Breitburn Energy Partners LP - FORM 10-K/A

Attached files

file	filename
EX-31.3 - Breitburn Energy Partners LP	v177740_ex31-3.htm
EX-32.2 - Breitburn Energy Partners LP	v177740_ex32-2.htm
EX-23.1 - Breitburn Energy Partners LP	v177740_ex23-1.htm
EX-32.3 - Breitburn Energy Partners LP	v177740_ex32-3.htm
EX-23.3 - Breitburn Energy Partners LP	v177740_ex23-3.htm
EX-32.1 - Breitburn Energy Partners LP	v177740_ex32-1.htm
EX-31.2 - Breitburn Energy Partners LP	v177740_ex31-2.htm
EX-31.1 - Breitburn Energy Partners LP	v177740_ex31-1.htm
EX-23.2 - Breitburn Energy Partners LP	v177740_ex23-2.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

Amendment No. 2

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2008

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ___ to ___

Commission File Number 001-33055

BreitBurn Energy Partners L.P.

(Exact name of registrant as specified in its charter)

Delaware	74-3169953
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)

515 South Flower Street, Suite 4800
Los Angeles, California	90071
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (213) 225-5900

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

Title of Each Class		Name of Each Exchange on Which Registered

Common Units Representing Limited Partner Interests		Nasdaq Global Select Market

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No þ

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (check one):

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

Indicate by check-mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

As of February 27, 2009, there were 52,770,011 Common Units outstanding. The aggregate market value of the Common Units held by non-affiliates of the registrant (98.69 percent) was approximately $1,124,000,000 for the Common Units on June 30, 2008 based on $21.63 per unit, the last reported sales price of the Common Units on the Nasdaq Global Select Market on such date. The calculation of the aggregate market value of the Common Units held by non-affiliates of the registrant is based on an assumption that Quicksilver Resources Inc., which owns 21,347,972 Common Units, representing 40.56 percent of the outstanding Common Units, is a non-affiliate of the registrant.

Documents Incorporated By Reference:

Portions of our definitive Proxy Statement for our 2009 Annual Meeting of Unitholders are hereby incorporated by reference into Part III hereof.

EXPLANATORY NOTE

BreitBurn Energy Partners L.P. is filing this Amendment No. 2 on Form 10-K/A (this “Amendment”) to amend its Annual Report on Form 10-K for the year ended December 31, 2008, filed with the Securities and Exchange Commission (the “SEC”) on March 2, 2009 (the “Original 10-K”).

This Amendment is being filed to amend the Original 10-K solely (i) to correct the certifications by our Principal Executive Officers and Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 due to the omission of the phrase “and internal control over financial reporting (as defined in Exchange Rules 13a-15(f) and 15d-15(f))” in the introductory portion of paragraph 4 of the certifications and the phrase “(the registrant’s fourth fiscal quarter in the case of an annual report)” in paragraph 4(d) of the certifications, (ii) to remove the inappropriate inclusion of the phrase “the audit committee of the board of directors of the registrant’s general partner” and replace it with the phrase “the audit committee of the registrant’s board of directors (or persons performing equivalent functions)” in paragraph 5 of the certifications, and (iii) to replace the phrase “Annual Report” with the word “report” in paragraphs 1, 2, 3 and 4(a) of the certifications. This amendment includes new certifications by our Principal Executive Officers and Principal Financial Officer pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act of 2002, filed as Exhibits 31.1, 31.2, 31.3, 32.1, 32.2 and 32.3 hereto. Each certification was true and correct as of the date of the filing of the Original 10-K.

Pursuant to interpretation 246.13 in the Regulation S-K section of the SEC’s “Compliance & Disclosure Interpretations,” we are also filing full Item 9A disclosures and our consolidated financial statements as part of this Amendment (collectively “Other Information”). Such Other Information was complete and correct as of the date of the filing of the Original 10-K.

Except as described above, we have not modified or updated other disclosures contained in the Original 10-K, including without limitation the Other Information. Accordingly, this Amendment, with the exception of the foregoing, does not reflect events occurring after the date of filing of the Original 10-K, or modify or update those disclosures affected by subsequent events. Consequently, all other information not affected by the corrections described above is unchanged and reflects the disclosures and other information made at the date of the filing of the Original 10-K and should be read in conjunction with our filings with the SEC subsequent to the filing of the Original 10-K, including amendments to those filings, if any.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information is accumulated and communicated to management, including our principal executive officers and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures. See “Management’s Report to Unitholders on Internal Control Over Financial Reporting” and “Reports of Independent Registered Public Accounting Firm” on page F-2 and F-3, respectively, of the consolidated financial statements.

