operation;

    require the installation of sophisticated safety and pollution control equipment;

    restrict the types, quantities, and concentration of various materials, including, without limitation, oil, natural gas and water, that can be released or discharged into the environment in connection with drilling, production, processing or transportation activities;

    limit or prohibit operations on lands lying within coastal, wilderness, wetlands, endangered species habitat, and other protected areas;

    establish standards for the closure, abandonment, cleanup or restoration of former operations, such as plugging of abandoned wells;

    impose substantial liabilities for unauthorized releases or discharges of regulated materials into the environment;

    require comprehensive environmental analyses, recordkeeping and reports with respect to operations affecting federal, state, and private lands or leases;

    may expose us to litigation by governmental authorities, special interest groups and other claimants; and

    may restrict the rate of oil, NGLs and natural gas production below the rate that would otherwise be possible.

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

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    Air Emissions

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

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

    Water Discharges

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

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

    Hazardous Substances and Wastes

        CERCLA, or "Superfund", imposes joint and several liability, without regard to fault, for the release of a "hazardous substance" into the environment, on responsible persons including the current and past owners or operators of the site where the release occurred, and companies that disposed or arranged for the transport or disposal of the hazardous substance. Under CERCLA and analogous California laws,

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responsible persons may be liable for cleanup costs, natural resource damages, and the costs of certain health studies. In addition, third parties may file claims for personal injury, property damage and other losses allegedly caused by the hazardous substances released into the environment. Although petroleum and crude oil fractions are not considered hazardous substances, in the course of our operations, we may use materials that, if released, may be treated as hazardous substances under CERCLA. Thus, governmental agencies or third parties may seek to hold us responsible for all or part of the costs to clean up sites at which such hazardous substances have been deposited.

        RCRA and analogous California laws regulate the generation, transportation, treatment, storage, disposal, and cleanup of "hazardous wastes" and the disposal of non-hazardous wastes. Drilling fluids, produced waters, and other wastes associated with the exploration or production of crude oil, natural gas, or geothermal energy constitute "solid wastes," which are subject to less stringent provisions than hazardous wastes. RCRA and California law also regulate Naturally Occurring Radioactive Materials ("NORM") generated in operations. Legislation or regulations have been proposed that could reclassify certain oil and natural gas exploration and production wastes as hazardous wastes, which would subject the reclassified wastes to more stringent handling, disposal and cleanup requirements. Such legislation, if enacted, could affect our operating costs.

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

    Regulation of Well Completion and Stimulation

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

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

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

        In April 2014, a California Senate committee proposed legislation that would have indefinitely banned hydraulic fracturing and other stimulation activity until the state examined potential environmental effects. Although the California Senate did not adopt the committee's proposal, similar legislation may be considered in the future. In addition, some local governments have proposed or adopted ordinances within their jurisdictions that purport to regulate drilling activities in general, or stimulation and completion activities in particular, or to ban such activities outright. None of the adopted local ordinances is expected to materially impact our current or expected future operations. If new or more stringent federal, state, or local restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs, experience delays or curtailment of our exploration or production activities and potentially be precluded from drilling wells.

    Safe Drinking Water Act and Underground Injection Control Program

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

    Environmental Impact Analysis

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

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

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defense costs. The CEQA process may impose additional delays and expense on the process of obtaining new permits and permit renewals.

    Endangered Species Act and Migratory Bird Treaty Act

        Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the federal Endangered Species Act ("ESA"), the California ESA ("CESA"), the Migratory Bird Treaty Act ("MBTA"), and the CWA. The U.S. Fish and Wildlife Service and the California Department of Fish and Game may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands and could delay or prohibit oil and gas development. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds, we believe that we are in substantial compliance with the ESA, CESA, MBTA and similar statutes, and we are not aware of any proposed species listings that will materially affect our operations. However, there could be new designations of previously unidentified endangered or threatened species, or critical or suitable habitat that would affect our operations.

    Abandonment, Decommissioning and Remediation Requirements

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

    Climate Change Legislation and Greenhouse Gas Regulations

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

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

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

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modifications to, our operations. Federal and California subsidies and tax incentives for the development and construction of alternative energy-fueled power generation and transportation also may reduce demand for our products and services.

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

    Worker Safety

        The federal OSHA and analogous California laws regulate the protection of the safety and health of workers. The California Department of Industrial Relations' Division of Occupational Safety and Health ("Cal/OSHA") requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees, state and local government authorities, and the public. Cal/OSHA has adopted and enforces Petroleum Safety Orders that require safety programs, and protective measures in our operations. Failure to comply with Cal/OSHA requirements can lead to the imposition of administrative, civil and/or criminal penalties as well as injunctive relief.

Regulation of Transportation and Sales of Natural Gas

    Regulations affecting sales

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

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

    Market manipulation and market transparency regulations

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

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

    Gathering regulations

        Section 1(b) of the federal Natural Gas Act ("NGA") exempts natural gas gathering facilities from the jurisdiction of the FERC. We own certain natural gas pipelines that we believe meet the traditional tests that FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, ongoing litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts, or Congress.

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

    Regulation of power sales and transmission

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

Regulation of Pipeline Safety and Maintenance

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

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commercially navigable waterways. In addition, PHMSA has authorized the California State Fire Marshal and California Public Utilities Commission to enforce federal intrastate pipeline regulations and inspection requirements in California.

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

Employees

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

Legal Proceedings

        We are party to various legal proceedings and claims in the ordinary course of our business. One of our subsidiaries has settled a previously disclosed matter with the California Air Resources Board regarding reporting and emissions from four pieces of equipment at its facility in Long Beach, California by paying a penalty of approximately $254,000 in the second quarter of 2014 without admitting liability.

        Two of our subsidiaries have reached a settlement in principle with the Regional Water Quality Control Board for the Central Valley Region of a claim the Board asserted in the second quarter of 2014 regarding the past use of certain drilling sumps in Kern County, California. Once the settlement is finalized, our subsidiaries would pay a cash penalty totaling approximately $239,000, and pay the same amount to fund a non-profit organization's community water center as a supplemental environmental project. We believe the other various legal proceedings and claims we are subject to in the ordinary course of our business will not have a material adverse effect on our consolidated or combined financial position, results of operations or liquidity.

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MANAGEMENT

Executive Officers

        The following table sets forth information, as of August 20, 2014, regarding the individuals who are expected to serve as our executive officers following the distribution. Additional individuals will be appointed prior to the distribution, and we will include information concerning those individuals in an amendment to this information statement. After the distribution, none of our executive officers will continue to be employees of Occidental.

Name
  Position(s) with CRC   Age  
William E. Albrecht   Executive Chairman of the Board     62  
Todd A. Stevens   President and Chief Executive Officer     47  
Marshall D. "Mark" Smith   Senior Executive Vice President and Chief Financial Officer     54  
Robert A. Barnes   Executive Vice President—Northern Operations     57  
Frank E. Komin   Executive Vice President—Southern Operations     59  

         William E. Albrecht was appointed as Executive Chairman of the Board of CRC in July 2014. Mr. Albrecht served as Vice President of Occidental from May 2008 to July 2014 and as President, Oxy Oil & Gas, Americas from January 2012 to July 2014. Mr. Albrecht also served as President—Oxy Oil & Gas, USA from April 2008 to January 2012. During his tenure with Occidental, Mr. Albrecht has had managerial oversight over our upstream assets. Mr. Albrecht has more than 35 years of experience in the domestic oil and gas industry, having previously served as an executive officer for domestic energy producer EOG Resources, and as a petroleum engineer for Tenneco Oil Company. Mr. Albrecht holds a Master of Science degree from the University of Southern California and a Bachelor of Science degree from the United States Military Academy. Mr. Albrecht's extensive managerial and operational experience in the upstream domestic energy business and his specific knowledge of our assets and proactive engagement with regulatory agencies, communities, and other stakeholders make him a valuable member of our Board of Directors.

         Todd A. Stevens was appointed President, Chief Executive Officer and Director of CRC in July 2014. Mr. Stevens served as Vice President—Acquisitions and Corporate Finance of Occidental from October 2004 to August 2012, as Vice President—California Operations, Oxy Oil & Gas from April 2008 to September 2012, and as Vice President—Corporate Development of Occidental Petroleum Corporation from August 2012 to July 2014. Mr. Stevens holds a Master of Business Administration degree from the University of Southern California and a Bachelor of Science degree from the United States Military Academy. Our Board of Directors will benefit from Mr. Stevens' deep knowledge of the oil and gas industry, his expertise in strategically evaluating and valuing oil and gas assets, and his significant managerial experience as an executive at Occidental, including his extensive experience in allocating capital, managing Occidental's and our assets and dealing with California's regulatory environment, agencies and political regime.

         Marshall D. "Mark" Smith was appointed Senior Executive Vice President and Chief Financial Officer of CRC in July 2014. Mr. Smith served as Senior Vice President of Ultra Petroleum Corp. from January 2011 to July 2014 and served as its Chief Financial Officer from July 2005 to July 2014. Mr. Smith has over 32 years of progressive experience in a multitude of disciplines within the energy industry including operations, strategic planning, corporate finance and business development. Early in his career, Mr. Smith served as a practicing petroleum engineer for both major and independent oil companies and later focused his career on mergers, acquisitions and corporate finance advisory assignments in the energy sector. From 2001 to 2002, Mr. Smith served as the Chief Financial Officer at Gulf Liquids, Inc. Mr. Smith was the Vice

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President of Business Development at J.M. Huber Energy from 2002 to 2004. From 2004 until joining Ultra Petroleum Corp. in July 2005, Mr. Smith served as Vice President of Upstream Business Development at Constellation Energy. Mr. Smith holds a Masters of Business Administration degree with highest honors from Oklahoma City University and a Bachelors of Science degree from the University of Oklahoma.

         Robert A. Barnes was appointed Executive Vice President—Northern Operations of CRC in July 2014. Mr. Barnes served as President and General Manager of Occidental of Elk Hills from December 2012 to July 2014. He served as Operations Manager for Oxy Permian CO 2 from May 2011 to November 2012, as Deputy General Manager and Senior Vice President, Operations, of Occidental Argentina from June 2010 to April 2011, and as Vice President, Operations, of Occidental Argentina from August 2007 to June 2010. Mr. Barnes also held Production Operations Manager and Operations Team Leader roles at Occidental of Elk Hills from 1998 to 2007, and worked as Production Superintendent in the Hugoton and Virginia Coalbed Methane Operations and held various roles in Operations and Drilling Engineering throughout the Rocky Mountains, California and Mid-Continent regions since joining Occidental in 1978. Mr. Barnes has over 36 years of oil and gas industry experience and holds a Bachelor of Business Administration degree from New Mexico State University.

         Frank E. Komin was appointed Executive Vice President—Southern Operations of CRC in July 2014. Mr. Komin served as President and General Manager of OXY Long Beach from January 2010 to July 2014, and served as President and General Manager of Oxy THUMS from February 2001 to December 2009. During his tenure at OXY Long Beach, Mr. Komin oversaw all aspects of Long Beach operations and the development of the Wilmington field. Mr. Komin has more than 36 years of experience in the domestic oil and gas industry. Before joining Oxy THUMS in 2000 as Manager, Production & Development, Mr. Komin worked for 22 years at ARCO as Reservoir Engineering Manager and Operations Superintendent, Kuparuk, Alaska from 1993 to 1997, as Asset Manager in Midland-Permian Basin, from 1988 to 1993, District Coordinator in Dallas, Texas, from 1987 to 1988, and in various engineering and engineering leadership roles from 1978 to 1987. Mr. Komin holds a Bachelor of Science degree from the University of Kansas.

Board of Directors

        We currently expect that, upon completion of the separation, our board of directors will consist of      members, a majority of whom we expect to satisfy the independence standards established by the Sarbanes-Oxley Act of 2002 and the applicable rules of the SEC and the NYSE. The following table sets forth information, as of August 20, 2014, regarding the individuals who are expected to serve on our board of directors following the distribution. Additional individuals will be appointed prior to the distribution, and we will include information concerning those individuals in an amendment to this information statement.

Name
  Age
William E. Albrecht   62
Todd A. Stevens   47

Board Committees

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

    Audit Committee

        Our audit committee will be composed of at least one director and a majority of independent directors. The Audit Committee will meet separately with representatives of our independent auditors, our internal audit personnel and representatives of senior management in performing its functions. The Audit Committee will approve the services of the independent auditors and review the general scope of audit

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coverage, matters relating to internal controls systems and other matters related to accounting and reporting functions. The board of directors is expected to determine that all of the members of the Audit Committee are financially literate and have accounting or related financial management expertise, each as required by the applicable NYSE listing standards. The board of directors is also expected to determine that at least one member of the Audit Committee will qualify as audit committee financial experts under the applicable rules of the Exchange Act.

    Compensation Committee

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

    Nominating and Corporate Governance Committee

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

        The phase-in rules of the NYSE permit our Audit Committee to have at least one independent committee member as of the date our common stock is first listed on the NYSE, a majority of independent members within 90 days after the effectiveness of our registration statement and all independent members within one year after the effectiveness of our registration statement; these phase-in rules further permit the Audit Committee to have at least two members within 90 days after the date our common stock is first listed on the NYSE and three members within one year after the date our common stock is first listed on the NYSE. With respect to our Compensation Committee and the Nominating and Corporate Governance Committee, the phase-in rules of the NYSE permit each of these committees to have one independent member as of the distribution date, a majority of independent members within 90 days after the distribution date and all independent members within one year after the distribution date.

Director Independence

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

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

Corporate Governance Policies

        Our board of directors will adopt corporate governance policies to help ensure that the board of directors has the necessary authority and practices in place to make decisions that are independent from management, that the board of directors adequately performs its function as the overseer of management

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and to help ensure that the interests of the board of directors and management are aligned with the interests of the stockholders.

Corporate Business Ethics and Corporate Policies

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

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

Compensation Committee Interlocks and Insider Participation

        During the fiscal year ended December 31, 2013 and the six months ended June 30, 2014, the California business was operated by subsidiaries of Occidental and not through an independent company and therefore did not have a compensation committee or any other committee serving a similar function. Decisions as to the compensation of those who will serve as our executive officers will be made initially by Occidental. See "Executive Compensation—Compensation Discussion and Analysis" included elsewhere in this information statement.

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EXECUTIVE COMPENSATION

        For purposes of the following Compensation Discussion and Analysis and Executive Compensation disclosures, the five persons who we expect will be our named executive officers following the spin-off are:

Name
  Most Recent Position at Occidental   Position at CRC
Todd A. Stevens   Vice President—Corporate Development   President and Chief Executive Officer

William E. Albrecht

 

Vice President of Occidental Petroleum Corporation and President, Oxy Oil & Gas, Americas

 

Executive Chairman of the Board

Marshall (Mark) Smith

 

n/a

 

Senior Executive Vice President and Chief Financial Officer

Robert A. Barnes

 

President and General Manager of Occidental of Elk Hills

 

Executive Vice President—Northern Operations

Frank E. Komin

 

President and General Manager of Oxy Long Beach

 

Executive Vice President—Southern Operations

        For purposes of the Compensation Discussion and Analysis, we refer to Messrs. Albrecht, Stevens, Smith, Barnes and Komin collectively as our "named executive officers." With the exception of Mr. Smith, all of our expected named executive officers have been employed by Occidental or its subsidiaries; therefore, the compensation information provided for 2013 will reflect compensation earned at Occidental or its subsidiaries and the design and objectives of the executive compensation programs in place prior to the spin-off.

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


COMPENSATION DISCUSSION AND ANALYSIS

Introduction

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

        This Compensation Discussion and Analysis has three main parts:

    Occidental 2013 Executive Compensation —This section describes and analyzes the executive compensation programs at Occidental in 2013 (beginning on page 126).

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    Effects of Spin-Off on Outstanding Executive and Other Compensation Arrangements —This section discusses Occidental's current expectations as to the effect of the spin-off on outstanding Occidental compensation awards that may be held by CRC's named executive officers upon the spin-off (beginning on page 134).

    Anticipated Post-Spin-off Compensation Programs —This section discusses our anticipated executive compensation programs from and after the spin-off (beginning on page 135).


Occidental 2013 Executive Compensation

Occidental 2013 Compensation Program

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

Occidental Peer Companies

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

    Alternative investment choices in the energy sector, including level of investment analyst coverage;

    Competitors for projects and acquisitions worldwide;

    Competitors for employees worldwide;

    Percentages of total proved reserves and total production attributable to oil and to natural gas;

    Oil and gas production and reserves;

    Total revenue and the percentage derived from upstream (exploration and production) activities; and

    Market capitalization.

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

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

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

Anadarko Petroleum Corporation   Devon Energy Corporation
Apache Corporation   EOG Resources, Inc.
Canadian Natural Resources Limited   ExxonMobil Corporation
Chevron Corporation   Hess Corporation
ConocoPhillips   Marathon Oil Corporation
    Total S.A.

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

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

Elements of the Occidental Program

Occidental Salary and Other Annual Compensation.

        The Occidental Compensation Committee believes that overall executive compensation should include elements that reward executives for consistent performance of basic job requirements and achievement of certain short-term goals which, over time, contribute to long-term growth of stockholder value. Consistent with the Occidental Compensation Committee's goal of emphasizing long-term compensation, salary and other annual compensation generally represent the smaller portion of the 2013 compensation packages of Occidental's executive officers. Short-term compensation for Occidental's executive officers generally includes base salary and other compensation, plus an award under Occidental's Executive Incentive Compensation Plan. Certain other compensation and benefits that apply to senior executives of Occidental are described under "Other Occidental Compensation and Benefits" beginning on page 132.

Occidental Executive Incentive Compensation Plan Award (Annual Incentive).

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

        Occidental Non-Equity Incentive Award (Performance-Based Portion).     The Non-Equity Incentive portion (60% of target value) is a performance-based cash award that is based on Occidental's performance during the year as measured against Occidental's targets established in the first quarter of the year. For purposes of the Performance-Based Portion of the Annual Incentive, Core, Occidental's Basic Earnings Per Share ("EPS") is computed by excluding the "Significant Items Affecting Earnings" from Occidental's Net

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

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

    Organizational development;

    Succession planning;

    Governance and ethical conduct;

    Functional and operating accomplishments;

    Health, environment and safety responsibilities; and

    Encouragement of diversity.

Occidental Long-Term Compensation.

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

    Alignment of executive and stockholder interests in achieving long-term growth in stockholder value,

    Ensuring that maximum payouts are made only for exceptional performance,

    Consistency with the compensation programs of peer companies, and

    Allocation of total compensation between long-term and short-term components.

This portion of the executive compensation program includes three types of awards: (i) an incentive based on either return on capital employed ("ROCE") (for executives with primarily corporate level

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responsibilities) or two return on asset ("ROA") awards (one for the oil & gas division as a whole and the other for the regional oil & gas division for which the executive is responsible); (ii) performance incentives based on TSR; and (iii) performance-based restricted stock incentives ("RSI"). The Occidental Compensation Committee awarded long-term incentives to Occidental's named executive officers in the following percentages: 40% to either one ROCE award or to two ROA awards, 30% to the TSR award and 30% to the RSI award.

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


Summary of Long-Term Incentive Compensation

Compensation Component
  Return on Capital
Employed Award
  Return on
Assets Awards
  Total Shareholder
Return Award(6)
  Restricted
Stock Award

PERFORMANCE PERIOD

  3 Years(2)   3 Years(2)   3 Years   3 - 7 Years(7)

FORM OF PAYOUT

 

Stock

 

Stock

 

Stock

 

Stock

PERFORMANCE BASIS

 

Return on Capital Employed(3)

 

Return on Assets for Oil and Gas segment as a whole (ROA-Total), or for the Americas region (ROA-Americas)(6)

 

TSR ranking within peer group, TSR being positive or negative, and TSR of S&P 500 Index

 

Cumulative Net Income

PAYOUT RANGE

 

 

 

 

 

 

 

 

Minimum Payout(1)

  0%   0%   0%   0%

Performance Resulting in Minimum Payout

  ROCE < 9%(4)   ROA-Total < 9%(4)
ROA-Americas < 8%(4)
  TSR ranking of 25 th  percentile or less   Cumulative Net Income < $12 billion(7)

Target Payout(1)

  100%   100%   100%   100%

Performance Required for Target Payout

  ROCE = 12%(4)   ROA-Total = 13%(4)
ROA-Americas = 12%(4)
  TSR performance two-thirds of the way between the 25 th  percentile TSR (0% payout) and the 75 th  percentile TSR (150% payout)(6)   Cumulative Net Income ³ $12 billion(7)

Maximum Payout(1)

  200%   200%   150%   100%

Performance Required for Maximum Payout

  ROCE ³ 18%(4)   ROA-Total  ³ 20%(4)
ROA-Americas  ³ 18%(4)
  TSR ranking of 75th percentile or greater, TSR is positive and exceeds S&P 500 TSR   Cumulative Net Income ³ $12 billion(7)

ADJUSTMENTS

 

The ROCE and all ROA thresholds would have been adjusted up or down by 2% if the three-year average forward strip West Texas Intermediate crude oil (WTI) prices as of December 31, 2013, were at least $10 greater or less than, respectively, the three-year average forward strip WTI prices as of June 30, 2013, but actual WTI prices resulted in no adjustments. All thresholds will be further adjusted up or down by 2% at the end of the performance period if actual average WTI prices over the performance period are at least $10 greater or less than, respectively, the three-year average forward strip WTI prices as of December 31, 2013.

HOLDING PERIOD

 

For all awards, a number of shares equal to 50% of net after-tax shares received are required to be retained for three years after vesting.

TAX DEDUCTIBILITY

 

All awards are intended to satisfy the tax deductibility requirements of Section 162(m) of the Internal Revenue Code.


(1)
Percent of grant for TSR award, RSI award, ROCE award and all ROA awards.

(2)
Three-year performance period begins January 1, 2014 and ends December 31, 2016.

(3)
ROCE shall be the percentage obtained by dividing (i) the sum of annual net income attributable to common stock for Occidental, after adding back after-tax interest expense, for each year in the performance period, as reported in Occidental's Form 10-K by (ii) the sum of the average capital employed (long-term debt plus stockholders' equity) for each year in the performance period, as reported in Occidental's Form 10-K.

(4)
See Adjustments row in chart for threshold adjustments.

(5)
ROA shall be the percentage obtained by dividing (i) the sum of the Net Income for the Oil and Gas Segment (Total or Americas) for each year in the performance period by (ii) the sum of the Assets for the Oil and Gas Segment (Total or Americas) for each year in the performance period. For the purposes of the foregoing calculation, "Net Income" shall be Results of Operations for the Oil and Gas Segment (Total or Americas) for the applicable year and "Assets" will be the Net Capitalized Costs (Total or Americas) for the applicable year, in each case as reported in the Supplemental Oil and Gas Information contained in Occidental's Annual Report on Form 10-K. For the purpose of the foregoing sentence, "Assets" will reflect all acquisitions, divestures and write downs during the performance period unless the senior management of Occidental recommends exclusion and the Occidental Compensation Committee agrees.

(6)
Payout percent for the TSR award is determined by performance compared to the peer group and is linearly interpolated between 25 th  percentile and 75 th  percentile TSR values.

(7)
The shares become non-forfeitable on the later of June 30, 2016, through which date the executive must remain employed by the company, and the date the Occidental Compensation Committee certifies the achievement of the Cumulative Net Income threshold. If the threshold is not met by June 30, 2020, the shares are forfeited entirely.

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        Occidental Return on Capital Employed Incentive Award.     This award is a new award implemented in 2013 to ensure a high level of executive focus on the key objective of ensuring efficient use of capital. This award is denominated in performance shares, each of which is equal to one share of Occidental's common stock. Key terms of the award are set forth in the table on page 129. At the end of the performance period, dividend equivalents will be paid with respect to the performance share level achieved in an amount equal to the dividends declared per share of Occidental common stock during the performance period. As described below, in connection with the spin-off, we expect that any of these awards that are held by our named executive officers will be converted into restricted shares of our common stock subject to such performance-based vesting requirements as determined by the Occidental Compensation Committee and time-based vesting conditions.

        Occidental Return on Assets Incentive Awards.     These new awards were implemented in 2013 to reward operating unit executives for performance within their direct areas of responsibility and influence. These awards are denominated in performance shares, each of which is equal to one share of Occidental common stock. Key terms of the awards are set forth in the table on page 129. At the end of the performance period, dividend equivalents will be paid with respect to the performance share level achieved in an amount equal to the dividends declared per share of Occidental common stock during the performance period. As described below, in connection with the spin-off, we expect that any of these awards that are held by our named executive officers will be converted into restricted shares of our common stock subject to such performance-based vesting requirements as determined by the Occidental Compensation Committee and time-based vesting conditions.