Our general partner’s Chief Executive Officers and Chief Financial Officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of December 31, 2008, concluded that our disclosure controls and procedures were effective.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2008 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a)

(1)

Financial Statements

See “Index to the Consolidated Financial Statements” set forth on Page F-1.

(2)

Financial Statement Schedules

All schedules are omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

(3)

Exhibits

NUMBER		DOCUMENT
3.1		Certificate of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to Amendment No. 1 to Form S-1 filed on July 13, 2006).

3.2		First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K dated October 10, 2006 and filed on October 16, 2006).

3.3		Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K dated June 17, 2008 and filed on June 23, 2008).

3.4		Second Amendment and Restated Limited Liability Company Agreement of BreitBurn GP, LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K dated June 17, 2008 and filed on June 23, 2008).

4.1		Registration Rights Agreement, dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K dated November 1, 2007 and filed on November 6, 2007).

4.2		Unit Purchase Rights Agreement, dated as of December 22, 2008, between BreitBurn Energy Partners L.P. and American Stock Transfer & Trust Company LLC (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K dated December 22, 2008 and filed on December 23, 2008).

10.1		Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners I, L.P. dated May 5, 2003 (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated May 25, 2007 and filed May 29, 2007).

10.2		Contribution, Conveyance and Assumption Agreement, dated as of October 10, 2006, by and among Pro GP Corp., Pro LP Corp., BreitBurn Energy Corporation, BreitBurn Energy Company L.P., BreitBurn Management Company, LLC, BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating GP, LLC and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated October 10, 2006 and filed on October 16, 2006).

10.3		Administrative Services Agreement, dated as of October 10, 2006, by and among BreitBurn GP, LLC, BreitBurn Energy Partners L.P., BreitBurn Operating L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K dated October 10, 2006 and filed on October16, 2006).

NUMBER		DOCUMENT
10.4†		BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan effective as of October 10, 2006 (incorporated herein by reference to Exhibit 10.5 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).

10.5†		BreitBurn Energy Company L.P. Unit Appreciation Plan for Officers and Key Individuals (incorporated herein by reference to Exhibit 10.6 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).

10.6†		BreitBurn Energy Company L.P. Unit Appreciation Plan for Employees and Consultants (incorporated herein by reference to Exhibit 10.7 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).

10.7†		Amendment No. 1 to the BreitBurn Energy Company L.P. Unit Appreciation Plan for Officers and Key Individuals (incorporated herein by reference to Exhibit 10.14 to Amendment No. 5 to Form S-1 for BreitBurn Energy Partners L.P. filed on October 2, 2006).

10.8†		Amendment to the BreitBurn Energy Company L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.15 to Amendment No. 5 to Form S-1 for BreitBurn Energy Partners L.P. filed on October 2, 2006).

10.9†		BreitBurn Energy Company L.P. Long Term-Incentive Plan (incorporated herein by reference to Exhibit 10.8 to Amendment No. 3 to Form S-1 for BreitBurn Energy Partners L.P. filed on September 19, 2006).

10.10†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Award Agreement (for Directors) (incorporated herein by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the year ended December 31, 2006 and filed on April 2, 2007).

10.11†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Performance Unit-Based Award Agreement (incorporated herein by reference to Exhibit 10.17 to the Annual Report on Form 10-K for the year ended December 31, 2006 and filed on April 2, 2007).

10.12		Amended and Restated Asset Purchase Agreement, dated as of May 16, 2007, by and among BreitBurn Operating L.P. and Calumet Florida, LLC (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated May 24, 2007 and filed on May 31, 2007).

10.13		Unit Purchase Agreement, dated as of May 16, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated May 24, 2007 and filed on May 31, 2007).

10.14		Unit Purchase Agreement, dated as of May 25, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K dated May 25, 2007 and filed on May 29, 2007).

10.15		ORRI Distribution Agreement Limited Partner Interest Purchase and Sale Agreement, dated as of May 24, 2007, by and among BreitBurn Operating L.P. and TIFD X-III LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated May 25, 2007 and filed May 29, 2007).

10.16		Contribution Agreement, dated as of September 11, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).

10.17		Amendment to Contribution Agreement, dated effective as of November 1, 2007, between Quicksilver Resources Inc. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.5 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).