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

    Reward higher returns in Occidental's stock relative to the peer group stockholder returns, based on a percentile ranking of the TSR within the peer group. This approach neutralizes major market variables that impact the entire oil and gas industry, thereby rewarding executives for superior performance compared to peer group companies.

    Align executive rewards with stockholder returns over a three-year period, which encourages executive focus on long-term returns.

    Ensure above-target payouts occur only if Occidental's TSR is positive and exceeds the TSR of the S&P 500 Index.

The TSR awards are denominated in performance share units, each of which is equivalent to one share of Occidental common stock. The percentage of such number of performance share units that will be payable at the end of the three-year performance period, which runs from July 1, 2013 through June 30, 2016, will depend on Occidental's TSR performance as described in the table on page 129. Cumulative dividend equivalents will be paid at the end of the three-year performance period and will be paid only on performance share units earned. As described below, in connection with the spin-off, we expect that any of these awards that are held by our named executive officers will be converted into restricted shares of our common stock subject to such performance-based vesting requirements as determined by the Occidental Compensation Committee and time-based vesting conditions.

        Occidental Restricted Stock Incentive Award.     Consistent with the executive compensation programs of a majority of the peer group companies, the Occidental Compensation Committee selected Restricted Stock Incentive awards (RSI awards) as a component of executive long-term incentive compensation. The

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RSI award is a grant of shares of Occidental's common stock and key terms of the award are set forth in the table on page 129. The Occidental Compensation Committee increased the performance goal from the 2012 level of $10 billion in cumulative net income to $12 billion in cumulative net income in order to make the achievement of the goal more challenging. Dividends will be paid on the shares from the grant date. As described below, in connection with the spin-off, we expect that any of these awards that are held by our named executive officers will be converted into restricted shares of our common stock subject to such performance-based vesting requirements as determined by the Occidental Compensation Committee and time-based vesting conditions.

Participants in the Occidental Executive Compensation Process

Role of Occidental Management in Executive Compensation

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

Role of Occidental's Compensation Consultants

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

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

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

Occidental Risk Management of Compensation Policies and Practices

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

    Program elements that use both annual and longer-term performance periods, with the most substantial portion having terms of at least three years.

    Transparent performance metrics that use absolute and relative measures readily ascertainable from public information.

    Use of external performance metrics, such as TSR, for a significant portion of the long-term performance-based incentive awards.

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    Comparative nature of the TSR performance measure, which neutralizes the potential impact volatile world oil prices could have on Occidental's TSR.

    Use of internal performance metrics, such as ROCE and ROA, that are transparent and publicly disclosed in Occidental's Form 10-K, and reported consistently with the Securities and Exchange Commission rules and regulations and United States Generally Accepted Accounting Principles.

    Adjustment of threshold performance levels for ROCE and ROA awards to moderate the effects of commodity prices on performance levels achieved.

    Payouts of long-term incentive awards that are 100% in stock rather than cash.

    Stringent share ownership guidelines for executives and the additional requirement that Occidental's named executive officers retain a number of shares equal to at least 50% of net after-tax shares acquired through equity awards granted after 2009 for at least three years following vesting of such awards.

    Forfeiture provisions for unvested awards in the event of violations of Occidental's Code of Business Conduct.

Other Occidental Compensation and Benefits

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

Defined Benefit Pension Program

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

Occidental Qualified Defined Contribution Plans

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

Occidental Nonqualified Defined Contribution Retirement Plan

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

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

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

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

Occidental Nonqualified Deferred Compensation Plan

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

Occidental Security

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

Occidental Tax Preparation and Financial Planning

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

Occidental Insurance

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

Individual Retention and Severance Arrangements

        In February 2013, Occidental provided a written arrangement regarding retention payment and separation benefits (the "Retention and Separation Arrangements") in certain circumstances for Messrs. Stevens, Albrecht and Barnes, none of whom has an employment agreement or offer letter that addresses termination payments and benefits. These arrangements replaced any notice and severance pay that they would otherwise have received under the applicable Occidental severance plan.

        Had Messrs. Stevens, Albrecht and Barnes remained employees of Occidental, they would have received a retention payment (the "retention payment") of one to two times their then-current annual base salary, payable in one lump sum cash payment one year after a new Chief Executive Officer of Occidental began employment. As Messrs, Stevens, Albrecht and Barnes will no longer be employed by Occidential following the spin-off, they will not receive the retention payment from Occidental. If they were terminated without cause by Occidental prior to December 31, 2014, subject to providing typical waivers and releases, they would have received (i) separation pay at their then-current base salary for 24 months, payable monthly; (ii) their target annual bonus amount for the year of separation, payable in one lump sum cash payment; (iii) the same medical and other benefits (other than notice and severance pay) as are received

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by employees under Occidental's severance plan; (iv) the retention payment (if not previously paid); and (v), in the case of Messrs. Stevens and Barnes, cash payments in consideration of forfeiture of all of their outstanding long-term incentive awards.


Effects of Spin-off on Outstanding Executive and Other Compensation Arrangements

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

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

Equity-Based and other Long-Term Incentive Awards

        We currently expect that effective as of the spin-off, each Occidental equity-based or other long-term incentive award held by an individual who will be employed by us following the spin-off will be converted into an award with respect to shares of CRC common stock (other than certain phantom unit awards, the treatment of which is still under consideration). Specifically, we currently expect that the following will occur:

    Stock-Based Equity Incentive Awards.   Each equity incentive award with respect to Occidental common stock (other than Occidental restricted shares, which are addressed below) that is held by our employees will be converted upon the spin-off into an award of shares of our restricted common stock, with the number of shares determined based upon the trading price of our common stock following the spin-off and (a) the payout of such incentive award at target performance, in the case of performance cycles with more than one year of performance remaining as of the spin-off, and (b) the payout of such incentive award based upon actual performance, calculated as of a date on or prior to the spin-off (as will be determined by the Occidental Compensation Committee), in the case of performance cycles with less than one year of performance remaining as of the spin-off. Any cash dividend equivalents that have accrued with respect to the equity incentive award held by our employees will be paid upon the spin-off, assuming settlement of such equity incentive award at the same level of performance assumed for purposes of converting the award, as described in the preceding sentence. From and after the spin-off, such restricted shares will be subject to service-based vesting requirements satisfied through continued service with us and our subsidiaries similar to the time-based vesting requirements that were applicable to the corresponding Occidental incentive award and such performance-based vesting requirements, if any, as are determined by the Occidental Compensation Committee. Outstanding long-term incentive units (each representing one share of Occidental common stock) that are held by our employees and that are to be settled 50% in cash and 50% in shares of Occidental common stock, however, will be converted upon the spin-off into long-term incentive units of CRC (each representing one share of our common stock) based upon the trading price of our common stock following the spin-off. Such company incentive units will be subject to service-based vesting requirements satisfied through continued service with us and our subsidiaries similar to the time-based vesting requirements that were applicable to the corresponding Occidental award and will be settled 50% in cash and 50% in shares of our common stock.

    Cash-Based Long-Term Incentive Awards .  Each cash-based long-term incentive award held by our employees will be converted upon the spin-off into an award of shares of our restricted common stock, with the number of shares determined based upon the trading price of our common stock following the spin-off and (a) the payout of such incentive award at target performance, in the case of performance cycles with more than one year of performance remaining as of the spin-off, and

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      (b) the payout of such incentive award based upon actual performance, calculated as of a date on or prior to the spin-off (as will be determined by the Occidental Compensation Committee), in the case of performance cycles with less than one year of performance remaining as of the spin-off. From and after the spin-off, such restricted shares will be subject to service-based vesting requirements satisfied through continued service with us and our subsidiaries similar to the time-based vesting requirements that were applicable to the corresponding Occidental incentive award and such performance-based vesting requirements, if any, as are determined by the Occidental Compensation Committee.

    Restricted Shares .  Each share of restricted Occidental common stock held by our employees will be converted into shares of our restricted common stock, with the number of shares determined based upon the trading price of our common stock following the spin-off. The company restricted common stock will vest generally based upon the same schedule as the prior Occidental restricted share, subject to continued service with us and our subsidiaries, and such performance-based vesting requirements, if any, as are determined by the Occidental Compensation Committee.

Annual Incentive Awards

        In the event the spin-off occurs during 2014, we anticipate that our employees will receive a full 2014 annual incentive plan award under our annual incentive programs.

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

Individual Arrangements

        In connection with the spin-off, we expect to assume all individual compensation arrangements between our named executive officers and Occidental.

Other Compensation Programs

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


Anticipated Post-Spin-off Compensation Programs

        In order to have our executive compensation programs in effect at the time of the spin-off, the Occidental Compensation Committee has approved the initial compensation programs as described below. The Occidental Compensation Committee retained Pay Governance LLC, its independent compensation consultant, to assist in the design and implementation of our compensation programs to be in effect following the spin-off. All executive compensation decisions for our named executive officers prior to the spin-off will be made by Occidental. To the extent such persons are executive officers of Occidental, the decisions will be made by the Occidental Compensation Committee. Executive compensation decisions following the spin-off will be made by our compensation committee.

        In early 2014, Pay Governance LLC assisted in developing a rewards structure for CRC. Specifically, Pay Governance LLC worked with Occidental and us to develop a peer group for purposes of conducting market analyses and to determine the level and form of executive and broad-based compensation after the spin-off.

Compensation Objectives

        Our executive compensation program to be in effect immediately following the spin-off is designed to provide competitive compensation levels generally targeted to market median, with flexibility to pay above

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or below market based on individual factors such as experience, performance, and internal equity. In developing our compensation program, Occidental and we took into account the following:

    Market practices.

    The need for a smooth transition of talent from Occidental to us.

    The need to attract executive talent from outside of Occidental.

    The need to provide CRC with appropriate programs immediately following the spin-off, recognizing that our board of directors (or a committee thereof) and management will be responsible for program design following the spin-off.

        We expect our compensation committee will review the compensation program approved by Occidental post spin-off and make adjustments as it deems appropriate to support our long-term strategic objectives.

Peer Companies

        Since our compensation program was designed based on market practices, Occidental and we worked with Pay Governance LLC to develop a peer group of companies on which to base market practice. Our peer group was developed using a multi-step screening process based on the following criteria:

    Industry—Companies in Global Industry Classification Standard sub-industry of oil and gas exploration and production.

    Scope—Companies in the range of 25% -400% of our expected market capitalization and 40% - 250% of our expected revenue.

    Geography—U.S.-listed companies focused on U.S. exploration and production.

        Based on these screens, the following compensation peer group was developed which includes companies generally similar in operations and scope to CRC, as well as companies that may have some operational or scope differences to CRC, but are in the same industry, and provide a more robust peer group:


Peer Companies

Apache Corporation   Cabot Oil and Gas Corporation
Chesapeake Energy Corporation   Cimarex Energy Co.
Concho Resources Inc.   Continental Resources, Inc.
Denbury Resources Inc.   Devon Energy Corporation
EOG Resources, Inc.   Marathon Oil Corporation
Newfield Exploration Company   Noble Energy, Inc.
Pioneer Natural Resources Company   QEP Resources, Inc.
Range Resources Corporation   Southwestern Energy Company
Whiting Petroleum Corporation   WPX Energy, Inc.

Elements of the Program

        The Occidental Compensation Committee believes that overall executive compensation should include elements that reward executives for consistent performance of basic job requirements and achievement of certain short-term goals which, over time, contribute to long-term growth of stockholder value. With a goal of emphasizing long-term compensation, salary and other annual compensation will represent the smaller portion of the compensation program for our named executive officers. Our initial executive compensation program is designed to be consistent with industry practice, linking executive compensation with the performance of the company by providing appropriate incentives to reward

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executives for performance that maximizes value creation for stockholders, while also enhancing retention during the critical transition to an independent company.

        Salary —The salaries for our named executive officers will be established based on peer group market data, as well as individual factors including experience and internal pay equity.

        Annual Incentive —The annual incentive component of our initial compensation program will provide each named executive officer with a target annual incentive opportunity expressed as a percentage of salary. Award opportunities will range from 0% to 200% of target and will be paid in cash. The initial awards will be based 50% on financial performance (the non-equity incentive award portion) and 50% on strategic goals related to our transition to an independent company (the bonus portion). In subsequent years, our compensation committee will determine the appropriate mix of financial, strategic and individual goals.

        The annual incentive will have established performance targets and weightings for each metric. Each metric will be evaluated independently with results on each metric summed to determine the final award payout. Specific payouts associated with performance above and below the target level will be determined on a subjective evaluation of results, including considerations related to the broader business environment, industry environment, oil prices and other factors. Initially, financial performance may be measured based on internal metrics such as EBITDAX, cash flow, and other metrics to be determined by our compensation committee and strategic goals will focus on measures related to executing a successful transition.

        Long-Term Incentives —Our initial compensation program will provide the majority of each named executive officer's compensation package through long-term incentives. The long-term incentive portion of the initial compensation program will be delivered using two types of awards:

    Restricted Stock Awards —The restricted stock portion of the long-term incentives will generally represent 40%—50% of the total long-term incentive award value for named executive officers. These awards are intended to enhance retention and development of ownership in the new organization and will vest, subject to attainment of an established performance goal, as early as the end of three years from the grant date, or as late as the end of seven years from the grant date. If the performance goal is not attained by the end of the applicable performance period, the award will forfeit in its entirety.

    Stock Options —The stock option portion of the long-term incentives will generally represent 50%—60% of the total long-term incentive award value for named executive officers. These awards are intended to incentivize executive behaviors that drive stock price appreciation by providing potential for long-term upside. The stock options will vest in equal installments over three years from the grant date and will have a seven-year exercise term. To account for potential volatility at the spin-off and to provide additional incentive for meaningful stock price appreciation, initial awards of stock options to named executive officers in connection with the spin-off will be granted with an exercise price that is 10% above the fair market value of our common stock at the time of the grant.

        For future years, the types of awards granted, their weighting as a percentage of total long-term incentive opportunity and any performance metrics will be determined by our compensation committee.

        These long-term incentives will be granted pursuant to the California Resources Corporation Long-Term Incentive Plan, which will be adopted prior to the spin-off. For greater detail regarding the terms of this plan, see "Executive Compensation-CRC Long-Term Incentive Plan" and the form of California Resources Corporation Long-Term Incentive Plan, a copy of which is filed as an exhibit to the registration statement of which this information statement is a part.

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        The following table summarizes key features of the long-term incentive components of the initial compensation program for named executive officers.

 
  Restricted Stock Awards   Stock Options
Forfeiture Provisions   Shares of stock will become non-forfeitable on the vesting date. If the grantee dies, becomes permanently disabled, retires with our consent, or is terminated without cause for our convenience prior to the vesting date, then the grantee will forfeit a pro rata portion of the shares based on the days remaining until the vesting date. If the grantee terminates voluntarily or is terminated for cause prior to the vesting date, all of the shares will be forfeited.   Stock options will become non-forfeitable on the applicable vesting dates.

If the grantee dies, becomes permanently disabled, retires with our consent, or is terminated without cause for our convenience prior to the final vesting date, then the grantee will forfeit a pro rata portion of the unvested stock options based on the days remaining until the final vesting date. Vested stock options will remain exercisable through the term of the original award.

        If the grantee terminates voluntarily or is terminated for cause prior to the final vesting date, all unvested stock options will be forfeited. Vested stock options will be exercisable for 90 days following the termination and will be forfeited after that date.
Change in Control   In the event of a change in control prior to the vesting date, a pro-rata portion of the shares will be forfeited based on the days remaining until the vesting date following the later of the date of the change in control and the date of the termination of the grantee's employment. The remaining shares will become nonforfeitable.   In the event of a change in control prior to the final vesting date, if a grantee is terminated by us as a result of the change in control, unvested stock options will become non-forfeitable. Vested stock options will remain exercisable through the term of the original award.
    In the event of a change in control after the vesting date, but prior to certification of the performance threshold, the shares of stock will become non-forfeitable.    

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Individual Compensation Arrangements

        The Occidental Compensation Committee has approved the following cash and equity compensation arrangements for our expected named executive officers. As discussed above, our retirement and other benefits will be substantially similar to the Occidental programs and are described below.

Todd A. Stevens—President and Chief Executive Officer

        Mr. Stevens, a 19-year veteran of Occidental, was appointed President, Chief Executive Officer and Director of CRC in July 2014. Mr. Stevens served as Vice President—Corporate Development of Occidental Petroleum Corporation from August 2012 to July 2014. In that role, he led Occidental's growth-focused initiatives including mergers and acquisitions, land management and worldwide exploration, and played a key role in the capital allocation process. From October 2004 to August 2012, Mr. Stevens was Vice President—Acquisition and Corporate Finance of Occidental Petroleum Corporation, and from April 2008 to September 2012, Mr. Stevens was Vice President—California Operations, Oxy Oil & Gas.

Compensation Element
  Target Value on
Grant Date
 

Base Salary

  $ 825,000  

Annual Incentive

  $ 825,000  

Long-Term Incentive

       

Restricted Stock Award

  $ 2,000,000  

Stock Option Award

  $ 3,000,000  

Total Cash and Equity Compensation

  $ 6,650,000  

William E. Albrecht—Executive Chairman

        Mr. Albrecht was appointed as Executive Chairman of our board of directors in July 2014. Mr. Albrecht served as Vice President of Occidental from May 2008 to July 2014 and as President, Oxy Oil & Gas, Americas from January 2012 to July 2014. With more than 35 years of industry experience, Mr. Albrecht was responsible for Occidental's oil and gas operations in North and South America, including its health, environment and safety, government relations and social responsibility activities. He joined Occidental in 2007 as Vice President, California Operations.

Compensation Element
  Target Value on
Grant Date
 

Base Salary

  $ 500,000  

Annual Incentive

  $ 500,000  

Long-Term Incentive

       

Restricted Stock Award

  $ 2,000,000  

Stock Option Award

  $ 2,000,000  

Total Cash and Equity Compensation

  $ 5,000,000  

        In addition, Mr. Albrecht will receive a transition bonus from Occidental of $1,250,000 prior to the spin-off.

Marshall (Mark) Smith—Senior Executive Vice President and Chief Financial Officer

        Mr. Smith was appointed Senior Executive Vice President and Chief Financial Officer of CRC in July 2014. He most recently served as Senior Vice President of Ultra Petroleum Corp. from January 2011 to July 2014 and served as its Chief Financial Officer from July 2005 to July 2014. Mr. Smith's 32 years of experience in the energy industry spans operations, strategic planning, corporate finance and business development. He began his career as a petroleum engineer working at both major and independent oil companies, later focusing on mergers, acquisitions and corporate finance advisory assignments. Mr. Smith served as Vice President of Upstream Business Development at Constellation Energy from 2004 to 2005.

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He was Vice President of Business Development at J.M. Huber Energy from 2002 to 2004, and Chief Financial Officer of Gulf Liquids, Inc. from 2001 to 2002. Mr. Smith holds a Bachelors of Science degree from the University of Oklahoma and a Masters of Business Administration degree from Oklahoma City University.

Compensation Element
  Target Value on
Grant Date
 

Base Salary

  $ 600,000  

Annual Incentive

  $ 600,000  

Long-Term Incentive

       

Restricted Stock Award

  $ 1,200,000  

Stock Option Award

  $ 1,800,000  

Total Cash and Equity Compensation

  $ 4,200,000  

        In addition, Mr. Smith received a cash sign-on bonus of $500,000 and a sign-on restricted stock award with a grant date value of $2,500,000, which will vest at the end of two years, subject to his continued employment with CRC.

Robert A. Barnes—Executive Vice President—Northern Operations

        Mr. Barnes, with 36 years' experience at Occidental, was appointed Executive Vice President—Northern Operations of CRC in July 2014. Mr. Barnes served as President and General Manager of Occidental of Elk Hills from December 2012 to July 2014. He served as Operations Manager for Oxy Permian CO 2 from May 2011 to November 2012, as Deputy General Manager and Senior Vice President, Operations, of Occidental Argentina from June 2010 to April 2011, and as Vice President, Operations, of Occidental Argentina from August 2007 to June 2010. Mr. Barnes also held Production Operations Manager and Operations Team Leader roles at Occidental of Elk Hills from 1998 to 2007, and worked as Production Superintendent in the Hugoton and Virginia Coalbed Methane Operations and held various roles in Operations and Drilling Engineering throughout the Rocky Mountains, California and Mid-Continent regions since joining Occidental in 1978.

Compensation Element
  Target Value on
Grant Date
 

Base Salary

  $ 400,000  

Annual Incentive

  $ 360,000  

Long-Term Incentive

       

Restricted Stock Award

  $ 800,000  

Stock Option Award

  $ 1,200,000  

Total Cash and Equity Compensation

  $ 2,760,000  

Frank E. Komin—Executive Vice President—Southern Operations

        Mr. Komin, with 14 years' experience at Occidental, was appointed Executive Vice President—Southern Operations of CRC in July 2014. Mr. Komin served as President and General Manager of OXY Long Beach from January 2010 to July 2014, and served as President and General Manager of Oxy THUMS from February 2001 to December 2009. With more than 36 years of experience in the domestic oil and gas industry, Mr. Komin has overseen all aspects of Long Beach operations and the development of

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the Wilmington field. Before joining Occidental, Mr. Komin worked for 22 years at ARCO, most recently as Reservoir Engineering Manager and Operations Superintendent, Kuparuk, Alaska.

Compensation Element
  Target Value on
Grant Date
 

Base Salary

  $ 400,000  

Annual Incentive

  $ 360,000  

Long-Term Incentive

       

Restricted Stock Award

  $ 800,000  

Stock Option Award

  $ 1,200,000  

Total Cash and Equity Compensation

  $ 2,760,000  

Other Compensation and Benefits

        In addition to the three components of the executive compensation program described above, we will provide the following programs to our named executive officers.

        Qualified Defined Contribution Plan —All of our employees will be eligible to participate in a tax-qualified, defined contribution plan. The defined contribution plan will provide for periodic cash contributions by CRC based on annual cash compensation and employee 401(k) deferrals. Employees will be permitted to save a percentage of their annual salary and bonus up to the annual limit set by IRS regulations. Employees will be able to direct their contributions to a variety of investments.

        Nonqualified Defined Contribution Plan —Substantially all employees whose participation in our qualified defined contribution plan is limited by applicable tax laws will be eligible to participate in our nonqualified defined contribution plan, which provides additional retirement benefits outside of those limitations.

        Annual allocations for each participant will restore the amounts that would have been contributed to the qualified defined contribution plan, but for the tax law limitations. Account balances will be payable following separation from service, or upon attainment of a specified age elected by the participant when initially participating in the plan.

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

        Nonqualified Deferred Compensation Plan —Certain management and other highly compensated employees will be eligible to participate in a nonqualified deferred compensation plan. Under the plan, participants will be able to elect to defer a portion of their base salary and annual bonus for a given year. Deferred amounts will earn interest at a rate equal to the five-year U.S. Treasury Note rate on the last business day of the processing month plus 2%, converted to a monthly allocation factor. Account balances will be payable following separation from service, or upon attainment of a specified age elected by the participant when initially participating in the plan.

        Tax Preparation and Financial Planning —Our senior executives, including each of the named executive officers, will be eligible to receive reimbursement, up to certain annual limits, for financial planning and investment advice, including legal advice related to tax and financial matters.

        Insurance —We will offer a variety of health coverage options to all employees. Named executive officers will participate in these plans on the same terms as other employees. In addition, for all employees above a certain job level, we will pay for an annual physical examination. We will provide all non-bargained employees with life insurance equal to twice the employee's base salary. We will also provide senior executives, including the named executive officers, with excess liability insurance coverage.

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        Severance Benefits —We will maintain a notice and severance pay plan that will, in connection with a qualifying termination of employment, provide for up to 12 months of base salary and other insurance coverage, depending on years of service, for non-bargained employees, including the named executive officers.

Stock Ownership Guidelines

        CRC will have minimum stock ownership guidelines for senior executives following the spin-off. The target ownership level for the Chief Executive Officer will be six times annual base salary and for the other named executive officers will be three times annual base salary. Executives will have five years to attain their required ownership levels.

CRC Long-Term Incentive Plan

        Prior to the spin-off, we will have adopted, and Occidental Petroleum Investment Co. ("OPIC"), a subsidiary of Occidental Petroleum Corporation, in its capacity as the sole stockholder of CRC will have approved, the California Resources Corporation Long-Term Incentive Plan (the "LTIP") to attract and retain employees, consultants and directors of CRC and its affiliates. The description of the LTIP set forth below is a summary of the material features of the LTIP. This summary, however, does not purport to be a complete description of all of the provisions of the LTIP and is qualified in its entirety by reference to the LTIP, a copy of which is filed as an exhibit to the registration statement of which this information statement is a part. As described in greater detail below, the LTIP provides for the grant of cash-based and equity-based awards with respect to our common stock.

Share Limits

        The number of shares of our common stock that will be available for issuance under the LTIP has not yet been determined. However, once such number is determined (which number will be disclosed in a subsequent amendment to the registration statement of which this information statement is a part) it will be subject to adjustment in accordance with the terms of the LTIP upon certain changes in capitalization and similar events. Awards payable in cash or payable in cash or shares, including restricted shares, that are forfeited, cancelled or do not vest, and shares that are subject to awards that expire or for any reason are terminated, cancelled, or fail to vest, will be available for subsequent awards under the LTIP. If an award under the LTIP is or may be settled only in cash, such award generally will not be counted against the share limit in the LTIP.

        During the term of the LTIP, no participant may be granted awards with respect to more than 50% of the shares of our common stock authorized for issuance under the LTIP, subject to adjustment in accordance with the terms of the LTIP. In addition, the LTIP will include a maximum limit on the amount of compensation that can be paid with respect to any performance-based awards denominated in cash granted to any one individual during any calendar year.

Administration and Eligibility

        Prior to the spin-off, the LTIP will be administered by the Occidental Compensation Committee. From and after the spin-off, the LTIP will be administered by the compensation committee of our board of directors (collectively with the Occidental Compensation Committee, the "Committee").

        Under the terms of the LTIP, the Committee has broad discretion to administer the plan, including the ability to determine to whom and when awards will be granted, determine the type and amount of awards (measured in cash or in shares of our common stock), construe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting of any award, delegate certain duties under the LTIP and execute all other responsibilities permitted or required under the LTIP.

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        The individuals eligible to receive awards under the LTIP include any person who at the time of grant is an officer, employee or consultant of CRC or any of our affiliates or is a non-employee member of our board of directors (together, an "eligible person").

Types of Awards

        As described above, the Committee has broad discretion under the plan to determine the types of awards it grants to eligible persons. The types of awards permitted under the LTIP (collectively, "awards") include: stock options (including both incentive stock options and nonstatutory options), stock purchase rights, stock bonuses, restricted stock units, stock appreciation rights, limited stock appreciation rights, phantom stock, restricted stock, stock units, dividend equivalents (independently or in tandem with any form of stock grant), dividend rights (independently or in tandem with any form of stock grant), or any similar securities with a value derived from the value of or related to our common stock or other securities or returns thereon, in each case, any of which may be payable in shares or cash, and may consist of one or more of such features in any combination, as determined by the Committee. In addition, the Committee has the authority under the LTIP to grant cash-based awards.

Performance-Based Awards

        The Committee may designate any award under the LTIP (including a cash award) as a "performance-based award." A performance-based award is any award the grant, exercise or settlement of which is subject to one or more performance standards that the Committee deems appropriate. However, if the Committee desires a performance-based award to constitute "performance-based compensation" for purposes of Section 162(m) of the Internal Revenue Code, then one or more of the following business criteria for us, on a consolidated basis, and/or for specified subsidiaries or business or geographical units, may be used by the Committee in establishing the performance goals for such performance awards: (A) accounts receivable to day sales outstanding; (B) accounts receivable to sales, services and/or other income; (C) debt; (D) debt to debt plus stockholder equity; (E) debt to earnings before interest expense and taxes (EBIT) or earnings before interest expense, taxes, depreciation and amortization (EBITDA); (F) EBIT; (G) EBITDA; (H) earnings per share; (I) economic value added; (J) expense reduction or improvement; (K) interest coverage; (L) inventory to sales, (M) inventory turns, (N) net income, (O) operating cash flow, (P) pre-tax margin, (Q) return on assets; (R) return on capital employed; (S) return on equity; (T) sales; (U) stock price appreciation; (V) total stockholder return; (W) operational measures such as changes in proved reserves, production goals, drilling costs, lifting costs, exploration costs, environmental compliance, safety and accident rates; (X) mix of oil and natural gas production or reserves; (Y) finding and development costs; (Z) recycling ratios; (AA) reserve growth; (BB) additions or revisions; (CC) captured prospects; (DD) lease operating expense; or (EE) captured net risked resource potential, in each case, as determined on an absolute or relative basis or as compared to the performance of a published or special index deemed applicable by the Committee including, but not limited to, the Standard & Poor's 500 Stock Index or a group of comparable companies.

Change in Control and Other Adjustments

        Upon a "change in control" (as defined in the LTIP), unless otherwise determined by the Committee, all awards outstanding pursuant to the plan will fully-vest and, if applicable, become exercisable. In addition, upon any change that is made to our capitalization, such as a stock split, stock combination, stock dividend, exchange of shares or other recapitalization, merger or otherwise, appropriate adjustments may be made by the compensation committee in the shares subject to the LTIP and awards under the LTIP.

Amendment and Termination

        Our board of directors may amend or terminate the LTIP at any time. However, no amendment or termination may impair the rights or benefits of a participant under an outstanding award in any material

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way without such participant's consent. In addition, to the extent required pursuant to any federal or state law or regulation or the rules of any stock exchange or automated quotations system in which shares of our common stock is listed or quoted, any such amendment will be subject to the approval of our stockholders.

        No awards may be granted under the LTIP from or after the tenth anniversary of the effective date of the plan.

Restrictions on Transfer

        Subject to certain limited exceptions under the LTIP, awards are generally not transferrable by the participant other than by will or the laws of descent.

Tax Withholding

        At our discretion, subject to conditions that the Committee may impose, a participant's minimum statutory tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of shares of our common stock issuable pursuant to the award based on the fair market value of the shares.

CRC Employee Stock Purchase Plan

        Prior to the spin-off, we anticipate that our board of directors will have adopted, and OPIC, in its capacity as the sole stockholder of CRC will have approved, the California Resources Corporation 2014 Employee Stock Purchase Plan (the "ESPP"). The ESPP will provide our employees and the employees of our subsidiaries that participate in the ESPP the ability to purchase shares of our common stock at a price equal to 85% of the closing price of a share of our common stock as of the first day of each offering period or the last day of each offering period, whichever amount is less. The ESPP will be administered by our compensation committee and is intended to qualify as an "employee stock purchase plan" pursuant to Section 423 of the Internal Revenue Code.

        The maximum number of shares of our common stock which may be issued pursuant to the ESPP has not yet been determined. However, once such number is determined (which number will be disclosed in a subsequent amendment to the registration statement of which this information statement is a part), it will be subject to adjustment pursuant to the terms of the ESPP. In addition, participants in the ESPP are subject to certain statutory limits on the number of shares that can be purchased in any given year.

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EXECUTIVE COMPENSATION TABLES

Summary Compensation Table

        We are a newly-formed entity and have not historically paid compensation or had employees (including executive officers). The tables below and the accompanying footnotes summarize the 2013 compensation paid by Occidental for the individuals that we expect to constitute our named executive officers following the spin-off. Compensation relating to our principal financial officer is not shown because he was not an employee of Occidental during 2013.

Name
  Year   Salary   Bonus(1)   Stock
Awards(2)
  Option
Awards
  Non-Equity
Incentive Plan
Compensation(3)
  Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
  All Other
Compensation(4)
  Total  

Todd A. Stevens

    2013   $ 385,000   $ 259,000   $ 2,846,340   $ 0   $ 791,000   $ 360   $ 114,766   $ 4,396,466  

President and Chief Executive Officer

                                                       

William E. Albrecht

   
2013
 
$

575,000
 
$

300,000
 
$

4,197,732
 
$

0
 
$

420,000
 
$

0
 
$

159,347
 
$

5,652,079
 

Executive Chairman

                                                       

Robert A. Barnes

   
2013
 
$

310,000
 
$

325,186

(5)

$

250,000
 
$

0
 
$

393,000
 
$

0
 
$

83,475
 
$

1,361,661
 

Executive Vice President—Northern Operations

                                                       

Frank E. Komin

   
2013
 
$

302,000
 
$

288,459

(5)

$

225,000
 
$

0
 
$

280,625
 
$

0
 
$

77,714
 
$

1,173,798
 

Executive Vice President—Southern Operations

                                                       

(1)
The 2013 amounts shown represent only the discretionary portion of the executive's Annual Incentive award, which was paid in the first quarter of 2014.

(2)
Awards that are payable in stock or based on stock value are stated at the grant date fair value, which incorporates the value of Occidental's stock as well as the estimated payout percentage as of the grant date. For a description of the assumptions used for calculating this amount, see Note 12 to Consolidated Financial Statements in Occidental's Form 10-K for the year ended December 31, 2013 regarding assumptions underlying valuation of equity awards.

(3)
The amounts represent only the performance-based portion of the executive's Annual Incentive award. The payout related to the Annual Incentive award was determined based on Occidental's attainment of specified earnings per share targets for Messrs. Stevens and Albrecht or production and cash flow goals for Messrs. Barnes and Komin.

(4)
The following table shows "All Other Compensation" amounts for 2013.

    All Other Compensation

 
  Todd A. Stevens   William E. Albrecht   Robert A. Barnes   Frank E. Komin  

Savings Plan(a)

  $ 15,300   $ 15,300   $ 15,300   $ 15,300  

Supplemental Retirement Plan II(b)

  $ 83,355   $ 129,675   $ 68,175   $ 62,175  

Personal Benefits

  $ 16,111 (c) $ 14,372 (d) $ 0   $ 239 (d)

Total

  $ 114,766   $ 159,347   $ 83,475   $ 77,714  

(a)
The amount shown is the company's contribution to the Occidental Petroleum Corporation Savings Plan (the "Savings Plan").

(b)
The amount shown is the company's contribution to the Occidental Petroleum Corporation Supplemental Retirement Plan II (the "Supplemental Retirement Plan II").

(c)
Includes tax preparation and financial counseling, excess liability insurance, physical examinations, and tax gross-up related to the amounts paid by Occidental for spousal travel ($596).

(d)
Reflects tax gross-up related to the amounts paid by Occidental for spousal travel.
(5)
Includes a special bonus of $183,186 for Mr. Barnes and $178,459 for Mr. Komin for 2013 operational performance.

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Grants of Plan-Based Awards

        The table below summarizes the following plan-based awards granted by the Occidental Compensation Committee to the expected named executive officers in 2013: Executive Incentive Compensation Plan (Non-Equity Incentive Portion)—EICP, Total Shareholder Return Incentive Awards ("TSR"), Restricted Stock Incentive Awards ("RSI"), Restricted Stock Incentive Awards (Time Vested)—RSI-TV, Return on Capital Employed Incentive Awards ("ROCE"), Return on Assets (Total) Awards ("ROA-T"), Return on Assets (Americas) Awards ("ROA-A").

        The equity awards listed below are the only stock awards granted to the expected named executive officers in 2013. No option awards or non-performance-based stock awards were granted in 2013.

 
   
   
   
   
   
   
   
   
  All Other
Option
Awards:
Number of
Securities
Underlying
Options
(# of Shares)
   
   
 
 
   
  Estimated Future Payouts
Under Non-Equity Incentive
Plan Awards
  Estimated Future Payouts
Under Equity Incentive
Plan Awards
  All Other
Stock
Awards:
Number of
Shares or
Units
(# Shares)
   
  Grant Date
Fair
Value of
Stock and
Option
Awards ($)
 
 
   
  Exercise or
Base
Price of
Option
Awards ($)
 
Name / Type of Grant
  Grant
Date
  Threshold
($)
  Target
($)
  Maximum
($)
  Threshold
# Shares
  Target
# Shares
  Maximum
# Shares
 

Todd A. Stevens

                                                                   

EICP(1)

        $ 4,000   $ 285,000   $ 570,000                                            

TSR(3)

    7/22/2013                       88     8,808     13,212                     $ 550,865  

RSI(2)

    7/22/2013                             8,808                           $ 810,000  

ROCE(4)

    7/22/2013                       2,935     11,740     23,480                     $ 1,493,315  

William E. Albrecht

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

EICP(1)

        $ 6,000   $ 450,000   $ 900,000                                            

TSR(3)

    7/22/2013                       147     14,679     22,019                     $ 918,045  

RSI(2)

    7/22/2013                             14,679                           $ 1,350,000  

ROA-T(4)

    7/22/2013                       1,223     4,893     9,786                     $ 579,687  

ROA-A(4)

    7/22/2013                       3,670     14,679     29,358                     $ 1,350,000  

Robert A. Barnes

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

EICP(1)

        $ 3,000   $ 210,000   $ 420,000                                            

RSI-TV(5)

    7/22/2013                             2,719                           $ 250,000  

ROA-T(6)

    7/22/2013   $ 15,000   $ 60,000   $ 120,000                                            

ROA-A(6)

    7/22/2013   $ 47,500   $ 190,000   $ 380,000                                            

Frank E. Komin

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

EICP(1)

        $ 2,000   $ 150,000   $ 300,000                                            

RSI-TV(5)

    7/22/2013                             2,447                           $ 225,000  

ROA-T(6)

    7/22/2013   $ 13,500   $ 54,000   $ 108,000                                            

ROA-A(6)

    7/22/2013   $ 42,750   $ 171,000   $ 342,000                                            

(1)
Payout at threshold assumes EPS of $6.26.

(2)
Dollar value shown represents the estimated grant date fair value of the full number of shares granted which become non-forfeitable on the later of the vesting date (July 21, 2016), through which date the executive must remain employed by the company, and the date the Occidental Compensation Committee certifies the achievement of the performance goal, which must be met no later than June 30, 2020. The RSI award does not have threshold to maximum payout ranges.

(3)
Actual payout may range from zero to the maximum number of performance share units. Awards will be paid out 100% in stock in a number of shares equal to the number of performance share units earned on the date of certification of the attainment of the performance goals. The target shares represent the target number of performance shares granted on the grant date, representing a payout of 100%. Threshold shares represent Occidental's performance just above the 25th percentile, resulting in an assumed payout of 1% of the target number of performance share units. The actual percentage payout would be linearly interpolated between the 25th percentile TSR performance (0% payout) and the 75th percentile TSR performance (150% payout). The estimated fair value of the TSR at the grant date is based on the projected performance at the grant date for Occidental indicating a payout of 68% of the target number of performance share units . See Note 12 to Consolidated Financial Statements in Occidental's Form 10-K for the year ended December 31, 2013, regarding assumptions underlying valuation of equity awards.

(4)
Dollar value shown represents the estimated grant date fair value of the target number of performance share units granted. The estimated fair value of the ROCE, ROA-T, and ROA-A is based on the projected performance at the grant date for Occidental indicating payouts of approximately 138%, 129%, and 100%, respectively. The actual payout may range from 0% to 200% of the target number of performance share units and will be paid out 100% in stock. Threshold shares represent a 25% payout percentage, which would be achieved with a return meeting the minimum threshold of 9% ROCE, 9% ROA-T, and 8% ROA-A.

(5)
Dollar value shown represents the estimated grant date fair value of the full number of units granted which become non-forfeitable with respect to one—third of the total units granted each on July 21, 2014, July 21, 2015, and July 21, 2016. The RSI-TV award does not have threshold to maximum payout ranges.

(6)
Dollar value shown represents the estimated grant date fair value of the target award granted. The estimated fair value of the ROA-T, and ROA-A is based on the projected performance at the grant date for Occidental indicating payouts of approximately 129%, and 100%, respectively. The actual payout may range from 0% to 200% of the target award amount and will be paid out 100% in cash. Threshold shares represent a 25% payout percentage, which would be achieved with a return meeting the minimum threshold of 9% ROA-T and 8% ROA-A.

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Outstanding Equity Awards at December 31, 2013

        The table below sets forth the outstanding equity awards held by the expected named executive officers as of December 31, 2013, including RSI, TSR, ROCE, ROA-T, ROA-A, Restricted Stock Incentive Awards (Time Vested), Phantom Share Unit Awards (PhSU), and Long-Term Incentive Awards (LTI).

        The TSR, RSI, ROCE, ROA-T, and ROA-A are performance-based awards with payouts that depend on the outcome of the performance criteria and the price of Occidental's stock on the award certification date, as applicable, with the possibility of no payout if performance criteria are not met. These are long-term awards with three-year and three- to seven-year performance periods, as applicable, that, based on achievement of performance criteria, will vest or become nonforfeitable between 2014 and 2020. The values shown for the TSR, ROCE, ROA-T, and ROA-A awards in the table below are shown at threshold, target, estimated performance, or maximum levels, as described below. Actual payouts, if any, will reflect actual performance, which may be at lower or higher levels than shown below, and on the price of Occidental's common stock at the time of payout, as applicable.

 
   
  Option Awards   Stock Awards  
Name / Type of Grant
  Grant Date   Number of
Securities
Underlying
Unexercised
Options (#)
Exercisable
  Number of
Securities
Underlying
Unexercised
Options (#)
Unexercisable
  Option
Exercise
Price ($)
  Option
Exercise
Date
  Number of
Shares or
Units of
Stock That
Have Not
Vested (#)
  Market
Value of
Shares or
Units That
Have Not
Vested ($)(1)
  Equity
Incentive
Plan
Awards:
Number of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested (#)
  Equity
Incentive
Plan
Awards:
Market or
Payout
Value of
Unearned
Shares,
Units or
Other
Rights That
Have Not
Vested (#)(1)
 

Todd A. Stevens

                                                       

RSI

    7/13/2011                                         15,539 (2) $ 1,477,759 (2)

RSI

    7/11/2012                                         18,920 (3) $ 1,799,292 (3)

RSI

    7/22/2013                                         8,808 (4) $ 837,641 (4)

TSR

    7/13/2011                                         2,331 (5,6) $ 221,678 (5)

TSR

    7/11/2012                                         2,838 (5,7) $ 269,884 (5)

TSR

    7/22/2013                                         8,808 (5,8) $ 837,641 (5)

ROCE

    7/22/2013                                         2,936 (9) $ 279,190 (9)

William E. Albrecht

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

RSI

    7/13/2011                                         15,539 (2) $ 1,477,759 (2)

RSI

    7/11/2012                                         18,920 (3) $ 1,799,292 (3)

RSI

    7/22/2013                                         14,679 (4) $ 1,395,973 (4)

TSR

    7/13/2011                                         6,216 (5,6) $ 591,142 (5)

TSR

    7/11/2012                                         7,568 (5,7) $ 719,688 (5)

TSR

    7/22/2013                                         14,679 (5,8) $ 1,395,973 (5)

ROA-T

    7/22/2013                                         1,223 (9) $ 116,331 (9)

ROA-A

    7/22/2013                                         3,670 (9) $ 348,993 (9)

Robert A. Barnes

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

PhSU

    7/15/2011                             585 (10) $ 55,634              

LTI

    7/11/2012                             1,656 (11) $ 157,486              

RSI-TV

    7/22/2013                             2,719 (12) $ 258,577              

Frank E. Komin

   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
   
 
 

LTI

    7/13/2011                             566 (13) $ 53,827              

LTI

    7/11/2012                             1,576 (11) $ 149,878              

RSI-TV

    7/22/2013                             2,447 (12) $ 232,710              

(1)
The amounts shown represent the product of the number of shares or units shown in the column immediately to the left and the closing price on December 31, 2013 of Occidental common stock as reported in the NYSE Composite Transactions, which was $95.10.

(2)
The shares are forfeitable until the later of July 12, 2014 and the certification by the Occidental Compensation Committee that the achievement of the performance threshold is met no later than June 30, 2018.

(3)
The shares are forfeitable until the later of July 10, 2015 and the certification by the Occidental Compensation Committee that the achievement of the performance threshold is met no later than June 30, 2019.

(4)
The shares are forfeitable until the later of July 21, 2016 and the certification by the Occidental Compensation Committee that the achievement of the performance threshold is met no later than June 30, 2020.

(5)
For TSRs granted in 2011 and 2012, the values shown reflect an estimated payout of a number of shares based on the threshold performance level which also reflects the performance of Occidental through December 31, 2013, and would result in payouts of 10%. For TSRs granted in 2013, the values shown reflect an estimated payout of the target number of shares since the performance of Occidental through December 31, 2013 exceeds the

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    threshold payout level, but is less than the level required to attain target payout. However, the ultimate payout may be significantly less or more than the amounts shown, with the possibility of no payout, depending on the outcome of the performance criteria and the value of Occidental stock on the award certification date.

(6)
The performance period for the TSR ends June 30, 2014.

(7)
The performance period for the TSR ends June 30, 2015.

(8)
The performance period for the TSR ends June 30, 2016.

(9)
For ROA awards and ROCE awards granted in 2013, payout values shown are at the threshold payout level of 25% since the performance periods begin January 1, 2014. However, the ultimate payout may be significantly less (zero) or more than the amounts shown, depending on the outcome of the performance criteria and the value of Occidental stock on the award certification date.

(10)
The units were forfeitable until July 14, 2014.

(11)
50% of the units were forfeitable until July 10, 2014 and 50% of the units are forfeitable until July 10, 2015.

(12)
33 1 / 3 % of the units were forfeitable until July 21, 2014, 33 1 / 3 % of the units are forfeitable until July 21, 2015 and 33 1 / 3 % of the units are forfeitable until July 21, 2016.

(13)
The units were forfeitable until July 12, 2014.

Option Exercises and Stock Vested in 2013

        The following table summarizes, for the expected named executive officers, the stock awards vested during 2013. The amounts reported as value realized are shown on a before-tax basis. No option awards vested. The stock awards that vested for Messrs. Stevens and Albrecht were TSR awards granted in 2009 and 2010 and RSI awards granted in 2010. The stock awards that vested for Messrs. Barnes and Komin were LTI awards granted in 2012 which were payable 50% in stock and 50% in cash.

Previously Granted Vested Option Awards Exercised and Previously Granted Stock Awards Vested in 2013

 
  Option Awards   Stock Awards  
Name
  Number of Shares
Acquired on
Exercise (#)
  Value Realized
on Exercise ($)
  Number of Shares
Acquired on
Vesting (#)
  Value Realized
on Vesting ($)(1)
 

Todd A. Stevens

    0   $ 0     29,223   $ 2,719,740  

William E. Albrecht

    0   $ 0     48,104   $ 4,487,310  

Robert A. Barnes

    0   $ 0     414   $ 36,962  

Frank E. Komin

    0   $ 0     395   $ 35,266  

(1)
The amount represents the product of the number of shares vested and the closing price of the common stock on the New York Stock Exchange on the vesting date. The following table shows the number of shares of each type of performance-based award that vested.

Name
  Number of Shares
of TSR Awards
  Number of Shares of
Restricted Stock Awards
or LTIs
 

Todd A. Stevens

    19,731     9,492  

William E. Albrecht

    31,494     16,610  

Robert A. Barnes

    0     414  

Frank E. Komin

    0     395  

Nonqualified Deferred Compensation

Nonqualified Defined Contribution Retirement Plan

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

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

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

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

        Mr. Albrecht made a specified age election such that his SRP II account, shown below, is being distributed annually. After a participant receives a specified age distribution, future allocations under the SRP II and earnings on those allocations will be distributed in the first 70 days of each following year.

Nonqualified Deferred Compensation

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

        The following table sets forth for 2013 the contributions, earnings, withdrawals and balances under the SRP II and the MDCP in which the named executive officers participate. Each of the executive officers are fully vested in their respective aggregate balances shown below.

Name
  Plan   Executive
Contributions
in 2013
($)(1)
  Occidental
Contributions
in 2013
($)(2)
  Aggregate
Earnings
in 2013
($)
  Aggregate
Withdrawals/
Distributions
in 2013
($)(3)
  Aggregate Balance
at 12/31/2013
($)
 

Todd A. Stevens

  SRP II   $ 0   $ 83,355   $ 27,856   $ 0   $ 905,719  

  MDCP   $ 30,200   $ 0   $ 17,948   $ 0   $ 576,809  

William E. Albrecht

  SRP II   $ 0   $ 129,675   $ 3,641   $ 191,006   $ 132,859  

Robert A. Barnes

  SRP II   $ 0   $ 68,175   $ 11,619   $ 0   $ 385,823  

Frank E. Komin

  SRP II   $ 0   $ 62,175   $ 11,993   $ 0   $ 396,773  

  MDCP   $ 0   $ 0   $ 38,060   $ 0   $ 1,209,745  

(1)
No employee contributions are permitted in the SRP II.

(2)
Amounts represent Occidental's 2013 contributions to the SRP II, which are reported under "All Other Compensation" in the Summary Compensation Table.

(3)
Distribution made in February 2013 in accordance with the specified age elections described under Nonqualified Defined Contribution Retirement Plan above.

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Potential Payments Upon Termination or Change in Control

Summary

        Payments and other benefits payable to named executive officers in various termination circumstances and a change of control are subject to certain policies, plans and agreements. Following is a summary of the material terms of these arrangements.