10.18		Amended and Restated Unit Purchase Agreement, dated as of October 26, 2007, by and among BreitBurn Energy Partners L.P. and each of the Purchasers set forth therein (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).

NUMBER		DOCUMENT
10.19		Amended and Restated Credit Agreement, dated November 1, 2007, by and among BreitBurn Operating L.P., as borrower, BreitBurn Energy Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as administrative agent (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K dated November 1, 2007 and filed November 6, 2007).

10.20†		Employment Agreement dated December 26, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Mark L. Pease (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated December 26, 2007 and filed December 27, 2007).

10.21†		First Amendment to the BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan dated December 26, 2007 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated November 5, 2007 and filed December 28, 2007).

10.22†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Executive Form) (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated March 5, 2008 and filed March 11, 2008).

10.23†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Unit Agreement (Non-Executive Form) (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated March 5, 2008 and filed March 11, 2008).

10.24†		Second Amended and Restated Employment Agreement dated December 31, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Halbert Washburn.

10.25†		Second Amended and Restated Employment Agreement dated December 31, 2007 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Randall Breitenbach.

10.26†		Employment Agreement date January 29, 2008 among BreitBurn Management Company, LLC, BreitBurn GP, LLC, Pro GP Corp. and Gregory C. Brown.

10.27†		Form of BreitBurn Energy Partners L.P. 2006 Long-Term Incentive Plan Restricted Phantom Units Directors’ Award Agreement.

10.28		Purchase Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated June 17, 2008 and filed on June 23, 2008).

10.29		Purchase Agreement dated June 17, 2008 by and among Pro LP Corporation, Pro GP Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated June 17, 2008 and filed on June 23, 2008).

10.30		Contribution Agreement dated June 17, 2008 by and among BreitBurn Management Company LLC, BreitBurn Energy Corporation and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.3 to the Current Report on Form 8-K dated June 17, 2008 and filed on June 23, 2008).

10.31		First Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement by and among BreitBurn Operating LP, BreitBurn Energy Partners L.P., as Parent Guarantor, its subsidiaries as guarantors, the Lenders and Wells Fargo Bank, National Association, as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.4 to the Current Report on Form 8-K dated June 17, 2008 and filed on June 23, 2008).

NUMBER		DOCUMENT
10.32		Amendment No. 1 to the Operations and Proceeds Agreement, relating to the Dominguez Field and dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.6 to the Current Report on Form 8-K dated June 17, 2008 and filed on June 23, 2008).

10.33		Amendment No. 1 to the Surface Operating Agreement dated October 10, 2006 entered into on June 17, 2008 by and between BreitBurn Energy Company L.P. and its predecessor BreitBurn Energy Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.7 to the Current Report on Form 8-K dated June 17, 2008 and filed on June 23, 2008).

10.34†		Employment Agreement Form for grant of Convertible Phantom units pursuant and subject to the terms and conditions of the Convertible Phantom Unit Agreement and the Partnership's 2006 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q dated June 30, 2008 and filed on August 11, 2008).

10.35†		Non-Employment Agreement Form for grant of Convertible Phantom units pursuant and subject to the terms and conditions of the Convertible Phantom Unit Agreement and the Partnership's 2006 Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q dated June 30, 2008 and filed on August 11, 2008).

10.36†		Amended and Restated Employment Agreement dated August 15, 2008 entered into by and between BreitBurn Management Company, LLC, BreitBurn GP, LLC and James Jackson (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated August 15, 2008 and filed on August 18, 2008).

10.37		Second Amended and Restated Administrative Services Agreement dated August 26, 2008 entered into by and between BreitBurn Energy Company L.P. and BreitBurn Management Company, LLC (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K dated August 26, 2008 and filed on September 02, 2008).

10.38		Omnibus Agreement, dated August 26, 2008, by and among BreitBurn Energy Holdings LLC, BEC (GP) LLC, BreitBurn Energy Company L.P, BreitBurn GP, LLC, BreitBurn management Company, LLC and BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 10.2 to the Current Report on Form 8-K dated August 26, 2008 and filed on September 02, 2008).

14.1		BreitBurn Energy Partners L.P. and BreitBurn GP, LLC Code of Ethics for Chief Executive Officers and Senior Officers (as amended and restated on February 28, 2007) (incorporated herein by reference to Exhibit 14.1 to the Current Report on Form 8-K dated February 28, 2007 and filed on March 5, 2007).