        Occidental's Golden Parachute Policy provides that, subject to certain exceptions, Occidental will not grant Golden Parachute Benefits (as defined in the Policy) to any senior executive which exceed 2.99 times his or her salary plus annual incentive pay unless the grant of such benefits is approved by a vote of the corporation's stockholders or the obligation with respect to such benefit pre-dated adoption of the Policy. The Golden Parachute Policy was approved by Occidental's stockholders. The complete Golden Parachute Policy is available at www.oxy.com.

        Under Occidental's Notice and Severance Pay Plan, employees, including named executive officers without employment agreements (which includes our expected named executive officers), terminated in certain circumstances without cause or as a result of a change of control are eligible for up to 12 months base salary depending on years of service, two months of contributions pursuant to Occidental's Savings Plan and the SRP II, and continued medical and dental coverage for the 12-month notice and severance period at the active employee rate.

        In February 2013, Occidental provided the Retention and Separation Arrangements for Messrs. Stevens, Albrecht and Barnes, none of whom has an employment agreement or offer letter that addresses termination payments and benefits. These arrangements replaced any notice and severance pay that they would otherwise have received under the Notice and Severance Pay Plan. Had they remained employees of Occidental, they would have received a retention payment (Retention Payment) of one to two times their then-current annual base salary, payable in one lump sum cash payment one year after a new Chief Executive Officer of Occidental began employment. As Messrs. Stevens, Albrecht and Barnes will no longer be employed by Occidental following the spin-off, they will not receive the Retention Payment from Occidental. If they were terminated without cause by Occidental prior to December 31, 2014, subject to providing typical waivers and releases, they would have received (i) separation pay at their then-current base salary for 24 months, payable monthly; (ii) their target annual bonus amount for the year of separation, payable in one lump sum cash payment; (iii) the same medical and other benefits (other than notice and severance pay) as are received by employees under the Notice and Severance Pay Plan; and (iv) the Retention Payment (if not previously paid). In addition, Messrs. Stevens and Barnes would have received cash payments in consideration of forfeiture of all of their outstanding long-term incentive awards, as described in the footnotes to the individual tables below.

        Occidental's 2005 Long-Term Incentive Plan has provisions that, in the event of a change of control of Occidental, require the outstanding awards granted under such plan to become fully vested and exercisable unless the Plan Administrator determines, prior to the occurrence of the event, that benefits will not accelerate. This plan was approved by Occidental's stockholders. Notwithstanding the foregoing, as of 2011, all new grants of equity awards under such plan vest on a pro rata basis in the event of a change of control, TSR awards granted prior to 2013 vest based on 50% of the maximum number of units that could be paid, and TSR awards, ROCE awards and ROA awards granted in 2013 vest at the target number of performance shares granted and are converted to restricted stock. All outstanding RSI awards vest on a pro rata basis. Payout of all outstanding awards in the event of a change of control occurs at the earlier of the employee's termination date as a result of the change of control or the end of the applicable performance or restricted period.

        Except as described in this summary and below under "Potential Payments," Occidental does not have any other agreements or plans that will require it to provide compensation to our expected named executive officers in the event of a termination of employment or a change of control.

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Potential Payments

        In the discussion that follows, payments and other benefits payable upon various terminations and change of control situations are set out as if the conditions for payments had occurred and the terminations took place on December 31, 2013, and reflect the terms of applicable plans, agreements, offer letters and long-term incentive award agreements then in effect. The amounts set forth below are estimates of the amounts that would be paid to each named executive officer upon his or her termination. The "Maximum Payout" is the maximum amount, including incentive awards and certain benefits, that could have been payable in the event of a change of control situation. The actual amounts to be paid out can be determined only at the time of such named executive officer's separation from Occidental. The disclosures below do not take into consideration any requirements under Section 409A of the Internal Revenue Code, which could affect, among other things, the timing of payments and distributions.

        The following payments and benefits, which are potentially available to all full-time salaried employees when their employment terminates, are not included in the amounts shown below:

    Notice and Severance Pay Plan payments and benefits.

    Life insurance proceeds equal to two times base salary, payable on death as available to all eligible employees.

    Amounts vested under Occidental's plans that are qualified under Section 401(a) of the Internal Revenue Code.

    Amounts vested under the Nonqualified Deferred Compensation arrangements.

    Bonus and non-equity incentive compensation (collectively, "bonus") under Occidental's Executive Incentive Compensation Plan (EICP) that would have been earned as of year-end. Any plan participant who leaves on or after that date for any reason is entitled to such amounts when payment is made in the first quarter of the following year. The amounts that were earned in 2013 by the named executive officers are included in the Summary Compensation Table. Bonus under the EICP that would have been payable in accordance with the terms of the Retention and Separation Arrangements is shown in the amounts below.

        Mr. Stevens.     Mr. Stevens does not have an employment agreement, but effective beginning February 2013, he would have received the benefits pursuant to his Retention and Separation Arrangement as

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described above. The following is a summary of the payments and benefits he would have been entitled to receive if the event specified occurred as of December 31, 2013.

Benefits and Payments Upon
Termination
  Retirement with
Occidental
Consent, Death,
or Disability
  Termination by
Mr. Stevens or
Termination for
Cause
  Termination
without Cause
  Change of
Control
  Change of
Control and
Termination
 

Equity Compensation

                               

TSR Awards

  $ 417,538 (1) $ 0   $ 3,295,358 (a) $ 3,295,358 (3) $ 3,295,358 (3)

RSI Awards(2)

  $ 2,227,908   $ 0   $ 2,227,908   $ 2,103,327   $ 2,227,908  

ROCE Awards(4)

  $ 0   $ 0   $ 1,116,474 (b) $ 1,116,474   $ 1,116,474  

Cash Payments

                               

Unused Vacation (lump sum)

  $ 31,420   $ 31,420   $ 31,420   $ 0   $ 31,420  

Retention Payment

  $ 0   $ 0   $ 770,000   $ 0   $ 770,000  

Severance (24 months)

  $ 0   $ 0   $ 770,000   $ 0   $ 770,000  

EICP Bonus (at target)(5)

  $ 0   $ 0   $ 475,000   $ 0   $ 475,000  

Benefits

                               

Retirement Benefits (2 months)

                               

Savings Plan

  $ 0   $ 0   $ 3,850   $ 0   $ 3,850  

SRP II

  $ 0   $ 0   $ 4,492   $ 0   $ 4,492  
                       

TOTAL

  $ 2,676,866   $ 31,420   $ 8,694,502   $ 6,515,159   $ 8,694,502  

For numeric footnotes, see page 154.

(a)
Under the terms of his Retention and Separation Arrangement, Mr. Stevens would have been entitled to receive a cash payment equal to the product of the year-end price of Occidental common stock of $95.10, and 50% of the maximum number of shares payable under the TSR awards.

(b)
Under the terms of his Retention and Separation Arrangement, Mr. Stevens would have been entitled to receive a cash payment equal to the product of the year-end price of Occidental common stock of $95.10, and the target number of shares payable under the ROCE awards.

        Mr. Albrecht.     Mr. Albrecht does not have an employment agreement, but effective beginning February 2013, he would have received the benefits pursuant to his Retention and Separation

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Arrangement as described above. The following is a summary of the payments and benefits he would have been entitled to receive if the event specified occurred as of December 31, 2013.

Benefits and Payments Upon
Termination
  Retirement with
Occidental
Consent, Death,
or Disability
  Termination by
Mr. Albrecht or
Termination for
Cause
  Termination
without Cause
  Change of
Control
  Change of
Control and
Termination
 

Equity Compensation

                               

TSR Awards

  $ 1,016,224 (1) $ 0   $ 1,016,224 (1) $ 7,949,980 (3) $ 7,949,980 (3)

RSI Awards(2)

  $ 2,311,025   $ 0   $ 2,311,025   $ 2,103,327   $ 2,311,025  

ROA Awards(4)

  $ 0   $ 0   $ 0   $ 1,861,297   $ 1,861,297  

Cash Payments

                               

Unused Vacation (lump sum)

  $ 64,505   $ 64,505   $ 64,505   $ 0   $ 64,505  

Retention Payment

  $ 0   $ 0   $ 1,150,000   $ 0   $ 1,150,000  

Severance (24 months)

  $ 0   $ 0   $ 1,150,000   $ 0   $ 1,150,000  

EICP Bonus (at target)(5)

  $ 0   $ 0   $ 750,000   $ 0   $ 750,000  

Benefits

                               

Retirement Benefits (2 months)

                               

Savings Plan

  $ 0   $ 0   $ 5,750   $ 0   $ 5,750  

SRP II

  $ 0   $ 0   $ 6,708   $ 0   $ 6,708  
                       

TOTAL

  $ 3,391,754   $ 64,505   $ 6,454,212   $ 11,914,604   $ 15,249,265  

For numeric footnotes, see page 154.

        Mr. Barnes.     Mr. Barnes does not have an employment agreement, but effective beginning February 2013, he would have received the benefits pursuant to his Retention and Separation Arrangement as described above. The following is a summary of the payments and benefits he would have been entitled to receive if the event specified occurred as of December 31, 2013.

Benefits and Payments Upon
Termination
  Retirement with
Occidental
Consent, Death,
or Disability
  Termination by
Mr. Barnes or
Termination for
Cause
  Termination
without Cause
  Change of
Control
  Change of
Control and
Termination
 

Equity Compensation

                               

RSI-TV Awards(6)

  $ 38,516   $ 0   $ 38,516   $ 0   $ 38,516  

LTI Awards(a)

  $ 37,565   $ 0   $ 157,486   $ 157,486   $ 157,486  

PhSU Awards(a)

  $ 26,248   $ 0   $ 55,634   $ 55,634   $ 55,634  

Cash Payments

                               

ROA Awards(4)

  $ 0   $ 0   $ 250,000   $ 250,000   $ 250,000  

Unused Vacation (lump sum)

  $ 62,000   $ 62,000   $ 62,000   $ 0   $ 62,000  

Retention Payment

  $ 0   $ 0   $ 310,000   $ 0   $ 310,000  

Severance (24 months)

  $ 0   $ 0   $ 620,000   $ 0   $ 620,000  

EICP Bonus (at target)(5)

  $ 0   $ 0   $ 350,000   $ 0   $ 350,000  

Benefits

                               

Retirement Benefits (2 months)

                               

Savings Plan

  $ 0   $ 0   $ 3,100   $ 0   $ 3,100  

SRP II

  $ 0   $ 0   $ 3,617   $ 0   $ 3,617  
                       

TOTAL

  $ 164,329   $ 62,000   $ 1,850,353   $ 463,120   $ 1,850,353  

For numeric footnotes, see page 154.

(a)
Represents the product of the year-end price of Occidental common stock of $95.10 and the pro-rata number of unvested LTI or PhSU awards for Retirement with Occidental Consent, Death, or Disability, payable 50% in cash and 50% in shares for the LTI awards and 100% cash for the PhSU awards. Under the terms of his Retention and Separation Arrangement, Mr. Barnes

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    would have received a cash payment equal to the product of the year-end price of Occidental common stock of $95.10, and the number of unvested LTI and PhSU awards for Termination without Cause. For Change of Control, represents the product of the year-end price of Occidental common stock of $95.10 and the number of unvested LTI and PhSU awards, payable in cash. All unvested LTI and PhSU awards are forfeited in the case of voluntary termination by the executive and termination for cause.

            Mr. Komin.     Mr. Komin does not have an employment agreement. The following is a summary of the payments and benefits he would have been entitled to receive if the event specified occurred as of December 31, 2013.

Benefits and Payments Upon
Termination
  Retirement with
Occidental
Consent, Death,
or Disability
  Termination by
Mr. Komin or
Termination for
Cause
  Termination
without Cause
  Change of
Control
  Change of
Control and
Termination
 

Equity Compensation

                               

RSI Awards(2)

  $ 34,616   $ 0   $ 34,616   $ 0   $ 34,616  

LTI Awards(a)

  $ 61,150   $ 0   $ 61,150   $ 203,705   $ 203,705  

Cash Payments

                               

ROA Awards(4)

  $ 0   $ 0   $ 0   $ 225,000   $ 225,000  

Unused Vacation (lump sum

  $ 20,924   $ 20,924   $ 20,924   $ 0   $ 20,924  

Benefits

                               

Retirement Benefits (2 months)

                               

Savings Plan

  $ 0   $ 0   $ 3,020   $ 0   $ 3,020  

SRP II

  $ 0   $ 0   $ 3,523   $ 0   $ 3,523  
                       

TOTAL

  $ 116,690   $ 20,924   $ 123,233   $ 428,705   $ 490,788  

(a)
Represents the product of the year-end price of Occidental common stock of $95.10 and the pro-rata number of unvested LTI awards for all scenarios except voluntary termination or termination for cause, payable 50% in cash and 50% in shares. All unvested LTI awards are forfeited in the case of voluntary termination by the executive and termination for cause.

(1)
Represents the product of the year-end price of Occidental common stock of $95.10, and the pro rata shares of TSR awards. Under the terms of the TSR agreements, executives receive a prorated payout, paid after the end of the applicable performance period, based on actual performance and the number of days employed at Occidental during the performance period. The values shown reflect an estimated payout of a prorated number of shares based on performance of Occidental through December 31, 2013, which would result in payouts of 10% for the TSRs granted in 2011, 2012 and 69% for 2013. The performance periods for the TSRs end in 2014, 2015 and 2016 for the 2011, 2012 and 2013 grants, respectively, so these payouts may not be indicative of the payout that would be made at the end of the performance period based on actual performance. Actual payout would be prorated and could vary from zero to 100% of maximum for grants in 2011 and 2012, or zero to 150% of target for 2013 grants, depending on attainment of performance objectives. The value of the payout also depends on the price of Occidental common stock at payout.

(2)
Represents the product of the year-end price of Occidental common stock of $95.10 and the pro rata number of RSI awards for scenarios other than Change of Control for 2013 RSI awards which are not affected by a Change of Control. All RSI awards are forfeited in the case of voluntary termination by the executive and termination for cause. Awards that have not been forfeited are subject to achievement of performance goals in all scenarios except Change of Control. The right to receive amounts in excess of these amounts would have been forfeited.

(3)
Represents the product of the year-end price of Occidental common stock of $95.10 and the shares of TSR awards that become non-forfeitable. For 2011 and 2012 awards, the right to receive 50% of the maximum number of performance shares (payable in shares for 2012 awards and 50% in shares and 50% in cash for 2011 awards) becomes non-forfeitable, and for all shares received, a number of shares equal to 50% of the after-tax shares received are subject to a 3-year holding period. For 2013 awards, the target number of performance shares is converted into shares of restricted stock which become non-forfeitable. A number of shares equal to 50% of the net after-tax shares received are subject to a 3-year holding period until the earlier of the date of the grantee's termination as a result of the Change of Control, or the last day of the performance period. The right to receive amounts in excess of these amounts would have been forfeited.

(4)
Under the terms of the respective agreements for the ROCE awards and all ROA awards, in scenarios of termination due to death, disability, retirement with the consent of Occidental less than 12 months after the grant date and termination without cause, executives receive a prorated payout, paid after the end of the applicable performance period, based on actual performance and the number of days employed at Occidental during the performance period. Since the performance period

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    began January 1, 2014 and these tables show values for events as of December 31, 2013, no values are shown for most scenarios because the executive would not have been employed during the performance period. For voluntary termination and termination for cause, all awards are forfeited. For Change of Control, the target number of shares granted convert to shares of restricted stock that become non-forfeitable. A number of shares equal to 50% of the net after-tax shares received are subject to a 3-year holding period until the earlier of the date of termination due to the Change of Control or the last day of the performance period. Values shown for both Change of Control scenarios represent either the product of the year-end price of Occidental common stock of $95.10, and the target number of shares granted or the target dollar amount granted, as applicable.

(5)
Calculated assuming Occidental achieves target performance for the performance-based portion, but payment would be based on Occidental's actual performance.

(6)
Represents the product of the year-end price of Occidental common stock of $95.10 and the pro rata number of unvested RSI-TV awards for scenarios other than Change of Control which does not affect the award. All unvested RSI-TV awards are forfeited in the case of voluntary termination by the executive and termination for cause.


Director Compensation

        In order to have our director compensation program in effect at the time of the spin-off, Occidental has approved the initial director compensation program as described below. Following the spin-off, our board of directors will make decisions regarding our director compensation program.

        The Occidental Compensation Committee retained Pay Governance LLC, its independent compensation consultant, to assist in the design of the director compensation program to be in effect following the spin-off. Specifically, Pay Governance worked with Occidental and us to develop a peer group for purposes of conducting market analyses, as described above under "Executive Compensation—Anticipated Post-Spin-off Compensation Programs", and to determine the level and form of outside director compensation after the spin-off.

Program Objectives

        Our director compensation program to be in effect immediately following the spin-off is designed to be consistent with the programs of peer companies. In developing our director compensation program, Occidental and we took into account the following:

    Market practices of our peer companies, as well as a group of 100 general industry companies similar in size to us, targeting a compensation package between the median of those two groups.

    The need to recruit independent directors.

    The need to provide us with appropriate programs immediately following the spin-off, recognizing that our board of directors will be responsible for program design following the spin-off.

Program Elements

        The elements of our approved outside director compensation program are as follows:

    Outside directors will receive an annual cash board retainer of $100,000.

    Board committee chairpersons will receive an additional annual cash retainer of $15,000.

    The lead independent director will receive an additional annual cash retainer of $20,000.

    Outside directors will receive an annual equity award relating to our common stock equivalent to $150,000 on the grant date. The equity award will generally vest one year following the grant date.

    A stock ownership guideline of five times the annual cash board retainer will apply to outside directors and must be attained within five years of election to our board of directors.

        In addition, we anticipate that after the spin-off we will implement a program that allows our outside directors to defer some or all of their cash compensation.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

        As of the date of this information statement, all outstanding shares of our common stock are owned beneficially and of record by Occidental. After the spin-off, Occidental will hold the Retained Securities for a maximum of 18 months. The following table sets forth information with respect to the anticipated beneficial ownership of our common stock by:

    each shareholder we believe (based on the assumptions described below) will beneficially own more than 5% of our outstanding common stock;

    each person who is expected to serve as a director upon completion of the spin-off;

    each person who is expected to serve as an executive officer upon completion of the spin-off; and

    all persons who are expected to serve as directors or executive officers upon completion of the spin-off as a group.

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

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

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

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

 
  Amount and Nature
of Beneficial
Ownership
 
Name of Beneficial Owner
  Number   Percentage  

             

             

All executive officers and directors as a group (        persons)

             

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ARRANGEMENTS BETWEEN OCCIDENTAL AND OUR COMPANY

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

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

Separation and Distribution Agreement

        The Separation and Distribution Agreement will govern the terms of the separation of the California business from Occidental's other businesses. Generally, the Separation and Distribution Agreement will include the agreements of Occidental and us on the steps to be taken to complete the separation, including the assets and rights to be transferred, liabilities to be assumed or retained, contracts to be assigned and related matters. Subject to the receipt of required governmental and other consents and approvals, in order to accomplish the separation, the Separation and Distribution Agreement will provide for Occidental and us to transfer specified assets and liabilities between the two companies to separate the California business from Occidental's remaining businesses. As a result of this transfer, we will own all assets exclusively related to the California business, including the assets reflected on our balance sheet as of                , 2014, and certain other assets related to the California business specifically allocated to us. We will also be responsible for all liabilities, including environmental liabilities, to the extent relating to the operation or ownership of the California business or any of the assets allocated to us in the separation, as well as all liabilities arising out of, relating to or resulting from our new financing arrangements or reflected as liabilities on our balance sheet as of June 30, 2014, subject to the discharge of any such liabilities after June 30, 2014. Occidental will retain all other assets and liabilities, including assets and liabilities related to discontinued businesses (other than those businesses that were a part of the California business prior to being discontinued). For purposes of allocating assets and liabilities between us and Occidental, the Separation and Distribution Agreement will provide that the California business will generally be defined as:

    the exploration for and development and production of crude oil and condensate, NGLs and natural gas in the State of California and in state waters offshore California, including all California operations of Occidental's oil and gas segment;

    the ownership and operation of our power plants at Elk Hills Field and in the offshore portion of the Wilmington Field;

    the marketing and trading of crude oil and condensate, NGL, natural gas, water, steam and electricity produced in the operations described in the prior two bullet points; and

    certain activities and operations directly and exclusively supporting or exclusively conducted in respect of the business described in the prior three bullet points.

The Separation and Distribution Agreement will also provide that the California business will not include the existing third-party gas marketing business of Occidental's non-California midstream and marketing segment, which participates in various U.S. markets, including California.

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        Unless otherwise provided in the Separation and Distribution Agreement or any of the related ancillary agreements, all assets will be transferred on an "as is, where is" basis.

        The Separation and Distribution Agreement will require Occidental and us to endeavor to obtain consents, approvals and amendments required to novate or assign the assets and liabilities that are to be transferred pursuant to the Separation and Distribution Agreement as soon as reasonably practicable. Generally, if the transfer of any assets or liabilities requires a consent that will not be obtained before the distribution, or if any assets or liabilities are erroneously transferred or if any assets or liabilities are erroneously not transferred, each party will agree to hold the relevant assets or liabilities for the intended party's use and benefit (at the intended party's expense) until they can be transferred to the intended party.

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

        The Separation and Distribution Agreement will specify those conditions that must be satisfied or waived by Occidental, in its sole discretion, prior to the distribution, including the following conditions:

    the SEC will have declared effective our registration statement on Form 10, of which this information statement is a part, under the Exchange Act; no stop order suspending the effectiveness of the registration statement shall be in effect; and no proceedings for such purpose shall be pending before or threatened by the SEC;

    any required actions and filings with regard to state securities and blue sky laws of the U.S. (and any comparable laws under any foreign jurisdictions) will have been taken and, where applicable, have become effective or been accepted;

    our common stock will have been authorized for listing on the NYSE, or another national securities exchange approved by Occidental, subject to official notice of issuance;

    Occidental shall have received a private letter ruling from the IRS to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates, and such private letter ruling shall not have been revoked or modified in any material respect;

    Occidental shall have received an opinion of its tax counsel, in form and substance acceptable to Occidental and which shall remain in full force and effect, that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes and (ii) the spin-off generally qualifies as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code;

    no order, injunction, decree or regulation issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the distribution will be in effect;

    the completion of our new financing arrangements;

    no other events or developments shall have occurred or exist that, in the judgment of the board of directors of Occidental, in its sole discretion, makes it inadvisable to effect the distribution or other transactions contemplated by the Separation and Distribution Agreement;

    each of the ancillary agreements contemplated by the Separation and Distribution Agreement shall have been executed by each party thereto; and

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    any government approvals and other material consents necessary to consummate the distribution will have been obtained and remain in full force and effect.

        In addition, Occidental will have the right to determine the date and terms of the distribution, including payment by us of a special distribution of approximately $6.0 billion to Occidental, and will have the right, at any time until completion of the distribution, to determine to abandon or modify the distribution and to terminate or modify the Separation and Distribution Agreement.

Transition Services Agreement

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

Tax Sharing Agreement

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

        In general, pursuant to the Tax Sharing Agreement:

    CRC and Occidental will agree to cooperate in the preparation of tax returns, refund claims and with regard to audits concerning matters covered by the agreement;

    the Tax Sharing Agreement will assign responsibilities for administrative matters, such as the filing of tax returns, payment of taxes due, retention of records and conduct of audits, examinations, or similar proceedings;

    with respect to any periods (or portions thereof) ending prior to the distribution and periods that begin on or before but end after the distribution, Occidental will pay any U.S. federal income taxes of the affiliated group of which Occidental is the common parent and, if CRC (including any of its subsidiaries) is included in that affiliated group, CRC will pay Occidental an amount equal to the amount of U.S. federal income tax CRC would have paid had CRC filed a separate consolidated U.S. federal income tax return, subject to certain adjustments. With respect to any periods (or portions thereof) beginning after the distribution, CRC will be responsible for any U.S. federal income taxes of CRC and its subsidiaries;

    with respect to any periods (or portions thereof) ending prior to the distribution and periods that begin on or before but end after the distribution, Occidental will pay any U.S. state or local franchise or income taxes that are determined on a consolidated, combined, or unitary basis and, if CRC (including any of its subsidiaries) is included in such determination, CRC will pay Occidental an amount equal to the amount of tax CRC would have paid had CRC filed a separate return for such income, subject to certain adjustments;

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    with respect to any periods (or portions thereof) beginning after the distribution, CRC will be responsible for any U.S. state or local income taxes of CRC and its subsidiaries;

    Occidental will be responsible for any U.S. federal, state, local, or foreign taxes due with respect to tax returns that include only Occidental and/or its subsidiaries (excluding CRC and its subsidiaries), and CRC will be responsible for any U.S. federal, state, local or foreign taxes due with respect to tax returns that include only CRC and/or its subsidiaries;

    to the extent that any gain or income is recognized by Occidental (including its subsidiaries) in connection with the failure of the spin-off or certain transactions undertaken in preparation for, or in connection with, the spin-off, to qualify for tax-free treatment under the relevant provisions of the Code, CRC will indemnify Occidental for any taxes on such gain or income to the extent such failure is attributable to:

    inaccurate covenants, representations, or warranties by CRC (or any CRC subsidiaries) made in connection with the Tax Sharing Agreement or any tax ruling requested or received from the IRS or opinions of Occidental's outside tax advisors;

    any breach by CRC (or any CRC subsidiaries) of certain restrictive covenants in the Tax Sharing Agreement; or

    certain other actions taken by CRC; and

    CRC will bear 50% of the amount of any taxes resulting from gain or income that is recognized by Occidental (including its subsidiaries) in connection with the failure of the spin-off or a related transaction to qualify for tax-free treatment under the relevant provisions of the Code, to the extent such failure is not attributable to the fault of either party.

        Occidental has requested a private letter ruling from the IRS substantially to the effect that certain aspects of the transactions that will be undertaken in preparation for, or in connection with, the spin-off will not cause the distribution to be taxable to Occidental or its affiliates for federal income tax purposes. In addition, the spin-off is conditioned on Occidental's receipt of an opinion from its tax counsel, in form and substance acceptable to Occidental, that (i) certain transactions that will be undertaken in preparation for, or in connection with, the spin-off will not be taxable to Occidental or its affiliates for federal income tax purposes, and (ii) the spin-off generally qualifies as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code. The opinion will rely on the private letter ruling as to matters covered by the private letter ruling.

        CRC will agree to certain restrictions that are intended to preserve the tax-free status of the contribution, distribution, and related transactions. After Occidental's initial distribution of at least 80.1% of CRC common stock and during the two-year period following Occidental's final disposition of the Retained Securities, these covenants will restrict CRC's ability to: (a) voluntarily liquidate or dissolve; (b) merge, convert or consolidate with or into another entity; (c) issue any capital stock or other equity interests, options or rights to acquire capital stock or other equity interests, or any other instruments convertible into or exchangeable for, or that could otherwise result in the issuance of, capital stock or other equity interests; (d) redeem or otherwise repurchase any outstanding capital stock or other equity interests, rights or instruments, other than pursuant to open market stock repurchase programs meeting certain requirements; (e) recapitalize, reclassify, or alter the voting rights of one or more shares of capital stock or other equity interests, rights or instruments; (f) take certain other actions inconsistent with any representation made in any materials provided in connection with any private letter ruling request or opinions of Occidental's outside tax advisors; (g) increase or decrease the number of members of the board of directors of CRC or any pre-spin-off CRC subsidiary, alter in any way the procedures for the nomination, election, and termination of members of the board, or expand, contract, or otherwise modify the rights of the board to govern the affairs of CRC except in certain circumstances; (h) sell, exchange, distribute, or otherwise dispose of any pre-spin-off CRC subsidiary or all or a substantial part of the assets

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of any of the trades or businesses conducted by CRC and the pre-spin-off CRC subsidiaries (other than sales or transfers of inventory in the ordinary course of business) before the spin-off except in certain circumstances; (i) take, or fail to take, any action that causes the trades or businesses conducted by CRC or any pre-spin-off CRC subsidiary to cease to be actively conducted in substantially the manner conducted pre-spin-off; (j) sell, transfer or agree to sell or transfer to any corporate subsidiary any assets held by certain Occidental subsidiaries before Occidental's internal reorganization in connection with the spin-off; (k) enter into any negotiations, agreements, understandings, or arrangements with respect to any of the foregoing; and (l) take, or fail to take, any action that could reasonably be expected to cause the spin-off to fail to qualify as a tax-free transaction under Sections 355, 361 and/or 368(a)(1)(D) of the Code. CRC may take certain actions otherwise subject to these restrictions only if Occidental consents to the taking of such action or if CRC obtains, and provides to Occidental, a private letter ruling from the IRS and/or an opinion from an independent law firm or accounting firm, in either case, acceptable to Occidental in its sole discretion, to the effect that such action would not jeopardize the tax-free status of the contribution, distribution, or related transactions.

Employee Matters Agreement

        The Employee Matters Agreement will govern Occidental's and our compensation and employee benefit obligations with respect to the current and former employees of each company, and generally will allocate liabilities and responsibilities relating to employee compensation and benefit plans and programs. The Employee Matters Agreement will generally provide for the following:

    the transfer of all employees who, following the spin-off, will work for the California business ("transferred employees") to us or one of our subsidiaries;

    the assumption (or retention) by us and our subsidiaries of all liabilities and obligations relating to current and former employees of the California business (excluding, with respect to current employees, certain pension obligations and, with respect to former employees, certain pension, retiree medical and nonqualified deferred compensation plan obligations);

    the retention by Occidental of all employee and benefit plan-related liabilities and obligations not relating to current or former employees of the California business;

    the establishment by us and our subsidiaries of new employee benefit plans for purposes of providing benefits to transferred employees;

    the cessation of active participation by transferred employees under all benefit plans sponsored by Occidental;

    the conversion of Occidental equity and equity-based awards held by transferred employees into awards with respect to our common stock;

    the adjustment of Occidental equity and equity-based awards not held by transferred employees to reflect the effect of the spin-off;

    the transfer of all assets held in trusts maintained by Occidental which relate to benefits payable under certain defined benefit plans maintained by our subsidiaries to a trust (or trusts) maintained by the respective subsidiaries;

    the transfer of liabilities and other obligations relating to benefits accrued by transferred employees pursuant to Occidental's supplemental retirement and nonqualified deferred compensation plans from Occidental to us and our subsidiaries;

    that the spin-off is not intended to constitute a "change in control" or similar transaction under Occidental or our benefit and compensation plans;

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    the crediting of transferred employees for their service with Occidental for purposes of determining eligibility, vesting and benefit levels under our benefit plans; and

    general cooperation and sharing of information between us and Occidental on matters relating to the transfers of employees and employee benefit plan-related liabilities and obligations.

AMI Agreement

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

Confidentiality and Trade Secret Protection Agreement

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

Intellectual Property License Agreement

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

Stockholder's and Registration Rights Agreement

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

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OTHER RELATED PARTY TRANSACTIONS

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

Marketing Transactions

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

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

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

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

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

    the nature of the related person's interest in the transaction;

    the material terms of the transaction

    the importance of the transaction to the related person;

    the importance of the transaction to us;

    whether the transaction would impair the judgment of a director or executive officer to act or their ability to act in our best interest;

    whether the transaction might affect a director's independence under NYSE standards; and

    any other matters deemed appropriate with respect to the particular transaction.

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

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

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


DESCRIPTION OF MATERIAL INDEBTEDNESS

        In connection with the separation, we expect to incur an aggregate of $6.065 billion in new debt from which we will not retain any substantial amount of cash following the separation. We expect that this indebtedness will consist of long-term notes, term loans and borrowings under a revolving credit facility.

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

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

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DESCRIPTION OF CAPITAL STOCK

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

Authorized Capitalization

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

Common Stock

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

Preferred Stock

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

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

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

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

Delaware Law

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

    the transaction is approved by the board of directors before the time the interested stockholder attained that status;

    upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

    on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

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

Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

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

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

    establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not later than 90 days nor earlier than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws specify the requirements as to form and content of all stockholder notices. These requirements may preclude stockholders from bringing matters before

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      the stockholders at an annual or special meeting, and may discourage or deter a third party from conducting a solicitation of proxies to elect its slate of directors or to approve its proposal, without regard to whether consideration of those nominees or proposals might be harmful or beneficial to us and our stockholders;

    provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

    provide that our board of directors is initially divided into three classes, but that our classified board structure will be eliminated at our 2018 annual meeting, when stockholders will be permitted to elect all of our board members annually. The terms of our initial first class of directors will expire at our 2015 annual meeting of stockholders, and their successors will be elected for a three-year term. The terms of our initial second class of directors will expire at our 2016 annual meeting of stockholders, and their successors will be elected for a two-year term. The terms of our initial third class of directors will expire at our 2017 annual meeting of stockholders, and their successors will be elected for a one-year term. These provisions regarding the election of our board of directors may have the effect of deferring hostile takeovers or delaying changes in control or management of our company prior to our 2018 annual meeting;

    provide that (x) the authorized number of directors may be changed only by resolution of the board of directors, (y) all vacancies, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum, and (z) for so long as we have a classified board of directors, our stockholders will have no ability to remove our directors without cause, and that, upon the declassification of our board of directors, directors may be removed without cause by our stockholders only upon the affirmative vote of holders of at least 75% of the voting power of our then outstanding common stock. These provisions regarding the makeup of our board of directors may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

    provide that (x) any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series, and (y) special meetings of our stockholders may only be called by the board of directors, the chief executive officer or the chairman of the board. These provisions regarding our stockholder meetings may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

    provide that (x) certain provisions of our certificate of incorporation related to the voting rights of stockholders, our board of directors, special meetings of our stockholders, the ability of our stockholders to act by written consent and the forum for certain disputes related to us or our stockholders, may be amended only by the affirmative vote of the holders of at least 75% of the voting power of our then outstanding common stock and that other provisions of our certificate of incorporation may be amended upon the affirmative vote of the holders of at least a majority of our then outstanding common stock and the approval of a majority of our directors then in office, or otherwise only by the affirmative vote of the holders of at least 75% of the voting power of the shares of our then outstanding common stock and (y) our bylaws can be amended or repealed at any regular or special meeting of stockholders or by the board of directors, provided any amendment by the stockholders will be effective only upon the affirmative vote of the holders of at least 75% of the voting power of the shares of common stock outstanding and entitled to vote thereon. These provisions regarding the amendment of our constituent documents may have the effect of deferring hostile takeovers or delaying changes in control or management of our company.

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Forum Selection

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

    any derivative action or proceeding brought on our behalf;

    any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders;

    any action asserting a claim arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws (as either may be amended from time to time); or

    any action asserting a claim that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein.

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

Limitation of Liability and Indemnification Matters

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

    for any breach of their duty of loyalty to us or our stockholders;

    for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

    for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

    for any transaction from which the director derived an improper personal benefit.

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

        Our amended and restated bylaws also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person's actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We may from time to time enter into indemnification agreements with our directors and officers. These agreements will typically require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision in our amended and restated certificate of incorporation and any indemnification agreements we enter into will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Sale of Unregistered Securities

        Upon our incorporation, we issued 1,000 shares of our common stock, par value $0.01 per share, to Occidental upon payment by Occidental of $10.00 pursuant to Section 4(a)(2) of the Securities Act. We did

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not register the issuance of these shares under the Securities Act because such issuance did not constitute a public offering.

Transfer Agent and Registrar

        The transfer agent and registrar for our common stock is American Stock Transfer & Trust Company, LLC.

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

      Regular Mail: 6201 15 th Avenue, Brooklyn, NY 11219

      Telephone: (800) 937-5449

Listing

        Our common stock is expected to trade on the NYSE under the symbol "CRC."

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WHERE YOU CAN FIND MORE INFORMATION

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

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

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

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

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

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

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GLOSSARY OF TECHNICAL TERMS

%Ro or vitrinite reflectance

  A measurement of the maturity of organic matter with respect to whether it has generated hydrocarbons or could be an effective source rock.

100% commercial success rate

 

All wells were completed and produce in commercially viable quantities.

Basin

 

A large natural depression on the earth's surface in which sediments generally brought by water accumulate.

Bbl

 

One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

BBoe

 

One billion Boe.

Bcf

 

One billion cubic feet of natural gas.

Boe

 

One stock tank barrel of oil equivalent, using the ratio of six Mcf of natural gas to one barrel of crude oil.

BS

 

One barrel of steam, cold water equivalent.

Completion

 

The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

Condensate

 

A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Conventional
Reservoir

 

A reservoir in which buoyant forces keep hydrocarbons in place below a sealing caprock. Reservoir and fluid characteristics of conventional reservoirs typically permit oil or natural gas to flow readily into wellbores.

/d

 

Per day.

Development drilling or development wells

 

Drilling or wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Disposal well

 

A well utilized to dispose of excess produced fluids that are not reused in normal operations.

Economically Producible

 

A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

EOR

 

Enhanced oil recovery.

Exploration activities

 

The initial phase of oil and natural gas operations that includes the generation of a prospect or play and the drilling of an exploration well.

Exploration well

 

Refers to a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Extension Well

 

A well drilled to extend the limits of a known reservoir.

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Field

 

An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Formation

 

A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or gross wells

 

The total acres or wells, as applicable, in which a working interest is owned.

Infill drilling

 

Drilling of an additional well or wells at less than existing spacing to more adequately drain a reservoir.

Injection well

 

A well in which water, gas or steam is injected, the primary objective typically being to maintain reservoir pressure and/or improve hydrocarbon recovery.

IOR

 

Improved oil recovery.

Maximum Efficiency Rate

 

The maximum sustainable daily oil or gas withdrawal rate from a reservoir which will permit economic development and depletion of that reservoir without detriment to ultimate recovery.

MBbl

 

One thousand barrels.

MBoe

 

One thousand Boe.

Mcf

 

One thousand cubic feet of natural gas. For the purposes of this report, this volume is stated at the legal pressure base of the state or area in which the reserves are located and at 60 degrees Fahrenheit.

mD

 

One millidarcy.

MMBbl

 

One million barrels.

MMBoe

 

One million Boe.

MMBtu

 

One million British thermal units. A British thermal unit is the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

MMcf

 

One million cubic feet of natural gas. For the purposes of this report, this volume is stated at the legal pressure base of the state or area in which the reserves are located and at 60 degrees Fahrenheit.

Natural gas liquids or NGLs

 

Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

Net acres or net
wells

 

The gross acres or wells, as applicable, multiplied by the working interests owned.

NYMEX

 

The New York Mercantile Exchange.

Oil

 

Crude oil or condensate.

Pay zone

 

A geological deposit in which oil and natural gas is found in commercial quantities.

Permeability

 

The ability, or measurement of a rock's ability, to transmit fluids.

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Porosity

 

The total pore volume per unit volume of rock.

Primary Recovery

 

The first stage of hydrocarbon production, in which natural reservoir energy, such as gasdrive, waterdrive or gravity drainage, displaces hydrocarbons from the reservoir, into the wellbore and up to surface. During primary recovery, only a small percentage of the initial hydrocarbons in place are produced, typically around 10% for oil reservoirs. Primary recovery is also called primary production.

Productive Wells

 

Producing wells and wells mechanically capable of production.

Proved developed non-producing reserves

 

Proved developed reserves that do not qualify as proved developed producing reserves, including reserves that are expected to be recovered from (i) completion intervals that are open at the time of the estimate, but have not started producing, (ii) wells that are shut in because pipeline connections are unavailable or (iii) wells not capable of production for mechanical reasons.

Proved developed reserves

 

Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or for which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved developed producing reserves

 

Reserves that are being recovered through existing wells with existing equipment and operating methods.

Proved reserves or proved oil and gas reserves

 

Refers to the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved undeveloped reserves or PUDs

 

Undeveloped reserves that qualify as proved reserves.

PV-10

 

PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period.

Recompletion

 

The completion for production of an existing wellbore in a different formation or producing horizon, either deeper or shallower, from that in which the well was previously completed.

Secondary recovery

 

The second stage of hydrocarbon production during which a substance such as water or gas is injected into the reservoir through injection wells located in rock that has fluid communication with production wells. The purpose of secondary recovery is to support reservoir pressure and to displace hydrocarbons toward the wellbore.

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Shut in

 

A well suspended from production or injection but not abandoned.

Tcf

 

One trillion cubic feet of natural gas.

Thermal Maturity

 

The degree of heating of a source rock in the process of transforming kerogen into hydrocarbon.

Thickness

 

The thickness of a layer or stratum of sedimentary rock measured perpendicular to its lateral extent, presuming deposition on a horizontal surface.

Total Organic
Carbon

 

The concentration of organic material in source rocks as represented by the weight percent of organic carbon.

Unconventional Resource

 

Oil and gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs.

Undeveloped acreage

 

Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether the acreage contains proved oil or natural gas reserves.

Undeveloped reserves

 

Refers to reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Working interest

 

The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production, subject to all royalties, overriding royalties and other burdens, all costs of exploration, development and operations and all risks in connection therewith.

Workover

 

Remedial operations on a well conducted with the intention of restoring or increasing production from the same zone, including by plugging back, squeeze cementing, reperforating, cleanout and acidizing.

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INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION

 
  Page  

Interim unaudited combined condensed financial statements

       

Combined Condensed Balance Sheets as of June 30, 2014 and December 31, 2013 (unaudited)

    F-2  

Combined Condensed Statements of Income for the six months ended June 30, 2014 and 2013 (unaudited)

    F-3  

Combined Condensed Statements of Comprehensive Income for the six months ended June 30, 2014 and 2013 (unaudited)

    F-4  

Combined Condensed Statements of Cash Flows for the six months ended June 30, 2014 and 2013 (unaudited)

    F-5  

Notes to Combined Condensed Financial Statements (unaudited)

    F-6  

Annual audited combined financial statements

       

Report of Independent Registered Public Accounting Firm

    F-10  

Combined Balance Sheets as of December 31, 2013 and 2012

    F-11  

Combined Statements of Income for the Years Ended December 31, 2013, 2012 and 2011

    F-12  

Combined Statements of Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011

    F-13  

Combined Statements of Net Investment for the Years Ended December 31, 2013, 2012 and 2011

    F-14  

Combined Statement of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011

    F-15  

Notes to Combined Financial Statements

    F-16  

Supplemental Financial Information

       

Supplemental Oil and Gas Information (unaudited)

    F-33  

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CALIFORNIA RESOURCES CORPORATION

Combined Condensed Balance Sheets

(unaudited)

 
  June 30,
2014
  December 31,
2013
 
 
  (in millions)
 

CURRENT ASSETS

             

Cash and cash equivalents

  $   $  

Trade receivables, net

    21     30  

Inventories

    72     75  

Other current assets

    185     149  
           

Total current assets

    278     254  
           

PROPERTY, PLANT AND EQUIPMENT

    21,985     20,972  

Accumulated depreciation, depletion and amortization

    (7,551 )   (6,964 )
           

    14,434     14,008  
           

OTHER ASSETS

    34     35  
           

TOTAL ASSETS

  $ 14,746   $ 14,297  
           
           

CURRENT LIABILITIES

             

Accounts payable

  $ 504   $ 448  

Accrued liabilities

    175     241  
           

Total current liabilities

    679     689  
           

DEFERRED INCOME TAXES

    3,293     3,122  

OTHER LONG-TERM LIABILITIES

    500     497  
           

    3,793     3,619  

NET INVESTMENT

             

Accumulated other comprehensive income

    (22 )   (24 )

Net parent company investment

    10,296     10,013  
           

Total net investment

    10,274     9,989  
           

TOTAL LIABILITIES AND NET INVESTMENT

  $ 14,746   $ 14,297  
           
           

   

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

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CALIFORNIA RESOURCES CORPORATION

Combined Condensed Statements of Income

(unaudited)

 
  For the six
months ended
June 30,
 
 
  2014   2013  
 
  (in millions)
 

REVENUES

             

Net sales to related parties

  $ 2,206   $ 2,049  

Net sales to third parties

    56     49  

Other income

    (1 )    
           

    2,261     2,098  
           

COSTS AND OTHER DEDUCTIONS

             

Production costs

    578     527  

Selling, general and administrative expenses

    166     154  

Depreciation, depletion and amortization

    582     565  

Taxes other than on income

    107     109  

Exploration expense

    46     40  
           

    1,479     1,395  
           

INCOME BEFORE INCOME TAXES

    782     703  

Provision for income taxes

    (313 )   (281 )
           

NET INCOME

  $ 469   $ 422  
           
           

   

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

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CALIFORNIA RESOURCES CORPORATION

Combined Condensed Statements of Comprehensive Income

(unaudited)

 
  For the six
months
ended
June 30,
 
 
  2014   2013  
 
  (in millions)
 

 

 

 

 

 

 

 

 

Net income

  $ 469   $ 422  

Other comprehensive income (loss) items:

             

Unrealized losses on derivatives(a)

    (2 )    

Pension and postretirement gains(b)

    1     2  

Reclassification to income of realized losses (gains) on derivatives(c)

    3     (1 )
           

Other comprehensive income (loss), net of tax

    2     1  
           

Comprehensive income

  $ 471   $ 423  
           
           

(a)
Net of tax of $1 and zero in 2014 and 2013, respectively.

(b)
Net of tax of zero and $1 in 2014 and 2013, respectively. See Note 6, Retirement and Postretirement Benefit Plans, for additional information.

(c)
Net of tax of $(2) and zero in 2014 and 2013, respectively.

   

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

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CALIFORNIA RESOURCES CORPORATION

Combined Condensed Statements of Cash Flows

(unaudited)

 
  For the six
months ended
June 30,
 
 
  2014   2013  
 
  (in millions)
 

CASH FLOW FROM OPERATING ACTIVITIES

             

Net income

  $ 469   $ 422  

Adjustments to reconcile net income to net cash provided by operating activities:

             

Depreciation, depletion and amortization of assets

    582     565  

Deferred income tax provision

    178     126  

Other noncash charges to income

    21     27  

Dry hole expenses

    32     24  

Changes in operating assets and liabilities, net

    (48 )   13  
           

Net cash provided by operating activities

    1,234     1,177  
           

CASH FLOW FROM INVESTING ACTIVITIES

             

Capital expenditures

    (1,003 )   (737 )

Payments for purchases of assets and businesses, and other

    (35 )   (31 )
           

Net cash used by investing activities

    (1,038 )   (768 )
           

CASH FLOW FROM FINANCING ACTIVITIES

             

Distributions to parent company

    (196 )   (409 )
           

Net cash used by financing activities

    (196 )   (409 )
           

Increase (decrease) in cash and cash equivalents

         

Cash and cash equivalents—beginning of period

         
           

Cash and cash equivalents—end of period

  $   $  
           
           

   

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

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Condensed Financial Statements

(unaudited)

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

The Separation and Spin-Off

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

        The separation will be completed through a spin-off that is being executed in accordance with a separation and distribution agreement and several other agreements between us and Occidental. The spin-off is intended to be tax-free to the stockholders of Occidental and to Occidental and us for United States federal income tax purposes. Occidental intends to distribute, on a pro-rata basis, at least 80.1% of the outstanding shares of our common stock to the Occidental stockholders as of the record date for the spin-off. Upon completion of the spin-off, which does not require shareholder approval, we will be an independent, stand-alone company from Occidental. The spin-off is, among other things, subject to final approval by Occidental's board of directors, receipt of a private letter ruling from the Internal Revenue Service regarding certain aspects of the spin-off and an opinion of tax counsel, with respect to the tax-free nature of the spin-off for federal income tax purposes, the registration statement on Form 10 being declared effective and the execution of the separation and distribution and related agreements.

        We were incorporated in Delaware as a wholly-owned subsidiary of Occidental on April 23, 2014. We are an oil and gas exploration and production company operating properties exclusively within the state of California, with integrated organization and infrastructure to gather, process and market our production.

Basis of Presentation

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

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

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Condensed Financial Statements (Continued)

(unaudited)

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

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

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

        In the opinion of our management, the accompanying combined condensed financial statements contain all adjustments (consisting of normal recurring adjustments) necessary to fairly present our combined condensed financial position as of June 30, 2014, and the combined condensed statements of income, comprehensive income and cash flows for the six months ended June 30, 2014 and 2013, as applicable. The income and cash flows for the periods ended June 30, 2014 and 2013 are not necessarily indicative of the income or cash flows to be expected for the full year.

        Events and transactions subsequent to the balance sheet date have been evaluated through August 18, 2014, the date these combined condensed financial statements were issued, for potential recognition or disclosure in the combined condensed financial statements.

NOTE 2    INVENTORIES

        Inventories as of June 30, 2014 and December 31, 2013, consisted of the following (in millions):

 
  2014   2013  

Materials and supplies

    69     73  

Finished goods

    3     2  
           

Total

  $ 72   $ 75  
           
           

NOTE 3    OTHER INFORMATION

        Other current assets include amounts due from joint venture partners of approximately $135 million and $97 million at June 30, 2014 and December 31, 2013, respectively. Other long-term liabilities include asset retirement obligations of $385 million and $388 million at June 30, 2014 and December 31, 2013, respectively.