21.1		List of subsidiaries of BreitBurn Energy Partners L.P (incorporated herein by reference to Exhibit 21.1 to the Annual Report on Form 10-K for the year ended December 31, 2008 and filed on March 2, 2009).

23.1*		Consent of PricewaterhouseCoopers LLP

23.2*		Consent of Netherland, Sewell & Associates, Inc.

23.3*		Consent of Schlumberger Data and Consulting Services

31.1*		Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.

31.3*		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.

NUMBER		DOCUMENT
32.1**		Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of Registrant’s Co-Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.

32.3**		Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

** Furnished herewith.

† Management contract or compensatory plan or arrangement.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	BREITBURN ENERGY PARTNERS L.P.

	By:	BREITBURN GP, LLC,
		its General Partner

Dated: March 17, 2010	By:	/s/ Halbert S. Washburn
		Halbert S. Washburn
		Co-Chief Executive Officer

Dated: March 17, 2010	By:	/s/ Randall H. Breitenbach
		Randall H. Breitenbach
		Co-Chief Executive Officer

BreitBurn Energy Partners L.P. and Subsidiaries

INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

Management's Report to Unitholders on Internal Control over Financial Reporting	F-2

Reports of Independent Registered Public Accounting Firm	F-3

Consolidated Statements of Operations	F-5

Consolidated Balance Sheets	F-6

Consolidated Statements of Cash Flows	F-7

Consolidated Statements of Partners’ Equity	F-8

Notes to Consolidated Financial Statements	F-9

F-1

Management’s Report to Unitholders on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed by, or under the supervision of, the management of BreitBurn Energy Partners L.P., designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A partnership's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership's assets that could have a material effect on the financial statements.

Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation to the effectiveness of future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008 using the criteria established in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management has concluded that, as of December 31, 2008, we maintained effective internal control over financial reporting.

The effectiveness of our internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-3.

/s/ Halbert S. Washburn		/s/ Randall H. Breitenbach
Halbert S. Washburn		Randall H. Breitenbach
Co-Chief Executive Officer of BreitBurn GP, LLC		Co-Chief Executive Officer of BreitBurn GP, LLC

/s/ James G. Jackson
James G. Jackson
Chief Financial Officer of BreitBurn GP, LLC

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors of BreitBurn GP, LLC and Unitholders of BreitBurn Energy Partners L.P.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners’ equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries (“successor”) (“the Partnership”) at December 31, 2008 and 2007, and the results of their operations and their cash flows for the years ended December 31, 2008 and 2007 and the period from October 10, 2006 to December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report to Unitholders on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits (which were integrated audits in 2008 and 2007). 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 14 to the financial statements, the Partnership changed the manner in which it accounts for recurring fair value measurements of financial instruments in 2008.

A partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A partnership’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Los Angeles, California
March 2, 2009

F-3

Report of Independent Registered Public Accounting Firm

To the Board of Directors of BreitBurn GP, LLC and Unitholders of BreitBurn Energy Partners L.P.

In our opinion, the accompanying consolidated statements of operations, partners’ equity and cash flows present fairly, in all material respects, the results of operations and cash flows of BreitBurn Energy Company L.P. and its subsidiaries (“predecessor”) (the “Partnership”) for the period from January 1, 2006 to October 9, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in note 15 to the consolidated financial statements, the Partnership changed the manner in which it accounts for stock based compensation as of January 1, 2006.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Los Angeles, California
April 2, 2007

F-4

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Operations

	Successor									Predecessor
	Year Ended						October 10 to			January 1 to
	December 31,						December 31,			October 9,
Thousands of dollars, except per unit amounts	2008			2007			2006 (1)			2006

Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	467,381		$	184,372		$	18,452		$	110,329
Gains (losses) on commodity derivative instruments, net (note 14)		332,102			(110,418	)		882			2,291
Other revenue, net (note 10)		2,920			1,037			170			923
Total revenues and other income items		802,403			74,991			19,504			113,543
Operating costs and expenses:
Operating costs		149,681			70,329			7,159			34,893
Depletion, depreciation and amortization (note 5)		179,933			29,422			2,506			10,903
General and administrative expenses		43,435			30,588			7,938			18,849
Total operating costs and expenses		373,049			130,339			17,603			64,645

Operating income (loss)		429,354			(55,348	)		1,901			48,898

Interest and other financing costs, net		29,147			6,258			72			2,651
Loss on interest rate swaps (note 14)		20,035			-			-			-
Other (income) expenses, net		(191	)		(111	)		(2	)		(275	)