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Condensed Financial Statements (Continued)

(unaudited)

NOTE 4    DERIVATIVES

Objective & Strategy

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

Cash-Flow Hedges

        We entered into financial swap agreements in November 2012 for the sale of a portion of our natural gas production. These swap agreements hedged 50 MMcf of natural gas per day beginning in January 2013 through March 2014 and qualified as cash-flow hedges. The weighted-average strike price of these swaps was $4.30. The gross and net fair values of these derivatives as of June 30, 2014 and December 31, 2013 were not material, as determined using Level 2 inputs in the fair value hierarchy.

        The after-tax gains and losses recognized in, and reclassified to income from, Accumulated Other Comprehensive Income (AOCI) for derivative instruments classified as cash-flow hedges for the six month periods ended June 30, 2014 and 2013, and the ending AOCI balances for each period were not material. The gains and losses reclassified to income were recognized in net sales, and the amount of the ineffective portion of cash-flow hedges was immaterial for the six months ended June 30, 2014 and 2013.

        There were no fair value hedges as of and during the six month periods ended June 30, 2014 and 2013.

NOTE 5    LAWSUITS, CLAIMS AND CONTINGENCIES

        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 June 30, 2014 and December 31, 2013, were not material to our balance sheets. We also evaluate the amount of reasonably possible losses that we could incur as a result of these matters. We believe that reasonably possible losses that we could incur in excess of reserves accrued on the balance sheet would not be material to our financial position or results of operations.

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

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Condensed Financial Statements (Continued)

(unaudited)

NOTE 6    RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

        The following table sets forth the components of the net periodic benefit costs for our defined benefit pension and postretirement benefit plans for the six months ended June 30, 2014 and 2013 (in millions):

 
  2014   2013  
Net Periodic Benefit Costs
  Pension Benefits   Postretirement
Benefits
  Pension Benefits   Postretirement
Benefits
 

Service cost

  $ 2   $ 2   $ 2   $ 2  

Interest cost

    2     2     2     2  

Expected return on plan assets

    (3 )       (2 )    

Recognized actuarial loss

    1         2     1  
                   

Total

  $ 2   $ 4   $ 4   $ 5  
                   
                   

        We did not make any contributions in either of the six-month periods ended June 30, 2014 and 2013, to our defined benefit pension plans.

NOTE 7    RELATED-PARTY TRANSACTIONS

        During the periods ended June 30, 2014 and 2013, we entered into the following related-party transactions (in millions):

 
  2014   2013  

Sales

  $ 2,206   $ 2,049  

Allocated costs for services provided by affiliates

  $ 77   $ 61  

Purchases

  $ 119   $ 86  

        Substantially all of our products were historically sold to Occidental's marketing subsidiaries at market prices and have been settled at the time of sale to those entities. For each of the periods ended June 30, 2014 and 2013, sales to Occidental subsidiaries accounted for approximately 98% of our net sales.

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

        Purchases from related parties reflect products purchased at market prices from Occidental's subsidiaries and are used in our operations. These purchases are included in production costs. There are no significant related party receivable or payable balances at June 30, 2014 and 2013.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders
Occidental Petroleum Corporation:

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

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

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

  /s/ KPMG LLP

Los Angeles, California
June 2, 2014

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California Resources Corporation

Combined Balance Sheets

As of December 31, 2013 and 2012

 
  2013   2012  
 
  (in millions)
 

CURRENT ASSETS

             

Cash and cash equivalents

  $   $  

Trade receivables, net

    30     22  

Inventories

    75     81  

Other current assets

    149     142  
           

Total current assets

    254     245  
           

PROPERTY, PLANT AND EQUIPMENT

    20,972     19,324  

Accumulated depreciation, depletion and amortization

    (6,964 )   (5,825 )
           

    14,008     13,499  
           

OTHER ASSETS

    35     20  
           

TOTAL ASSETS

  $ 14,297   $ 13,764  
           
           

CURRENT LIABILITIES

             

Accounts payable

  $ 448   $ 371  

Accrued liabilities

    241     180  
           

Total current liabilities

    689     551  
           

DEFERRED INCOME TAXES

    3,122     2,842  

OTHER LONG-TERM LIABILITIES

    497     511  
           

    3,619     3,353  
           

CONTINGENT LIABILITIES AND COMMITMENTS

             

NET INVESTMENT

   
9,989
   
9,860
 
           

TOTAL LIABILITIES AND NET INVESTMENT

  $ 14,297   $ 13,764  
           
           

   

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

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California Resources Corporation

Combined Statements of Income

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

 
  2013   2012   2011  
 
  (in millions)
 

REVENUES AND OTHER INCOME

                   

Net sales to related parties

  $ 4,174   $ 3,970   $ 3,862  

Net sales to third parties

    111     102     76  

Other income

    (1 )   1     (4 )
               

    4,284     4,073     3,934  
               

COSTS AND OTHER DEDUCTIONS

                   

Production costs

    1,066     1,314     1,074  

Selling, general and administrative expenses

    326     296     287  

Depreciation, depletion and amortization

    1,144     926     675  

Asset impairments and related items

        41      

Taxes other than on income

    185     167     143  

Exploration expense

    116     148     114  
               

    2,837     2,892     2,293  
               

INCOME BEFORE INCOME TAXES

    1,447     1,181     1,641  

Provision for income taxes

    (578 )   (482 )   (670 )
               

NET INCOME

  $ 869   $ 699   $ 971  
               
               

   

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

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California Resources Corporation

Combined Statements of Comprehensive Income

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

 
  2013   2012   2011  
 
  (in millions)
 

Net income

  $ 869   $ 699   $ 971  

Other comprehensive income (loss) items:

                   

Unrealized (losses) gains on derivatives(a)

    (2 )   3      

Pension and postretirement gains (losses)(b)

    27     2     (10 )

Reclassification to income of realized (gains) losses on derivatives(c)

    (2 )        
               

Other comprehensive income (loss), net of tax

    23     5     (10 )
               

Comprehensive income

  $ 892   $ 704   $ 961  
               
               

(a)
Net of tax of $1, $(1) and zero in 2013, 2012 and 2011, respectively.

(b)
Net of tax of $(16), $(1) and $6 in 2013, 2012 and 2011, respectively. See Note 10, Retirement and Postretirement Benefit Plans, for additional information.

(c)
Net of tax of $1, zero and zero in 2013, 2012 and 2011, respectively.

   

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

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California Resources Corporation

Combined Statements of Net Investment

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

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

Balance, December 31, 2010

  $ (42 ) $ 6,599   $ 6,557  

Net income

        971     971  

Other comprehensive loss, net of tax

    (10 )       (10 )

Net contributions from parent company

        1,106     1,106  
               

Balance, December 31, 2011

  $ (52 ) $ 8,676   $ 8,624  

Net income

        699     699  

Other comprehensive income, net of tax

    5         5  

Net contributions from parent company

        532     532  
               

Balance, December 31, 2012

  $ (47 ) $ 9,907   $ 9,860  

Net income

        869     869  

Other comprehensive income, net of tax

    23         23  

Net distributions to parent company

        (763 )   (763 )
               

Balance, December 31, 2013

  $ (24 ) $ 10,013   $ 9,989  
               
               

   

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

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CALIFORNIA RESOURCES CORPORATION

Combined Statements of Cash Flows

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

 
  2013   2012   2011  
 
  (in millions)
 

CASH FLOW FROM OPERATING ACTIVITIES

                   

Net income

  $ 869   $ 699   $ 971  

Adjustments to reconcile net income to net cash provided by operating activities:

                   

Depreciation, depletion and amortization of assets

    1,144     926     675  

Deferred income tax provision

    260     603     586  

Other noncash charges to income

    29     28     27  

Asset impairments and related items

        41      

Dry hole expenses

    72     128     74  

Changes in operating assets and liabilities:

                   

(Increase) decrease in trade receivables, net

    (8 )   20     (31 )

Decrease (increase) in inventories

    8     (23 )   (2 )

Decrease (increase) in other current assets

    2     (49 )   (15 )

Increase (decrease) in accounts payable and accrued liabilities

    100     (150 )   171  
               

Net cash provided by operating activities

    2,476     2,223     2,456  
               

CASH FLOW FROM INVESTING ACTIVITIES

                   

Capital expenditures

    (1,669 )   (2,331 )   (2,164 )

Payments for purchases of assets and businesses

    (48 )   (427 )   (1,405 )

Other, net

    4     3     4  
               

Net cash used by investing activities

    (1,713 )   (2,755 )   (3,565 )
               

CASH FLOW FROM FINANCING ACTIVITIES

                   

(Distributions to) contributions from parent company

    (763 )   532     1,106  
               

Net cash (used) provided by financing activities

    (763 )   532     1,106  
               

Increase (decrease) in cash and cash equivalents

            (3 )

Cash and cash equivalents—beginning of year

            3  
               

Cash and cash equivalents—end of year

  $   $   $  
               
               

   

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

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements

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

The Separation and Spin-Off

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

        The separation will be completed through a spin-off that is being executed in accordance with a separation and distribution agreement and several other agreements between us and Occidental. The spin-off is intended to be tax-free to the stockholders of Occidental and to Occidental and us for United States federal income tax purposes. Occidental intends to distribute, on a pro-rata basis, at least 80.1% of the outstanding shares of our common stock to the Occidental stockholders as of the record date for the spin-off. Upon completion of the spin-off, which does not require shareholder approval, we will be an independent, stand-alone company from Occidental. The spin-off is, among other things, subject to final approval by Occidental's board of directors, receipt of a private letter ruling from the Internal Revenue Service regarding certain aspects of the spin-off and an opinion of tax counsel, with respect to the tax-free nature of the spin-off for federal income tax purposes, the registration statement on Form 10 being declared effective and the execution of the separation and distribution and related agreements.

        We were incorporated in Delaware as a wholly-owned subsidiary of Occidental on April 23, 2014. We are an oil and gas exploration and production company operating properties exclusively within the state of California, with integrated organization and infrastructure to gather, process and market our production.

Basis of Presentation

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

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

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

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

have been incurred if we had been a stand-alone company would depend on multiple factors, including organizational structure and strategic and operating decisions.

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

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

Risks and Uncertainties

        The process of preparing financial statements in conformity with United States generally accepted accounting principles (GAAP) requires management to make informed estimates and judgments regarding certain types of financial statement balances and disclosures. Such estimates primarily relate to unsettled transactions and events as of the date of the combined financial statements and judgments on expected outcomes as well as the materiality of transactions and balances. Changes in facts and circumstances or discovery of new information relating to such transactions and events may result in revised estimates and judgments and actual results may differ from estimates upon settlement. Management believes that these estimates and judgments provide a reasonable basis for the fair presentation of our financial statements.

Revenue Recognition

        We recognize revenue from oil and gas production when title has passed from us to the transportation company or the customer, as applicable. We recognize our share of revenues net of any royalties and other third-party share.

Net Investment

        In our combined balance sheets, net investment represents Occidental's historical investment in us, our accumulated net income and the net effect of transactions with, and allocations from, Occidental.

Inventories

        Materials and supplies are valued at weighted-average cost and are reviewed periodically for obsolescence. Finished goods include oil and gas products, which are valued at the lower of cost or market.

Property, Plant and Equipment

        The carrying value of our property, plant and equipment (PP&E) represents the cost incurred to acquire or develop the asset, including any asset retirement obligations, net of accumulated depreciation, depletion and amortization (DD&A) and any impairment charges. For assets acquired, PP&E cost is based

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

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

on fair values at the acquisition date. Asset retirement obligations are capitalized and amortized over the lives of the related assets.

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

        The following table summarizes the activity of capitalized exploratory well costs for continuing operations for the years ended December 31:

 
  2013   2012   2011  
 
  (in millions)
 

Balance—Beginning of Year

  $ 18   $ 63   $ 24  

Additions to capitalized exploratory well costs pending the determination of proved reserves

    46     62     85  

Reclassifications to property, plant and equipment based on the determination of proved reserves

    (31 )   (61 )   (34 )

Capitalized exploratory well costs charged to expense

    (15 )   (46 )   (12 )
               

Balance—End of Year

  $ 18   $ 18   $ 63  
               
               

        We expense annual lease rentals, the costs of injection used in production and exploration, geological, geophysical and seismic costs as incurred. Cost of maintenance and repairs are expensed as incurred, except that the costs of replacements that expand capacity or add proven oil and gas reserves are capitalized.

        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. Substantially all of our total depreciation, depletion and amortization expense relates to production costs.

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

        Our gas plant and power plant assets are depreciated over the estimated useful lives of the assets, using the straight-line method, with expected useful lives of the assets ranging from 2 to 30 years. Other

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

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

property and equipment is depreciated using the straight-line method based on expected lives of the individual assets or group of assets ranging from two to 20 years.

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

        A portion of the carrying value of our oil and gas properties is attributable to unproved properties. At December 31, 2013, the net capitalized costs attributable to unproved properties were approximately $900 million. The unproved amounts are not subject to DD&A until they are classified as proved properties. As exploration and development work progresses, if reserves on these properties are proved, capitalized costs attributable to the properties become subject to DD&A. If the exploration and development work were to be unsuccessful, or management decided not to pursue development of these properties as a result of lower commodity prices, higher development and operating costs, contractual conditions or other factors, the capitalized costs of the related properties would be expensed. The timing of any writedowns of these unproved properties, if warranted, depends upon management's plans, the nature, timing and extent of future exploration and development activities and their results. In 2012, management decided not to pursue development of certain of our gas properties which were impacted by persistently low gas prices. As a result, we recorded an impairment charge in 2012, which is reflected in asset impairments and related charges in the combined statement of income. We believe the current plans and exploration and development efforts will allow us to realize the unproved property balance.

        We perform impairment tests on our infrastructure assets whenever events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows that would indicate that the carrying amount may not be recoverable, or when management's plans change with respect to those assets. Any impairment loss would be calculated as the excess of the asset's net book value over its estimated fair value.

Asset Retirement Obligations

        We recognize the fair value of asset retirement obligations in the period in which a determination is made that a legal obligation exists to dismantle an asset and reclaim or remediate the property at the end of its useful life and the cost of the obligation can be reasonably estimated. The liability amounts are based on future retirement cost estimates and incorporate many assumptions such as time to abandonment, technological changes, future inflation rates and the risk-adjusted discount rate. When the liability is initially recorded, we capitalize the cost by increasing the related PP&E balances. If the estimated future cost of the asset retirement obligation changes, we record an adjustment to both the asset retirement obligation and PP&E. Over time, the liability is increased and expense is recognized for accretion, and the capitalized cost is depreciated over the useful life of the asset.

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

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

        At certain of our facilities, we have identified asset retirement obligations that are related mainly to plant and field decommissioning, including plugging and abandonment of wells. We do not know or cannot estimate when we may settle these obligations. Therefore, we cannot reasonably estimate the fair value of these liabilities. We will recognize these asset retirement obligations in the periods in which sufficient information becomes available to reasonably estimate their fair values. Additionally, for certain plants, we do not have a legal obligation to decommission them and accordingly we have not recorded a liability.

        The following table summarizes the activity of the asset retirement obligation, of which $388 million and $367 million is included in other long-term liabilities, with the remaining current portion in accrued liabilities at December 31, 2013 and 2012, respectively.

 
  For the years
ended
December 31,
 
 
  2013   2012  
 
  (in millions)
 

Beginning balance

  $ 387   $ 327  

Liabilities incurred—capitalized to PP&E

    25     24  

Liabilities settled and paid

    (9 )   (12 )

Accretion expense

    21     18  

Acquisitions, dispositions and other—changes in PP&E

    (2 )    

Revisions to estimated cash flows—changes in PP&E

    (7 )   30  
           

Ending balance

  $ 415   $ 387  
           
           

Derivative Instruments

        Derivatives are carried at fair value and on a net basis when a legal right of offset exists with the same counterparty. We apply hedge accounting when transactions meet specified criteria for cash-flow hedge treatment and management elects and documents such treatment. Otherwise, any fair value gains or losses are recognized in earnings in the current period. For cash-flow hedges, the gain or loss on the effective portion of the derivative is reported as a component of other comprehensive income (OCI) with an offsetting adjustment to the basis of the item being hedged. Realized gains or losses from cash-flow hedges, and any ineffective portion, are recorded as a component of net sales in the combined statements of income. Ineffectiveness is primarily created by a lack of correlation between the hedged item and the hedging instrument due to location, quality, grade or changes in the expected quantity of the hedged item. Gains and losses from derivative instruments are reported net in the combined statements of income.

        A hedge is regarded as highly effective such that it qualifies for hedge accounting if, at inception and throughout its life, we expect that changes in the fair value or cash flows of the hedged item will be offset by 80 to 125 percent of the changes in the fair value or cash flows, respectively, of the hedging instrument. In the case of hedging a forecast transaction, the transaction must be probable and must present an exposure to variations in cash flows that could ultimately affect reported net income or loss. We discontinue hedge accounting when we determine that a derivative has ceased to be highly effective as a hedge; when the hedged item matures or is sold or repaid; or when a forecast transaction is no longer deemed probable.

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

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

Retirement and Postretirement Benefit Plans

        A majority of our employees participated in postretirement benefit plans sponsored by Occidental, which included participants from other Occidental subsidiaries. These plans do not have any assets and are funded as benefits are paid. We recognized a liability in the accompanying balance sheets for the employees of the California operations. The related postretirement expenses were allocated to us from Occidental based on headcount.

        For defined benefit pension and postretirement plans that are sponsored by us, we recognize the net overfunded or underfunded amounts in the financial statements using a December 31 measurement date.

        We determine our defined benefit pension and postretirement benefit plan obligations based on various assumptions and discount rates. The discount rate assumptions used are meant to reflect the interest rate at which the obligations could effectively be settled on the measurement date. We estimate the rate of return on assets with regard to current market factors but within the context of historical returns.

        Pension plan assets are measured at fair value. Common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds are valued using quoted market prices in active markets when available. When quoted market prices are not available, these investments are valued using pricing models with observable inputs from both active and non-active markets. Common and collective trusts are valued at the fund units' net asset value (NAV) provided by the issuer, which represents the quoted price in a non-active market. Short-term investment funds are valued at the fund units' NAV provided by the issuer.

        Actuarial gains and losses that have not yet been recognized through income are recorded in accumulated other comprehensive income within net investment, net of taxes, until they are amortized as a component of net periodic benefit cost.

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 measurements, maximize our use of observable inputs and minimize use of unobservable inputs. We generally use an income approach to measure fair value when observable inputs are unavailable. This approach utilizes management's judgments regarding expectations of projected cash flows and discounts those cash flows using a risk-adjusted discount rate.

        Cash flow hedges are carried at fair value. We utilize the mid-point between bid and ask prices for valuing these instruments. In addition to using market data in determining these fair values, we make assumptions about the risks inherent in the inputs to the valuation technique. These instruments are Over-the-Counter (OTC) bilateral financial commodity contracts, which are generally valued using quotations provided by brokers. Substantially all of these inputs are observable data or are supported by observable prices at which transactions are executed in the marketplace. We classify these measurements as Level 2.

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Table of Contents


CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

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

        The carrying amounts of on-balance-sheet financial instruments approximate fair value.

Other current assets

        Other current assets include amounts due from joint venture partners of approximately $97 million and $71 million at December 31, 2013 and 2012, respectively.

Accrued liabilities

        Accrued liabilities include accrued compensation-related costs of approximately $70 million and $50 million at December 31, 2013 and 2012, respectively.

Supplemental Cash Flow Information

        We have not made United States federal and state income tax payments directly to taxing jurisdictions; rather, our share of our parent's tax payments or refunds were paid or received, as applicable, by our parent and are reflected as part of the net parent company investment. Such amounts paid during the year ended December 31, 2013 and 2011 were approximately $318 million and $84 million, respectively, while the year ended December 31, 2012 resulted in a net refund of approximately $121 million. We also paid taxes other than on income, consisting mostly of property taxes, of approximately $185 million, $171 million and $143 million during the years ended December 31, 2013, 2012 and 2011, respectively.

Income taxes

        Our taxable income was historically included in the consolidated U.S. federal income tax returns of Occidental Petroleum Corporation and in a number of their consolidated state income tax returns. In the accompanying combined financial statements, our provision for income taxes is computed as if we were a stand-alone tax-paying entity.

        Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income.

NOTE 2    ACQUISITIONS

2013

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

2012

        During the year ended December 31, 2012, we paid approximately $380 million for oil and gas properties, almost all of which was allocated to PP&E, including an acquisition for $275 million for certain

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 2    ACQUISITIONS (Continued)

producing and non-producing assets in the Sacramento basin and undeveloped acreage in the San Joaquin basin.

2011

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

NOTE 3    ACCOUNTING AND DISCLOSURE CHANGES

Recently Adopted Accounting and Disclosure Changes

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

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

NOTE 4    INVENTORIES

        Inventories consisted of the following:

 
  Balance at
December 31,
 
 
  2013   2012  
 
  (in millions)
 

Materials and supplies

  $ 73   $ 77  

Finished goods

    2     4  
           

Total

  $ 75   $ 81  
           
           

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 5    LEASE COMMITMENTS

        We have entered into various operating lease agreements, mainly for office equipment, field equipment and office space. We lease assets when leasing offers greater operating flexibility. Lease payments are generally expensed as part of production costs or selling, general and administrative expenses. At December 31, 2013, future net minimum lease payments for noncancelable operating leases (excluding oil and gas and other mineral leases, utilities, taxes, insurance and maintenance expense) totaled:

 
  Amount  
 
  (in millions)
 

2014

  $ 9  

2015

    6  

2016

    5  

2017

    5  

2018

    4  

Thereafter

    4  
       

Total minimum lease payments

  $ 33  
       
       

        Rental expense for operating leases was $11 million in 2013, $12 million in 2012 and $8 million in 2011.

NOTE 6    DERIVATIVES

Objective & Strategy

        We only occasionally hedge our oil and gas production, and, when we do so, the volumes are usually insignificant. Refer to Note 1 for our accounting policy on derivatives.

Cash-Flow Hedges

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

        The after-tax gains and losses recognized in, and reclassified to income from, Accumulated Other Comprehensive Income (AOCI), for derivative instruments classified as cash-flow hedges for the year ended December 31, 2013 and 2012, and the ending AOCI balances for each period were not material. We expect to reclassify an insignificant amount, based on the valuation as of December 31, 2013, of net after-tax derivative losses from AOCI into income during the next 12 months. We recognized gains and losses reclassified to income in net sales. The amount of the ineffective portion of cash-flow hedges was immaterial for the year ended December 31, 2013 and 2012.

        There were no fair value hedges as of and during the years ended December 31, 2013, 2012 and 2011.

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 7    LAWSUITS, CLAIMS, COMMITMENTS AND CONTINGENCIES

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

        We have certain commitments under contracts, including purchase commitments for goods and services. At December 31, 2013, total purchase obligations were approximately $650 million, which included approximately $250 million, $80 million, $40 million, $30 million and $230 million that will be paid in 2014, 2015, 2016, 2017 and 2018, respectively. Included in the purchase obligations are commitments for major fixed and determinable capital expenditures during 2014 and thereafter, which were approximately $270 million.

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

NOTE 8    INCOME TAXES

        Income before income taxes was as follows:

For the years ended December 31,
  (in millions)  

2013

  $ 1,447  
       
       

2012

  $ 1,181  
       
       

2011

  $ 1,641  
       
       

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 8    INCOME TAXES (Continued)

        The provisions (credits) for federal, state and local income taxes consisted of the following:

For the years ended December 31,
  United States
Federal
  State
and Local
  Total  
 
  (in millions)
 

2013

                   

Current

  $ 227   $ 91   $ 318  

Deferred

    222     38     260  
               

  $ 449   $ 129   $ 578  
               
               

2012

                   

Current

  $ (140 ) $ 19   $ (121 )

Deferred

    518     85     603  
               

  $ 378   $ 104   $ 482  
               
               

2011

                   

Current

  $ 22   $ 62   $ 84  

Deferred

    504     82     586  
               

  $ 526   $ 144   $ 670  
               
               

        The following reconciliation of the United States federal statutory income tax rate to our effective tax rate is stated as a percentage of pre-tax income:

 
  For the years ended
December 31,
 
 
  2013   2012   2011  

United States federal statutory tax rate

    35 %   35 %   35 %

State income taxes, net of federal benefit

    6     6     6  

Other

    (1 )        
               

Effective tax rate

    40 %   41 %   41 %
               
               

        The tax effects of temporary differences resulting in deferred income taxes at December 31, 2013 and 2012 were as follows:

 
  2013   2012  
Tax effects of temporary differences
  Deferred Tax
Assets
  Deferred Tax
Liabilities
  Deferred Tax
Assets
  Deferred Tax
Liabilities
 
 
  (in millions)
 

Property, plant and equipment differences

  $   $ (3,583 ) $   $ (3,270 )

Postretirement benefit accruals

    14         28      

Deferred compensation and benefits

    60         46      

Asset retirement obligations

    182         170      

Federal benefit of state income taxes

    208         170      

All other

    22     (2 )   31     (2 )
                   

Total deferred taxes

  $ 486   $ (3,585 ) $ 445   $ (3,272 )
                   
                   

        The current portion of total deferred tax assets was $23 million and $15 million as of December 31, 2013 and 2012, respectively, which was reported in other current assets. The noncurrent portion of total deferred tax assets was reported net against deferred tax liabilities. We expect to realize the recorded deferred tax assets through future operating income and reversal of temporary differences.