Income (loss) before taxes and minority interest		380,363			(61,495	)		1,831			46,522

Income tax expense (benefit) (note 6)		1,939			(1,229	)		(40	)		90
Minority interest (note 20)		188			91			-			(1,039	)

Net income (loss) before change in accounting principle		378,236			(60,357	)		1,871			47,471

Cumulative effect of change in accounting principle (note 15)		-			-			-			577

Net income (loss)		378,236			(60,357	)		1,871		$	48,048

General Partner's interest in net income (loss)		(2,019	)		(672	)		37

Limited Partners' interest in net income (loss)	$	380,255		$	(59,685	)	$	1,834

Basic net income (loss) per unit (note 2)	$	6.42		$	(1.83	)	$	0.08		$	0.27
Diluted net income (loss) per unit (note 2)	$	6.28		$	(1.83	)	$	0.08		$	0.27

(1) Reflects activity since closing of initial public offering on October 10, 2006. There was no activity from inception on March 23, 2006 to October 10, 2006.

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

F-5

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Balance Sheets

	December 31,			December 31,
Thousands of dollars, except unit amounts	2008			2007
ASSETS
Current assets:
Cash	$	2,546		$	5,929
Accounts receivable, net (note 2)		47,221			44,202
Derivative instruments (note 14)		76,224			948
Related party receivables (note 7)		5,084			35,568
Inventory (note 8)		1,250			5,704
Prepaid expenses		5,300			2,083
Intangibles (note 9)		2,771			3,169
Other current assets		170			160
Total current assets		140,566			97,763
Equity investments (note 10)		9,452			15,645
Property, plant and equipment
Oil and gas properties (note 4)		2,057,531			1,910,941
Non-oil and gas assets (note 4)		7,806			568
		2,065,337			1,911,509
Accumulated depletion and depreciation (note 5)		(224,996	)		(47,022	)
Net property, plant and equipment		1,840,341			1,864,487
Other long-term assets
Intangibles (note 9)		495			3,228
Derivative instruments (note 14)		219,003			-
Other long-term assets		6,977			5,433

Total assets	$	2,216,834		$	1,986,556
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable	$	28,302		$	13,910
Book overdraft		9,871			1,920
Derivative instruments (note 14)		10,192			35,172
Related party payables (note 7)		-			10,137
Revenue distributions payable		16,162			21,266
Derivative settlements payable		50			2,775
Salaries and wages payable		6,249			28
Accrued liabilities		9,164			5,476
Total current liabilities		79,990			90,684
Long-term debt (note 11)		736,000			370,400
Long-term related party payables (note 7)		-			1,532
Deferred income taxes (note 6)		4,282			3,074
Asset retirement obligation (note 12)		30,086			27,819
Derivative instruments (note 14)		10,058			65,695
Other long-term liabilities		2,987			2,000
Total liabilities		863,403			561,204
Minority interest (note 20)		539			544
Partners' equity (note 13)
Limited partners' interest (a)		1,352,892			1,423,418
General partner interest		-			1,390
Total liabilities and partners' equity	$	2,216,834		$	1,986,556

(a) Limited partner units outstanding		52,635,634			67,020,641

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

F-6

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Cash Flows

	Successor									Predecessor
	Year Ended						October 10 to			January 1 to
	December 31,						December 31,			October 9,
Thousands of dollars	2008			2007			2006(1)			2006