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 9    ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

        Accumulated other comprehensive loss consisted of the following after-tax amounts:

 
  Balance at
December 31,
 
 
  2013   2012  
 
  (in millions)
 

Unrealized losses (gains) on derivatives

    (1 )   3  

Pension and post-retirement adjustments(a)

    (23 )   (50 )
           

Total

  $ (24 ) $ (47 )
           
           

(a)
See Note 10 for further information.

NOTE 10    RETIREMENT AND POSTRETIREMENT BENEFIT PLANS

        As discussed in Note 1, a majority of our employees participated in postretirement benefit plans sponsored by Occidental, which included participants of other Occidental subsidiaries and certain employees were part of pension and postretirement plans sponsored by us.

Defined Contribution Plans

        All of our employees were eligible to participate in one or more of the defined contribution retirement or savings plans that provide for periodic contributions by us, our subsidiaries or Occidental, based on plan-specific criteria, such as base pay, age, level and employee contributions. Certain salaried employees participated in a supplemental retirement plan that restored benefits lost due to governmental limitations on qualified retirement benefits. The accrued liabilities for the supplemental retirement plan were $17 million and $11 million as of December 31, 2013 and 2012, respectively, and we expensed $34 million in 2013, $35 million in 2012 and $31 million in 2011 under the provisions of these defined contribution and supplemental retirement plans.

Defined Benefit Plans

        Participation in defined benefit pension and postretirement plans sponsored by us is limited. Approximately 270 employees, mainly union, nonunion hourly and certain employees that joined us from acquired operations with grandfathered benefits, are currently accruing benefits under these plans.

        Pension costs for the defined benefit pension plans, determined by independent actuarial valuations, are generally funded by payments to trust funds, which are administered by independent trustees.

Postretirement and Other Benefit Plans

        We provided postretirement medical and dental benefits and life insurance coverage for our employees not covered by our sponsored plans and their eligible dependents through Occidental sponsored plans. The benefits were generally funded as they were paid during the year. These benefit costs were approximately $18 million in 2013, $17 million in 2012 and $12 million in 2011.

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 10    RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Continued)

Obligations and Funded Status

        The following tables show the amounts recognized in our combined balance sheets related to pension and postretirement benefit plans, including our share of obligations for Occidental-sponsored plans as well as plans that we or our subsidiaries sponsor, and their funding status, obligations and plan asset fair values (in millions):

 
  Pension
Benefits
  Postretirement
Benefits
 
 
  As of December 31,  
 
  2013   2012   2013   2012  

Amounts recognized in the consolidated balance sheet:

                         

Accrued liabilities

  $   $   $ (1 ) $ (1 )

Other long-term liabilities

    (12 )   (34 )   (62 )   (73 )
                   

  $ (12 ) $ (34 ) $ (63 ) $ (74 )
                   
                   

AOCI included the following after-tax balances:

                         

Net loss

  $ 19   $ 31   $ 4   $ 19  
                   
                   

 

 
  Pension
Benefits
  Postretirement
Benefits
 
 
  For the years ended
December 31,
 
 
  2013   2012   2013   2012  

Changes in the benefit obligation:

                         

Benefit obligation—beginning of year

  $ 108   $ 108   $ 74   $ 67  

Service cost—benefits earned during the period

    5     4     4     4  

Interest cost on projected benefit obligation

    3     4     3     3  

Actuarial (gain) loss

    (2 )   7     (18 )    

Benefits paid

    (11 )   (15 )        
                   

Benefit obligation—end of year

  $ 103   $ 108   $ 63   $ 74  
                   

Changes in plan assets:

                         

Fair value of plan assets—beginning of year

  $ 74   $ 70   $   $  

Actual return on plan assets

    13     7          

Employer contributions

    15     12          

Benefits paid

    (11 )   (15 )        
                   

Fair value of plan assets—end of year

  $ 91   $ 74   $   $  
                   

(Unfunded) status:

  $ (12 ) $ (34 ) $ (63 ) $ (74 )
                   
                   

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 10    RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Continued)

        The following table sets forth the accumulated and projected benefit obligations and fair values of assets of the defined benefit pension plans:

 
  Accumulated
Benefit
Obligation
in Excess of
Plan Assets
  Plan Assets
in Excess of
Accumulated
Benefit
Obligation
 
 
  As of December 31,  
 
  2013   2012   2013   2012  
 
  (in millions)
 

Projected Benefit Obligation

  $ 30   $ 108   $ 73   $  

Accumulated Benefit Obligation

  $ 25   $ 85   $ 58   $  

Fair Value of Plan Assets

  $ 23   $ 74   $ 68   $  

        We do not expect any plan assets to be returned during 2014.

COMPONENTS OF NET PERIODIC BENEFIT COST

        The following table sets forth the components of net periodic benefit costs:

 
  Pension
Benefits
  Postretirement
Benefits
 
 
  For the years ended December 31,  
 
  2013   2012   2011   2013   2012   2011  
 
  (in millions)
 

Net periodic benefit costs:

                                     

Service cost—benefits earned during the period

  $ 5   $ 4   $ 4   $ 5   $ 4   $ 3  

Interest cost on projected benefit obligation

    3     4     5     3     3     3  

Expected return on plan assets

    (4 )   (4 )   (5 )            

Recognized actuarial loss

    4     4     3     2     2     2  

Settlement cost

    2     6                  
                           

Net periodic benefit cost

  $ 10   $ 14   $ 7   $ 10   $ 9   $ 8  
                           
                           

        The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $2 million and zero, respectively. The estimated net loss and prior service cost for the defined benefit postretirement plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $1 million and zero, respectively.

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 10    RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Continued)

ADDITIONAL INFORMATION

        The following table sets forth the weighted-average assumptions used to determine our benefit obligations and net periodic benefit cost:

 
  Pension
Benefits
  Postretirement
Benefits
 
 
  For the years ended
December 31,
 
 
  2013   2012   2013   2012  

Benefit Obligation Assumptions:

                         

Discount rate

    4.45 %   3.59 %   4.75 %   3.89 %

Rate of compensation increase

    4.00 %   4.00 %        

Net Periodic Benefit Cost Assumptions:

                         

Discount rate

    3.59 %   4.12 %   3.89 %   4.12 %

Assumed long term rate of return on assets

    6.50 %   6.50 %        

Rate of compensation increase

    4.00 %   4.00 %        

        For pension plans and postretirement benefit plans that we or our subsidiaries sponsor, we based the discount rate on the Aon/Hewitt AA-AAA Universe yield curve in 2013 and 2012. The weighted-average rate of increase in future compensation levels is consistent with our past and anticipated future compensation increases for employees participating in retirement plans that determine benefits using compensation. The assumed long-term rate of return on assets is estimated with regard to current market factors but within the context of historical returns for the asset mix that exists at year end.

        The postretirement benefit obligation was determined by application of the terms of medical and dental benefits and life insurance coverage, including the effect of established maximums on covered costs, together with relevant actuarial assumptions and healthcare cost trend rates projected at an assumed U.S. Consumer Price Index (CPI) increase of 2.36 percent and 2.39 percent as of December 31, 2013 and 2012, respectively. A 1-percent increase or a 1-percent decrease in these assumed healthcare cost trend rates would result in an increase of $6 million or a reduction of $5 million, respectively, in the postretirement benefit obligation as of December 31, 2013. The annual service and interest costs would not be materially affected by these changes.

        The actuarial assumptions used could change in the near term as a result of changes in expected future trends and other factors that, depending on the nature of the changes, could cause increases or decreases in the plan assets and liabilities.

Fair Value of Pension Plan Assets

        We employ a total return investment approach that uses a diversified blend of equity and fixed-income investments to optimize the long-term return of plan assets at a prudent level of risk. The investments were monitored by Occidental's Investment Committee in its role as fiduciary. The Investment Committee, consisting of senior Occidental executives, selected and employed various external professional investment management firms to manage specific investments across the spectrum of asset classes. Equity investments were diversified across United States and non-United States stocks, as well as differing styles and market capitalizations. Other asset classes, such as private equity and real estate, may have been used by the investment management firms with the goals of enhancing long-term returns and improving portfolio

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 10    RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Continued)

diversification. The target allocation of plan assets was 65 percent equity securities and 35 percent debt securities. Investment performance was measured and monitored on an ongoing basis through quarterly investment portfolio and manager guideline compliance reviews, annual liability measurements and periodic studies.

        The fair values of our pension plan assets by asset category are as follows (in millions):

 
  Fair Value Measurements at
December 31, 2013 Using
 
 
  Level 1   Level 2   Level 3   Total  

Asset Class:

                         

Master trust investment account(a)

  $   $ 69   $   $ 69  

Mutual funds:

                         

Bond funds

    5             5  

Blend funds

    3             3  

Value

    3             3  

Growth funds

    3             3  

Guaranteed deposit account

            9     9  
                   

Total pension plan assets(b)

  $ 14   $ 69   $ 9   $ 92  
                   
                   

 

 
  Fair Value Measurements at
December 31, 2012 Using
 
 
  Level 1   Level 2   Level 3   Total  

Asset Class:

                         

Master trust investment account(a)

  $   $ 53   $   $ 53  

Mutual funds:

                         

Bond funds

    6             6  

Blend funds

    3             3  

Value

    3             3  

Growth funds

    2             2  

Guaranteed deposit account

            8     8  
                   

Total pension plan assets(b)

  $ 14   $ 53   $ 8   $ 75  
                   
                   

(a)
Represents our investment in a master trust investment account established by Occidental. The trust investments include common stock, preferred stock, publicly registered mutual funds, U.S. government securities and corporate bonds.

(b)
Amounts exclude net payables of approximately $1 million as of December 31, 2013 and 2012.

        The activity during the years ended December 31, 2013 and 2012, for the assets using Level 3 fair value measurements was insignificant.

        We do not expect to contribute to our defined benefit pension plans during 2014.

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CALIFORNIA RESOURCES CORPORATION

Notes to Combined Financial Statements (Continued)

NOTE 10    RETIREMENT AND POSTRETIREMENT BENEFIT PLANS (Continued)

        Estimated future benefit payments, which reflect expected future service, as appropriate, are as follows:

For the years ended December 31,
  Pension
Benefits
  Postretirement
Benefits
 
 
  (in millions)
 

2014

  $ 9   $  

2015

  $ 7   $  

2016

  $ 11   $  

2017

  $ 9   $ 1  

2018

  $ 9   $ 1  

2019 - 2023

  $ 52   $ 6  

NOTE 11    RELATED-PARTY TRANSACTIONS

Related Party Transactions

        During 2013, 2012 and 2011, we entered into the following related-party transactions:

 
  2013   2012   2011  
 
  (in millions)
 

Sales

  $ 4,174   $ 3,970   $ 3,862  

Allocated costs for services provided by affiliates

  $ 146   $ 129   $ 148  

Purchases

  $ 164   $ 119   $ 133  

        Substantially all of our products are historically sold to Occidental's marketing subsidiaries at market prices and have been settled at the time of sale to those entities. For the years ended December 31, 2013, 2012 and 2011, sales to Occidental subsidiaries accounted for approximately 97%, 97% and 98% of our net sales, respectively.

        As discussed in Note 1, the combined statements of income include expense allocations for certain corporate functions and centrally-located activities historically performed by Occidental. These functions include executive oversight, accounting, treasury, tax, financial reporting, internal audit, legal, risk management, information technology, government relations, public relations, investor relations, human resources, procurement, engineering, drilling, exploration, finance, marketing, ethics and compliance, and certain other shared services. Charges from Occidental for these services are reflected in selling, general and administrative expenses.

        Purchases from related parties reflect products purchased at market prices from Occidental's subsidiaries and are used in our operations. These purchases are included in production costs. There are no significant related party receivable or payable balances at December 31, 2013, 2012 and 2011.

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SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

        The following tables set forth our net interests in quantities of proved developed and undeveloped reserves of oil (including condensate), natural gas liquids and natural gas and changes in such quantities. Reserves are stated net of applicable royalties. Estimated reserves include our economic interests under arrangements similar to production-sharing contracts (PSCs) relating to the Wilmington field in Long Beach. All of our proved reserves are located within the state of California.

Oil Reserves

 
  San Joaquin
Basin
  Los Angeles
Basin(a)
  Ventura
Basin
  Sacramento
Basin
  Total  
 
  (In millions of barrels (MMBbl))
 

PROVED DEVELOPED AND UNDEVELOPED RESERVES

                               

Balance at December 31, 2010

    340     110     39         489  

Revisions of previous estimates

    (58 )               (58 )

Improved recovery

    51     12     3         66  

Extensions and discoveries

    7         1         8  

Purchases of proved reserves

    16     16             32  

Sales of proved reserves

                     

Production

    (20 )   (7 )   (2 )       (29 )
                       

Balance at December 31, 2011

    336     131     41         508  

Revisions of previous estimates

    (44 )   1     (3 )       (46 )

Improved recovery

    36     16     11         63  

Extensions and discoveries

    3                 3  

Purchases of proved reserves

    1                 1  

Sales of proved reserves

                     

Production

    (21 )   (9 )   (2 )       (32 )
                       

Balance at December 31, 2012

    311     139     47         497  

Revisions of previous estimates

    (8 )   3     (3 )       (8 )

Improved recovery

    49     24     3         76  

Extensions and discoveries

                     

Purchases of proved reserves

                     

Sales of proved reserves

                     

Production

    (21 )   (10 )   (2 )       (33 )
                       

Balance at December 31, 2013

    331     156     45         532  
                       
                       

PROVED DEVELOPED RESERVES

                               

December 31, 2010

    266     83     27         376  
                       
                       

December 31, 2011

    239     97     30         366  
                       
                       

December 31, 2012

    220     104     30         354  
                       
                       

December 31, 2013(b)

    225     109     29         363  
                       
                       

PROVED UNDEVELOPED RESERVES

                               

December 31, 2010

    74     27     12         113  
                       
                       

December 31, 2011

    97     34     11         142  
                       
                       

December 31, 2012

    91     35     17         143  
                       
                       

December 31, 2013

    106     47     16         169  
                       
                       

(a)
Includes proved reserves related to economic arrangements similar to PSCs of 102 MMBbl, 98 MMBbl, 92 MMBbl and 89 MMBbl at December 31, 2013, 2012, 2011 and 2010, respectively.

(b)
Approximately 11 percent of the proved developed reserves at December 31, 2013 are nonproducing.

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NGLs Reserves

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  
 
  (In MMBbl)
 

PROVED DEVELOPED AND UNDEVELOPED RESERVES

                               

Balance at December 31, 2010

    72         4         76  

Revisions of previous estimates

    (5 )       (1 )       (6 )

Improved recovery

    3                 3  

Extensions and discoveries

    1                 1  

Purchases of proved reserves

                     

Sales of proved reserves

                     

Production

    (5 )               (5 )
                       

Balance at December 31, 2011

    66         3         69  

Revisions of previous estimates

    (14 )               (14 )

Improved recovery

    12         1         13  

Extensions and discoveries

                     

Purchases of proved reserves

                     

Sales of proved reserves

                     

Production

    (6 )               (6 )
                       

Balance at December 31, 2012

    58         4         62  

Revisions of previous estimates

    13                 13  

Improved recovery

    4                 4  

Extensions and discoveries

                     

Purchases of proved reserves

                     

Sales of proved reserves

                     

Production

    (7 )               (7 )
                       

Balance at December 31, 2013

    68         4         72  
                       
                       

PROVED DEVELOPED RESERVES

                               

December 31, 2010

    40         4         44  
                       
                       

December 31, 2011

    42         3         45  
                       
                       

December 31, 2012

    42         2         44  
                       
                       

December 31, 2013(a)

    47         2         49  
                       
                       

PROVED UNDEVELOPED RESERVES

                               

December 31, 2010

    32                 32  
                       
                       

December 31, 2011

    24                 24  
                       
                       

December 31, 2012

    16         2         18  
                       
                       

December 31, 2013

    21         2         23  
                       
                       

(a)
Approximately 2 percent of the proved developed reserves at December 31, 2013 are nonproducing.

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Gas Reserves

 
  San Joaquin Basin   Los Angeles Basin   Ventura Basin   Sacramento Basin   Total  
 
  (In billions of cubic feet (Bcf))
 

PROVED DEVELOPED AND UNDEVELOPED RESERVES

                               

Balance at December 31, 2010

    1,170     12     39     3     1,224  

Revisions of previous estimates

    (357 )   5     (1 )   4     (349 )

Improved recovery

    39         1     6     46  

Extensions and discoveries

    35                 35  

Purchases of proved reserves

    1     9     1     38     49  

Sales of proved reserves

                       

Production

    (80 )   (1 )   (4 )   (10 )   (95 )
                       

Balance at December 31, 2011

    808     25     36     41     910  

Revisions of previous estimates

    (150 )   (6 )   (3 )   (9 )   (168 )

Improved recovery

    100     1     9     1     111  

Extensions and discoveries

    6             6     12  

Purchases of proved reserves

    2             154     156  

Sales of proved reserves

                       

Production

    (74 )   (1 )   (4 )   (14 )   (93 )
                       

Balance at December 31, 2012

    692     19     38     179     928  

Revisions of previous estimates

    (4 )   (4 )   (1 )   (38 )   (47 )

Improved recovery

    47     3     2         52  

Extensions and discoveries

                     

Purchases of proved reserves

                     

Sales of proved reserves

                     

Production

    (66 )   (1 )   (4 )   (24 )   (95 )
                       

Balance at December 31, 2013

    669     17     35     117     838  
                       
                       

PROVED DEVELOPED RESERVES

                               

December 31, 2010

    584     9     31     3     627  
                       
                       

December 31, 2011

    548     19     31     41     639  
                       
                       

December 31, 2012

    473     14     28     147     662  
                       
                       

December 31, 2013(a)

    459     11     25     116     611  
                       
                       

PROVED UNDEVELOPED RESERVES

                               

December 31, 2010

    586     3     8         597  
                       
                       

December 31, 2011

    260     6     5         271  
                       
                       

December 31, 2012

    219     5     10     32     266  
                       
                       

December 31, 2013

    210     6     10     1     227  
                       
                       

(a)
Approximately 8 percent of the proved developed reserves at December 31, 2013 are nonproducing.

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Total Reserves

 
  San Joaquin
Basin
  Los Angeles
Basin(b)
  Ventura
Basin
  Sacramento
Basin
  Total  
 
  (In MMBoe(a))
 

PROVED DEVELOPED AND UNDEVELOPED RESERVES

                               

Balance at December 31, 2010

    606     112     52         770  

Revisions of previous estimates

    (122 )   1     (2 )       (123 )

Improved recovery

    61     12     3     1     77  

Extensions and discoveries

    15         1         16  

Purchases of proved reserves

    16     17         6     39  

Sales of proved reserves

                     

Production

    (39 )   (7 )   (2 )   (2 )   (50 )
                       

Balance at December 31, 2011

    537     135     52     5     729  

Revisions of previous estimates

    (83 )       (4 )   (1 )   (88 )

Improved recovery

    65     16     13         94  

Extensions and discoveries

    5         1     1     7  

Purchases of proved reserves

    1             25     26  

Sales of proved reserves

                     

Production

    (39 )   (9 )   (4 )   (2 )   (54 )
                       

Balance at December 31, 2012

    486     142     58     28     714  

Revisions of previous estimates

    4     2     (3 )   (6 )   (3 )

Improved recovery

    61     25     3         89  

Extensions and discoveries

                     

Purchases of proved reserves

                     

Sales of proved reserves

                     

Production

    (40 )   (10 )   (3 )   (3 )   (56 )
                       

Balance at December 31, 2013

    511     159     55     19     744  
                       
                       

PROVED DEVELOPED RESERVES

                               

December 31, 2010

    402     84     39         525  
                       
                       

December 31, 2011

    372     100     40     5     517  
                       
                       

December 31, 2012

    341     106     38     23     508  
                       
                       

December 31, 2013(c)

    349     111     35     19     514  
                       
                       

PROVED UNDEVELOPED RESERVES

                               

December 31, 2010

    204     28     13         245  
                       
                       

December 31, 2011

    165     35     12         212  
                       
                       

December 31, 2012

    145     36     20     5     206  
                       
                       

December 31, 2013

    162     48     20         230  
                       
                       

(a)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of West Texas Intermediate (WTI) oil and NYMEX natural gas were $97.97 per Bbl and $3.66 per Mcf, respectively, resulting in an oil to gas ratio of over 25 to 1.

(b)
Includes proved reserves related to economic arrangements similar to PSCs of 102 MMBbl, 98 MMBbl, 92 MMBbl and 89 MMBbl at December 31, 2013, 2012, 2011 and 2010, respectively.

(c)
Approximately 9 percent of the proved developed reserves at December 31, 2013 are nonproducing.

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Capitalized Costs

        Capitalized costs relating to oil and gas producing activities and related accumulated DD&A were as follows:

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  
 
  (In millions)
 

December 31, 2013

                               

Proved properties

  $ 15,592   $ 2,487   $ 1,479   $ 542   $ 20,100  

Unproved properties

    584     105     91     92     872  
                       

Total capitalized costs(a)

    16,176     2,592     1,570     634     20,972  

Accumulated depreciation, depletion and amortization

    (5,923 )   (571 )   (342 )   (128 )   (6,964 )
                       

Net capitalized costs

  $ 10,253   $ 2,021   $ 1,228   $ 506   $ 14,008  
                       
                       

December 31, 2012

                               

Proved properties

  $ 14,817   $ 1,974   $ 1,327   $ 286   $ 18,404  

Unproved properties

    639     97     92     92     920  
                       

Total capitalized costs(a)

    15,456     2,071     1,419     378     19,324  

Accumulated depreciation, depletion and amortization

    (5,039 )   (424 )   (272 )   (90 )   (5,825 )
                       

Net capitalized costs

  $ 10,417   $ 1,647   $ 1,147   $ 288   $ 13,499  
                       
                       

December 31, 2011

                               

Proved properties

  $ 12,611   $ 1,904   $ 1,227   $ 199   $ 15,941  

Unproved properties

    641     52     12     69     774  
                       

Total capitalized costs(a)

    13,252     1,956     1,239     268     16,715  

Accumulated depreciation, depletion and amortization

    (4,214 )   (405 )   (279 )   (39 )   (4,937 )
                       

Net capitalized costs

  $ 9,038   $ 1,551   $ 960   $ 229   $ 11,778  
                       
                       

(a)
Includes acquisition costs, development costs and asset retirement obligations.