Cash flows from operating activities
Net income (loss)	$	378,236		$	(60,357	)	$	1,871		$	48,048
Adjustments to reconcile net income (loss) to cash flow from operating activities:
Depletion, depreciation and amortization		179,933			29,422			2,506			10,903
Unit-based compensation expense		6,907			12,999			4,490			7,979
Unrealized (gain) loss on derivative instruments		(370,734	)		103,862			1,299			(5,983	)
Distributions greater (less) than income from equity affiliates		1,198			(28	)		32			48
Deferred income tax		1,207			(1,229	)		(40	)		90
Minority interest		188			91			-			(1,039	)
Cumulative effect of change in accounting principle		-			-			-			(577	)
Amortization of intangibles		3,131			2,174			-			-
Other		2,643			2,182			51			950
Changes in net assets and liablities:
Accounts receivable and other assets		258			(24,713	)		(5,873	)		(5,569	)
Inventory		4,454			4,829			-			-
Net change in related party receivables and payables		32,688			(39,202	)		(9,017	)		(3,694	)
Accounts payable and other liabilities		(13,413	)		30,072			3,425			(3,576	)
Net cash provided (used) by operating activities		226,696			60,102			(1,256	)		47,580
Cash flows from investing activities(2)
Capital expenditures		(131,082	)		(23,549	)		(1,248	)		(36,941	)
Property acquisitions		(9,957	)		(996,561	)		-			(79	)
Proceeds from sale of assets, net		-			-			-			1,752
Net cash used by investing activities		(141,039	)		(1,020,110	)		(1,248	)		(35,268	)
Cash flows from financing activities
Issuance of common units, net of discount		-			663,338			118,715			-
Purchase of common units		(336,216	)		-			-			-
Redemptions of common units from predecessors		-			-			(15,485	)		-
Distributions to predecessor members concurrent with initial
public offering		-			581			(63,230	)		-
Distributions(3)		(121,349	)		(60,497	)		-			(36,357	)
Proceeds from the issuance of long-term debt		803,002			574,700			5,500			86,700
Repayments of long-term debt		(437,402	)		(205,800	)		(40,500	)		(67,200	)
Book overdraft		7,951			(116	)		2,036			3,610
Initial public offering costs		-			-			(4,055	)		(2,845	)
Long-term debt issuance costs		(5,026	)		(6,362	)		(400	)		-
Cash contributed by minority interest		-			-			-			2,399
Net cash provided (used) by financing activities		(89,040	)		965,844			2,581			(13,693	)
Increase (decrease) in cash		(3,383	)		5,836			77			(1,381	)
Cash beginning of period		5,929			93			16			2,740
Cash end of period	$	2,546		$	5,929		$	93		$	1,359

(1) Reflects activity since closing of initial public offering. There was no activity from inception March 23, 2006 to October 10th, 2006.

(2) Non-cash investing activity in 2007 was $700 million, reflecting the issuance of 21.348 million Common Units for the Quicksilver acquisition.

(3) Includes distributions on equivalent units of $2.3 million

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

F-7

BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Partners' Equity

	For the period from October 10, 2006 to
	December 31, 2008
Thousands of dollars	Limited Partners			General Partner			Total
Balance, October 10, 2006	$	-		$	-		$	-
Contributions (a)		136,035			2,776			138,811
Initial public offering investment (b)		99,175			-			99,175
Distributions to predecessor members concurrent with
initial public offering (c)		(62,649	)		-			(62,649	)
Net income		1,834			37			1,871
Balance, December 31, 2006	$	174,395		$	2,813		$	177,208
Issuance of units (d)		700,000			-			700,000
Private offering investment (e)		663,338			-			663,338
Distributions		(59,746	)		(751	)		(60,497	)
Unit-based compensation		5,133			-			5,133
Net loss		(59,685	)		(672	)		(60,357	)
Other		(17	)		-			(17	)
Balance, December 31, 2007	$	1,423,418		$	1,390		$	1,424,808
Redemtion of common units from predecessors (f)		(336,216	)		-			(336,216	)
Distributions		(118,580	)		(427	)		(119,007	)
Distributions paid on unissued units under incentive plans		(2,335	)		(7	)		(2,342	)
Unit-based compensation		7,383			-			7,383
Net income (loss) (g)		380,255			(2,019	)		378,236
Contribution of general partner interest to the partnership		(1,063	)		1,063			-
Other		30			-			30
Balance, December 31, 2008	$	1,352,892		$	-		$	1,352,892

(a) Represents book value contributions from predecessor.

(b) Net of underwriting discount and initial public offering costs.

(d) Reflects the issuance of 21.348 million Common Units for the Quicksilver acquisition.

(e) Reflects the issuance of 23.697 million Common Units in three private placements.

(f) Reflects the purchase of 14.405 million Common Units from subsidiaries of Provident.

(g) General partner interests were purchased as of June 17, 2008.

	Predecessor
	For the period from January 1, 2006 to October 9, 2006
Thousands of dollars	Pro LP Corp			Pro GP Corp			Breitburn S Corp			Total
Balance, January 1, 2006	$	230,352		$	960		$	8,713		$	240,025
Distributions paid or accrued		(34,628	)		(146	)		(1,619	)		(36,393	)
Net income		45,718			192			2,138			48,048
Balance, October 9, 2006	$	241,442		$	1,006		$	9,232		$	251,680

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

F-8

Notes to Consolidated Financial Statements

Note 1. Organization and Operations

BreitBurn Energy Partners L.P.

The Partnership is a Delaware limited partnership formed on March 23, 2006. In October 2006, we completed an initial public offering of 6,000,000 Common Units and completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering at $18.50 per unit, or $17.205 per unit, after deducting the underwriting discount. On May 24, 2007, we sold 4,062,500 Common Units in a private placement at $32.00 per unit, resulting in proceeds of approximately $130 million. The net proceeds of this private placement were used to acquire certain interests in oil leases and related assets located in Florida from Calumet Florida L.L.C. and to reduce indebtedness under our credit facility. On May 25, 2007, we sold 2,967,744 Common Units in a private placement at $31.00 per unit, resulting in proceeds of approximately $92 million. The net proceeds of this private placement were used to acquire a 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) from TIFD X-III LLC which owned interests in the Sawtelle and East Coyote oil fields located in California, and to terminate existing hedges related to future production from BEPI. On November 1, 2007, we sold 16,666,667 Common Units in a private placement at $27.00 per unit, resulting in proceeds of approximately $450 million. The net proceeds from this private placement were used to fund a portion of the cash consideration for our acquisition from Quicksilver of properties located in Michigan, Indiana and Kentucky (the “Quicksilver Acquisition”). Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.

Our general partner is BreitBurn GP, a Delaware limited liability company, also formed on March 23, 2006. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BOLP and BOLP’s general partner BOGP. We own all of the ownership interests in BOLP and BOGP.

Our wholly owned subsidiary BreitBurn Management manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 7 for information regarding our relationship with BreitBurn Management.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million (the “Common Unit Purchase”). These units have been cancelled and are no longer outstanding. This purchase was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units. It increased debt by $336.2 million and decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs.

On June 17, 2008, we also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner, for a purchase price of approximately $10 million (the “BreitBurn Management Purchase”). See Note 4 for the purchase price allocation for this transaction. Also on June 17, 2008, we entered into a contribution agreement (the “Contribution Agreement”) with the General Partner, BreitBurn Management and BreitBurn Corporation, which is wholly owned by the Co-Chief Executive Officers of the General Partner, Halbert S. Washburn and Randall H. Breitenbach, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units, the economic value of which was equivalent to the value of their combined 4.45 percent interest in BreitBurn Management, and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated and our limited partners holding Common Units were given a right to nominate and vote in the election of directors to the Board of Directors of the General Partner. As a result of these transactions (collectively, the “Purchase, Contribution and Partnership Transactions”), the General Partner and BreitBurn Management became our wholly owned subsidiaries.

F-9

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly owned subsidiaries entered into the First Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent and First Amendment to Security Agreement (“Amendment No. 1 to the Credit Agreement”), with Wells Fargo Bank, National Association, as administrative agent. Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement dated November 1, 2007 from $750 million to $900 million. We used borrowings under Amendment No. 1 to the Credit Agreement to finance the Common Unit Purchase and the BreitBurn Management Purchase.

As of December 31, 2008, the public unitholders, the institutional investors in our private placements and Quicksilver owned 98.69 percent of the Common Units. BreitBurn Corporation owned 690,751 Common Units, representing a 1.31 percent limited partner interest. We own 100 percent of the General Partner, BreitBurn Management and BOLP.

On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital Partners (“Greenhill”) and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC, previously owned by Provident, and the remaining indirect interests in BEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of the our senior management. BEC was a separate U.S. subsidiary of Provident and was our Predecessor.

2. Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries and our predecessor. Investments in affiliated companies with a 20 percent or greater ownership interest, and in which we do not have control, are accounted for on the equity basis. Investments in affiliated companies with less than a 20 percent ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than 50 percent interest are consolidated. Investments in which we own less than a 50 percent interest but are deemed to have control or where we have a variable interest in an entity where we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization, asset retirement obligations and impairment of oil and gas properties.

We account for business combinations using the purchase method, in accordance with SFAS No. 141 Accounting for Business Combinations. We use estimates to record the assets and liabilities acquired. All purchase price allocations are finalized within one year from the acquisition date.

F-10

Basis of Presentation

Our financial statements are prepared in conformity with U.S. generally accepted accounting principles. Certain items included in the prior year financial statements have been reclassified to conform to the 2008 presentation.

Business segment information

SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, establishes standards for reporting information about operating segments. Segment reporting is not applicable because our oil and gas operating areas have similar economic characteristics and meet the criteria for aggregation as defined in SFAS No. 131. We acquire, exploit, develop and explore for and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.