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Table of Contents

Costs Incurred

        Costs incurred includes capital expenditures, exploration (whether expensed or capitalized), acquisitions, and asset retirement obligations, as follows:

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  
 
  (In millions)
 

FOR THE YEAR ENDED DECEMBER 31, 2013

                               

Property acquisition costs

                               

Proved properties

  $ 14   $ 1   $   $ 5   $ 20  

Unproved properties

    23     9     1         33  

Exploration costs

    127         1     3     131  

Development costs

    1,092     371     110     15     1,588  
                       

Costs incurred

  $ 1,256   $ 381   $ 112   $ 23   $ 1,772  
                       
                       

FOR THE YEAR ENDED DECEMBER 31, 2012

                               

Property acquisition costs

                               

Proved properties

  $ 83   $ 8   $   $ 274   $ 365  

Unproved properties

    30     1         10     41  

Exploration costs

    153     4     1     1     159  

Development costs

    1,732     348     124     26     2,230  
                       

Costs incurred

  $ 1,998   $ 361   $ 125   $ 311   $ 2,795  
                       
                       

FOR THE YEAR ENDED DECEMBER 31, 2011

                               

Property acquisition costs

                               

Proved properties

  $ 351   $ 413   $ 106   $ 149   $ 1,019  

Unproved properties

    438         6     68     512  

Exploration costs

    146     29     9     1     185  

Development costs

    1,703     207     54     40     2,004  
                       

Costs incurred

  $ 2,638   $ 649   $ 175   $ 258   $ 3,720  
                       
                       

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Results of Operations

        Our oil and gas producing activities, which exclude items such as asset dispositions and corporate overhead, were as follows:

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  
 
  (In millions)
 

FOR THE YEAR ENDED DECEMBER 31, 2013

                               

Revenues(a)

  $ 2,969   $ 968   $ 259   $ 89   $ 4,285  

Production costs(b)

    658     306     75     27     1,066  

Other operating expenses

    153     56     19     18     246  

Depreciation, depletion and amortization

    866     108     73     97     1,144  

Taxes other than on income

    123     43     9     10     185  

Exploration expenses

    94     1     13     8     116  
                       

Pretax income

    1,075     454     70     (71 )   1,528  

Income tax expense

    428     181     28     (28 )   609  
                       

Results of operations

  $ 647   $ 273   $ 42   $ (43 ) $ 919  
                       
                       

FOR THE YEAR ENDED DECEMBER 31, 2012

                               

Revenues(a)

  $ 2,843   $ 921   $ 262   $ 46   $ 4,072  

Production costs(b)

    885     331     81     17     1,314  

Other operating expenses

    138     52     18     10     218  

Depreciation, depletion and amortization

    742     79     61     44     926  

Taxes other than on income

    114     37     9     7     167  

Asset impairments and related items

    31     10             41  

Exploration expenses

    112     29     1     6     148  
                       

Pretax income

    821     383     92     (38 )   1,258  

Income tax expense

    335     156     38     (15 )   514  
                       

Results of operations

  $ 486   $ 227   $ 54   $ (23 ) $ 744  
                       
                       

FOR THE YEAR ENDED DECEMBER 31, 2011

                               

Revenues(a)

  $ 2,898   $ 766   $ 231   $ 43   $ 3,938  

Production costs(b)

    721     264     77     12     1,074  

Other operating expenses

    127     50     13     6     196  

Depreciation, depletion and amortization

    543     58     44     30     675  

Taxes other than on income

    101     29     8     5     143  

Exploration expenses

    113             1     114  
                       

Pretax income

    1,293     365     89     (11 )   1,736  

Income tax expense

    528     149     36     (4 )   709  
                       

Results of operations

  $ 765   $ 216   $ 53   $ (7 ) $ 1,027  
                       
                       

(a)
Revenues are net of royalty payments.

(b)
Production costs are the costs incurred in lifting the oil and gas to the surface and include gathering, processing, field storage and insurance on proved properties, but do not include DD&A, royalties, income taxes and general and administrative expenses.

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Table of Contents

Results per Unit of Production

 
  San Joaquin
Basin
  Los Angeles
Basin
  Ventura
Basin
  Sacramento
Basin
  Total  

FOR THE YEAR ENDED DECEMBER 31, 2013

                               

Revenue from each barrel of oil equivalent ($/Boe)(a)(b)

  $ 75.58   $ 101.17   $ 79.28   $ 22.09   $ 76.32  

Production costs

    16.75     31.98     22.96     6.70     18.99  

Other operating expenses

    3.89     5.85     5.82     4.47     4.38  

Depreciation, depletion and amortization

    22.05     11.29     22.34     24.08     20.38  

Taxes other than on income

    3.13     4.49     2.75     2.48     3.29  

Exploration expenses

    2.39     0.10     3.98     1.99     2.07  
                       

Pretax income

    27.37     47.46     21.43     (17.63 )   27.21  

Income tax expense

    10.90     18.92     8.57     (6.95 )   10.85  
                       

Results of operations

  $ 16.47   $ 28.54   $ 12.86   $ (10.68 ) $ 16.36  
                       
                       

FOR THE YEAR ENDED DECEMBER 31, 2012

                               

Revenue from each barrel of oil equivalent ($/Boe)(a)(b)

  $ 71.96   $ 102.45   $ 81.85   $ 20.09   $ 75.42  

Production costs

    22.40     36.82     25.30     7.42     24.34  

Other operating expenses

    3.49     5.78     5.62     4.37     4.04  

Depreciation, depletion and amortization

    18.78     8.79     19.06     19.21     17.15  

Taxes other than on income

    2.89     4.12     2.81     3.06     3.09  

Asset impairments and related items

    0.78     1.11             0.76  

Exploration expenses

    2.83     3.23     0.31     2.62     2.74  
                       

Pretax income

    20.79     42.60     28.75     (16.59 )   23.30  

Income tax expense

    8.48     17.35     11.87     (6.55 )   9.52  
                       

Results of operations

  $ 12.31   $ 25.25   $ 16.88   $ (10.04 ) $ 13.78  
                       
                       

FOR THE YEAR ENDED DECEMBER 31, 2011

                               

Revenue from each barrel of oil equivalent ($/Boe)(a)(b)

  $ 75.10   $ 103.99   $ 82.38   $ 25.67   $ 78.08  

Production costs

    18.68     35.84     27.46     7.16     21.30  

Other operating expenses

    3.29     6.79     4.64     3.58     3.89  

Depreciation, depletion and amortization

    14.07     7.87     15.69     17.91     13.38  

Taxes other than on income

    2.62     3.94     2.85     2.99     2.84  

Exploration expenses

    2.93             0.60     2.26  
                       

Pretax income

    33.51     49.55     31.74     (6.57 )   34.41  

Income tax expense

    13.68     20.23     12.84     (2.39 )   14.06  
                       

Results of operations

  $ 19.83   $ 29.32   $ 18.90   $ (4.18 ) $ 20.35  
                       
                       

(a)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per Bbl and $3.66 per Mcf, respectively, resulting in an oil to gas ratio of over 25 to 1.

(b)
Revenues are net of royalty payments.

F-40


Table of Contents

Standardized Measure, Including Year-to-Year Changes Therein, of Discounted Future Net Cash Flows

        For purposes of the following disclosures, future cash flows were computed by applying to our proved oil and gas reserves the unweighted arithmetic average of the first-day-of-the-month price for each month within the years ended December 31, 2013, 2012 and 2011, respectively. The realized prices used to calculate future cash flows vary by producing area and market conditions. Future operating and capital costs were forecast using the current cost environment applied to expectations of future operating and development activities. Future income tax expenses were computed by applying, generally, year-end statutory tax rates (adjusted for permanent differences, tax credits and allowances) to the estimated net future pre-tax cash flows. The discount was computed by application of a 10-percent discount factor. The calculations assumed the continuation of existing economic, operating and contractual conditions at December 31, 2013, 2012 and 2011. Such assumptions, which are prescribed by regulation, have not always proven accurate in the past. Other valid assumptions would give rise to substantially different results.

Standardized Measure of Discounted Future Net Cash Flows

 
  Total  
 
  (In millions)
 

AT DECEMBER 31, 2013

       

Future cash inflows

  $ 60,884  

Future costs

       

Production costs and other operating expenses

    (29,523 )

Development costs(a)

    (6,327 )

Future income tax expense

    (8,213 )
       

Future net cash flows

    16,821  

Ten percent discount factor

    (7,598 )
       

Standardized measure of discounted future net cash flows

  $ 9,223  
       
       

AT DECEMBER 31, 2012

       

Future cash inflows

  $ 57,468  

Future costs

       

Production costs and other operating expenses

    (26,968 )

Development costs(a)

    (5,961 )

Future income tax expense

    (8,059 )
       

Future net cash flows

    16,480  

Ten percent discount factor

    (7,407 )
       

Standardized measure of discounted future net cash flows

  $ 9,073  
       
       

AT DECEMBER 31, 2011

       

Future cash inflows

  $ 60,872  

Future costs

       

Production costs and other operating expenses

    (26,642 )

Development costs(a)

    (5,015 )

Future income tax expense

    (9,925 )
       

Future net cash flows

    19,290  

Ten percent discount factor

    (8,943 )
       

Standardized measure of discounted future net cash flows

  $ 10,347  
       
       

(a)
Includes asset retirement costs.

F-41


Table of Contents

Changes in the Standardized Measure of Discounted Future Net Cash Flows From Proved Reserve Quantities

 
  For the years ended December 31,  
 
  2013   2012   2011  
 
  (In millions)
 

Beginning of year

  $ 9,073   $ 10,347   $ 7,051  
               

Sales and transfers of oil and gas produced, net of production costs and other operating expenses

    (3,082 )   (2,695 )   (2,840 )

Net change in prices received per Bbl, net of production costs and other operating expenses

    575     (1,431 )   4,837  

Extensions, discoveries and improved recovery, net of future production and development costs

    1,914     1,897     2,662  

Change in estimated future development costs

    (688 )   (1,526 )   (1,015 )

Revisions of quantity estimates

    (62 )   (1,405 )   (1,839 )

Previously estimated development costs incurred during the period

    1,185     1,039     869  

Accretion of discount

    1,292     1,512     1,048  

Net change in income taxes

    (95 )   984     (1,960 )

Purchases and sales of reserves in place, net

    4     221     1,065  

Changes in production rates and other

    (893 )   130     469  
               

Net change

    150     (1,274 )   3,296  
               

End of year

  $ 9,223   $ 9,073   $ 10,347  
               
               

F-42


Table of Contents

Oil, NGLs and Natural Gas Production Per Day

        The following table set forth the production volumes of oil, NGLs and natural gas per day for each of the three years in the period ended December 31, 2013.

 
  2013   2012   2011  

Oil (MBbl/d)

                   

San Joaquin Basin(b)

    58     58     56  

Los Angeles Basin(c)

    26     24     19  

Ventura Basin

    6     6     5  

Sacramento Basin

             
               

Total

    90     88     80  
               

NGLs (MBbl/d)

                   

San Joaquin Basin(b)

    19     16     14  

Los Angeles Basin

             

Ventura Basin

    1     1     1  

Sacramento Basin

             
               

Total

    20     17     15  
               

Natural gas (MMcf/d)

                   

San Joaquin Basin(b)

    182     204     220  

Los Angeles Basin(c)

    2     3     1  

Ventura Basin

    11     12     12  

Sacramento Basin

    65     37     27  
               

Total

    260     256     260  
               

Total Production (MBoe/d)(a)

    154     148     138  
               
               

(a)
Natural gas volumes have been converted to Boe based on energy content of six Mcf of gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in 2013, the average prices of WTI oil and NYMEX natural gas were $97.97 per Bbl and $3.66 per Mcf, respectively, resulting in an oil to gas ratio of over 25 to 1.

(b)
Includes daily production from Elk Hills field of 26 MBbl oil, 18 MBbl NGLs and 145 MMcf gas in 2013; 29 MBbl oil, 15 MBbl NGLs and 168 MMcf gas in 2012; and 30 MBbl oil, 14 MBbl NGLs and 174 MMcf gas in 2011.

(c)
Includes daily production from Wilmington field of 22 MBbl Oil in 2013; 21 MBbl Oil in 2012 and 19 MBbl Oil 2011.

F-43




Exhibit 99.3

 

Information Regarding “Significant Items Affecting Earnings of Occidental Petroleum” extracted from Occidental’s Annual Report on Form 10-K for the year ended December 31, 2013

 

SIGNIFICANT ITEMS AFFECTING EARNINGS

 

The following table sets forth, for the years ended December 31, 2013, 2012 and 2011, significant transactions and events affecting Occidental’s earnings that vary widely and unpredictably in nature, timing and amount:

 

Significant Items Affecting Earnings

 

Benefit (Charge) (in millions)

 

2013

 

2012

 

2011

 

OIL AND GAS

 

 

 

 

 

 

 

Asset impairments and related items

 

$

(607

)

$

(1,731

)

$

 

Libya exploration write-off

 

 

 

(35

)

Gains on sale of Colombian pipeline interest

 

 

 

22

 

Foreign tax

 

 

 

(29

)

Total Oil and Gas

 

$

(607

)

$

(1,731

)

$

(42

)

CHEMICAL

 

 

 

 

 

 

 

Carbocloro sale gain

 

$

131

 

$

 

$

 

Total Chemical

 

$

131

 

$

 

$

 

MIDSTREAM AND MARKETING

 

 

 

 

 

 

 

Plains Pipeline sale gain and other

 

$

1,030

 

$

 

$

 

Total Midstream and Marketing

 

$

1,030

 

$

 

$

 

CORPORATE

 

 

 

 

 

 

 

Charge for former employees and consultants

 

$

(55

)

$

 

$

 

Litigation reserves

 

 

(20

)

 

Premium on debt extinguishments

 

 

 

(163

)

State income tax charge

 

 

 

(33

)

Tax effect of pre-tax adjustments

 

(179

)

636

 

50

 

Discontinued operations, net of tax(a)

 

(19

)

(37

)

131

 

Total Corporate

 

$

(253

)

$

579

 

$

(15

)

 


(a)    The 2011 amount includes a $144 million after-tax gain from the sale of the Argentine operations.

 



 

Information Regarding “Basic Earnings Per Common Share of Occidental Petroleum” extracted from Occidental’s Annual Report on Form 10-K for the year ended December 31, 2013

 

Consolidated Statements of Income

 

Occidental Petroleum Corporation

In millions, except per-share amounts

 

and Subsidiaries

 

For the years ended December 31,

 

2013

 

2012

 

2011

 

REVENUES AND OTHER INCOME

 

 

 

 

 

 

 

Net sales

 

$

24,455

 

$

24,172

 

$

23,939

 

Interest, dividends and other income

 

106

 

81

 

180

 

Gain on sale of equity investments

 

1,175

 

 

 

 

 

25,736

 

24,253

 

24,119

 

 

 

 

 

 

 

 

 

COSTS AND OTHER DEDUCTIONS

 

 

 

 

 

 

 

Cost of sales (excludes depreciation, depletion and amortization of $5,341 in 2013, $4,504 in 2012 and $3,584 in 2011)

 

7,562

 

7,844

 

7,385

 

Selling, general and administrative and other operating expenses

 

1,801

 

1,602

 

1,523

 

Depreciation, depletion and amortization

 

5,347

 

4,511

 

3,591

 

Asset impairments and related items

 

621

 

1,751

 

 

Taxes other than on income

 

749

 

680

 

605

 

Exploration expense

 

256

 

345

 

258

 

Interest and debt expense, net

 

118

 

130

 

298

 

 

 

16,454

 

16,863

 

13,660

 

INCOME BEFORE INCOME TAXES AND OTHER ITEMS

 

9,282

 

7,390

 

10,459

 

Provision for domestic and foreign income taxes

 

(3,755

)

(3,118

)

(4,201

)

Income from equity investments

 

395

 

363

 

382

 

 

 

 

 

 

 

 

 

INCOME FROM CONTINUING OPERATIONS

 

5,922

 

4,635

 

6,640

 

Discontinued operations, net

 

(19

)

(37

)

131

 

 

 

 

 

 

 

 

 

NET INCOME

 

$

5,903

 

$

4,598

 

$

6,771

 

 

 

 

 

 

 

 

 

BASIC EARNINGS PER COMMON SHARE

 

 

 

 

 

 

 

Income from continuing operations

 

$

7.35

 

$

5.72

 

$

8.16

 

Discontinued operations, net

 

(0.02

)

(0.05

)

0.16

 

BASIC EARNINGS PER COMMON SHARE

 

$

7.33

 

$

5.67

 

$

8.32

 

 

 

 

 

 

 

 

 

DILUTED EARNINGS PER COMMON SHARE

 

 

 

 

 

 

 

Income from continuing operations

 

$

7.34

 

$

5.71

 

$

8.16

 

Discontinued operations, net

 

(0.02

)

(0.04

)

0.16

 

DILUTED EARNINGS PER COMMON SHARE

 

$

7.32

 

$

5.67

 

$

8.32

 

DIVIDENDS PER COMMON SHARE

 

$

2.56

 

$

2.16

 

$

1.84

 

 



 

Note 12 to Consolidated Financial Statements of Occidental extracted from

Occidental’s Annual Report on Form 10-K for the year ended December 31, 2013

 

NOTE 12               STOCK-BASED INCENTIVE PLANS

 

Occidental has established several Plans that allow it to issue stock-based awards including in the form of RSUs, stock options (Options), stock appreciation rights (SARs) and TSRIs. An aggregate of 66 million shares of Occidental common stock were authorized for issuance and approximately 16 million shares had been issued through December 31, 2013. Of the remaining shares, only approximately 20 million shares are available for grants of future awards because a plan provision requires each share covered by an award (other than Options and SARs) to be counted as if three shares were issued in determining the number of shares that are available for future awards. Accordingly, the number of shares available for future awards may be less than 20 million depending on the type of award granted. Additionally, under the plan, the shares available for future awards may increase, depending on the award type, by the number of shares currently unvested or forfeitable, or three times that number as applicable, that (i) fail to vest, (ii) are forfeited or canceled, or (iii) correspond to the portion of any stock-based awards settled in cash.

 

During 2013, non-employee directors were granted awards for 37,100 shares of restricted stock, a substantial majority of which fully vested on the grant date. Compensation expense for these awards was measured using the quoted market price of Occidental’s common stock on the grant date and was fully recognized at that time.

 

The following table summarizes certain stock-based incentive amounts for the past three years:

 

For the years ended December 31, (in millions)

 

2013

 

2012

 

2011

 

Compensation expense

 

$

152

 

$

78

 

$

110

 

Income tax benefit recognized in the income statement

 

$

55

 

$

29

 

$

40

 

Intrinsic value of options and stock-settled SARs exercised

 

$

24

 

$

18

 

$

21

 

Cash paid (a)

 

$

96

 

$

83

 

$

124

 

Fair value of RSUs and TSRIs vested during the year (b)

 

$

83

 

$

28

 

$

53

 

 


(a)    Includes cash paid under the cash-settled portion of the SARs, RSUs and TSRIs.

(b)    As measured on the vesting date for the stock-settled portion of the RSUs and TSRIs.

 

As of December 31, 2013, unrecognized compensation expense for all unvested stock-based incentive awards, based on year-end valuation, was $205 million. This expense is expected to be recognized over a weighted-average period of 2.0 years.

 

RSUs

 

Certain employees are awarded the right to receive RSUs, some of which have performance criteria, and are in the form of, or equivalent in value to, actual shares of Occidental common stock. Depending on their terms, RSUs are settled in cash or stock at the time of vesting. These awards vest ratably over three years, or at the end of two or three years, following the grant date, however, certain of the RSUs are forfeitable if performance objectives are not satisfied by the seventh anniversary of the grant date. For certain three-year RSUs, dividend equivalents are paid during the vesting period. For those awards that cliff vest in two or three years, dividend equivalents are accumulated during the vesting period and are paid when they vest.

 

The weighted-average, grant-date fair values of cash-settled RSUs granted in 2013, 2012 and 2011 were $89.70, $84.38 and $104.74 per share, respectively. The weighted-average, grant-date fair values of the stock-settled RSUs granted in 2013, 2012, and 2011 were $90.35, $84.81 and $102.97, respectively.

 

A summary of changes in Occidental’s unvested cash- and stock-settled RSUs during the year ended December 31, 2013 is presented below:

 



 

 

 

Cash-Settled

 

Stock-Settled

 

 

 

RSUs
(000’s)

 

Weighted-
Average Grant-
Date Fair Value

 

RSUs
(000’s)

 

Weighted-
Average Grant-
Date Fair Value

 

Unvested at January 1

 

1,332

 

$

90.27

 

1,375

 

$

88.23

 

Granted

 

785

 

89.70

 

793

 

90.35

 

Vested

 

(613

)

89.89

 

(438

)

84.51

 

Forfeitures

 

(73

)

90.26

 

(123

)

88.59

 

Unvested at December 31

 

1,431

 

90.12

 

1,607

 

90.26

 

 

TSRIs

 

Certain executives are awarded TSRIs that vest at the end of a three-year period following the grant date if performance targets are certified as being met. TSRIs granted in July 2013 and 2012 have payouts that range from 0 to 150 percent of the target award and 0 to 100 percent of the maximum award, respectively, that would settle, once certified, fully in stock. TSRIs granted in July 2011 have payouts that range from 0 to 100 percent of the maximum award that would settle, once certified, 50 percent in stock and 50 percent in cash. Dividend equivalents for TSRIs are accumulated and paid upon vesting for the number of vested shares.

 

The fair values of TSRIs are initially determined on the grant date using a Monte Carlo simulation model based on Occidental’s assumptions, noted in the following table, and the volatility from corresponding peer group companies. The expected life is based on the vesting period (Term). The risk-free interest rate is the implied yield available on zero coupon T-notes (US Treasury Strip) at the time of grant with a remaining term equal to the Term. The dividend yield is the expected annual dividend yield over the Term, expressed as a percentage of the stock price on the grant date. Estimates of fair value may not accurately predict the value ultimately realized by the employees who receive the awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.

 

The grant-date assumptions used in the Monte Carlo simulation models for the estimated payout level of TSRIs were as follows:

 

 

 

TSRIs

 

Year Granted

 

2013

 

2012

 

2011

 

Assumptions used:

 

 

 

 

 

 

 

Risk-free interest rate

 

0.6

%

0.4

%

0.6

%

Dividend yield

 

2.8

%

2.6

%

1.8

%

Volatility factor

 

30

%

34

%

33

%

Expected life (years)

 

3

 

3

 

3

 

Grant-date fair value of underlying Occidental common stock

 

$

91.97

 

$

84.57

 

$

102.97

 

 

A summary of Occidental’s unvested TSRIs as of December 31, 2013, and changes during the year ended December 31, 2013, is presented below:

 

 

 

TSRIs

 

 

 

Awards
(000’s)

 

Weighted-
Average Grant-
Date Fair Value
of Occidental
Stock

 

Unvested at January 1 (a)

 

1,930

 

$

80.39

 

Granted (a)

 

135

 

91.97

 

Vested (a)

 

(1,143

)

72.44

 

Forfeitures

 

(90

)

87.05

 

Unvested at December 31 (a)

 

832

 

92.49

 

 


(a)    Presented at the target or mid-point payouts.

 



 

STOCK OPTIONS AND SARs

 

Certain employees have been granted Options that are settled in stock and SARs that are settled either only in stock or only in cash. No Options or SARs have been granted since 2006 and all outstanding awards are vested. Exercise prices of the Options and SARs were equal to the quoted market value of Occidental’s stock on the grant date. Generally, the Options and SARs vest ratably over three years from the grant date with a maximum term of ten years. These Options and SARs may be forfeited or accelerated under certain circumstances.

 

The fair value of each Option, stock-settled SAR or cash-settled SAR is initially measured on the grant date using the Black Scholes option valuation model. The expected life is estimated based on the actual weighted-average life of historical exercise activity of the grantee population at the grant date. The volatility factors are based on the historical volatilities of Occidental common stock over the expected lives as estimated on the grant date. The risk-free interest rate is the implied yield available on US Treasury Strips at the grant date with a remaining term equal to the expected life of the measured instrument. The dividend yield is the expected annual dividend yield over the expected life, expressed as a percentage of the stock price on the grant date. Estimates of fair value may not accurately predict the value ultimately realized by employees who receive stock-based incentive awards, and the ultimate value may not be indicative of the reasonableness of the original estimates of fair value made by Occidental.

 

The following is a summary of Option and SAR transactions during the year ended December 31, 2013:

 

 

 

Cash-Settled

 

Stock-Settled

 

 

 

SARs
(000’s)

 

Weighted-
Average
Exercise
Price

 

Weighted-
Average
Remaining
Contractual
Term (yrs)

 

Aggregate
Intrinsic
Value
(000’s)

 

SARs &
Options
(000’s)

 

Weighted-
Average
Exercise
Price

 

Weighted-
Average
Remaining
Contractual
Term (yrs)

 

Aggregate
Intrinsic
Value
(000’s)

 

Beginning balance, January 1

 

494

 

$

24.66

 

 

 

 

 

537

 

$

31.88

 

 

 

 

 

Exercised

 

(142

)

$

24.66

 

 

 

 

 

(391

)

$

28.12

 

 

 

 

 

Forfeitures

 

 

$

 

 

 

 

 

(1

)

$

15.57

 

 

 

 

 

Ending balance, December 31

 

352

 

$

24.66

 

0.5

 

$

24,783

 

145

 

$

42.11

 

1.9

 

$

7,701

 

Exercisable at December 31

 

352

 

$

24.66

 

0.5

 

$

24,783

 

145

 

$

42.11

 

1.9

 

$

7,701

 

 

OTHER

 

During 2013, Occidental also granted approximately 160,000 share-equivalents to certain employees that vest at the end of a three-year period beginning January 1, 2014, if performance targets based on returns on assets of the applicable segment or capital employed are certified as being met. These awards are settled in stock at the time of vesting, with payouts that range from 0 to 200 percent of the target award. Dividend equivalents are accumulated and paid upon vesting for the number of vested shares. The weighted-average, grant-date fair value of these awards was $80.98.