Revenue recognition

Revenues associated with sales of our crude oil and natural gas are recognized when title passes from us to our customer. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest (‘‘entitlement’’ method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions.

Cash and cash equivalents

We consider all investments with original maturities of three months or less to be cash equivalents. At December 31, 2008 and 2007 we had no such investments.

Accounts Receivable

Our accounts receivable are primarily from purchasers of crude oil and natural gas and counterparties to our financial instruments. Crude oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. During 2008 we terminated our crude oil derivative instruments with Lehman Brothers due to their bankruptcy, and at December 31, 2008, we had an allowance of $4.6 million related to these contracts. As of December 31, 2007, we did not carry an allowance for doubtful accounts receivable.

Inventory

Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded as inventory.

Investments in Equity Affiliates

Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production.

Property, plant and equipment

Oil and gas properties

We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred, including internal acquisition costs, relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.

F-11

Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization (“DD&A”) are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are computed on a property-by-property basis and recognized using the units-of-production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.

Non-oil and gas assets

Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from 3 to 30 years.

Oil and natural gas reserve quantities

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.

Asset retirement obligations

We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The computation of our asset retirement obligations (“ARO”) is prepared in accordance with Statement of Financial Accounting Standards (‘‘SFAS’’) No. 143, Accounting for Asset Retirement Obligations. This accounting standard applies to the fair value of a liability for an asset retirement obligation that is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.

Impairment of assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets,” as amended. Under SFAS 144, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted cash flows are forecast using five-year NYMEX forward strip prices at the end of the period and escalated thereafter at 2.5 percent. For impairment charges, the associated property’s expected future net cash flows are discounted using a rate of approximately ten percent. Reserves are calculated based upon reports from third-party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Because of the low commodity prices that existed at year end 2008, and the uncertainty surrounding future commodity prices and costs, we performed impairment tests on our long-lived assets at December 31, 2008.

We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. In 2008, we recorded $51.9 million in impairments and $34.5 million in price related depletion and depreciation adjustments. See Note 5 – Impairments and Price Related Depletion and Depreciation Adjustments. We did not record an impairment charge in 2007 and we recorded an impairment charge of $0.3 million in the fourth quarter of 2006 for one of our Wyoming properties. The charge was included in DD&A on the consolidated statement of operations.

F-12

Debt issuance costs

The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization.

Equity-based compensation

BreitBurn Management and the Predecessor had various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 15. Prior to January 1, 2006, the Predecessor applied the recognition and measurement principles of Accounting Principles Board (‘‘APB’’) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for those plans. The Predecessor used the method prescribed under Financial Accounting Standards Board (‘‘FASB’’) Interpretation No. 28, Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans—and interpretation of APB Opinions No. 15 and 25, to calculate the expenses associated with its awards.

Effective January 1, 2006, the Predecessor adopted the fair value recognition provisions of SFAS No. 123 (revised 2004) (SFAS No. 123(R)), Share Based Payments, using the modified-prospective transition method. Under this transition method, equity-based compensation expense for the periods after January 1, 2006 includes compensation expense for all equity-based compensation awards granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123, Accounting for Stock-Based Compensation and for options granted subsequent to January 1, 2006 in accordance with the provisions of SFAS No. 123(R). Unit based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities were charged to compensation expense based on the fair value provisions of SFAS No. 123(R). We and the Predecessor recognized these compensation costs on a graded-vesting method. Under the graded-vesting method a company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award was, in substance, multiple awards.

Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period.

Fair market value of financial instruments

The carrying amount of our cash, accounts receivable, accounts payable, and accrued expenses, approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt approximates fair value; however, changes in the credit markets at year-end may impact our ability to enter into future credit facilities at similar terms.

Accounting for business combinations

We and our Predecessor have accounted for all business combinations using the purchase method, in accordance with SFAS No. 141, Accounting for Business Combinations. Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets. We and our Predecessor have not recognized any goodwill from any business combinations.

F-13

Concentration of credit risk

We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings.

Derivatives

SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of all derivative instruments as assets or liabilities in our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. For derivatives designated as cash flow hedges, changes in fair value are recognized in other comprehensive income, to the extent the hedge is effective, until the hedged item is recognized in earnings. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness, as defined by SFAS No.133, is recognized immediately in earnings. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities. We currently do not designate any of our derivatives as hedges for accounting purposes.

Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value measurement under SFAS No. 157 is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date, considered from the perspective of a market participant that holds the asset or owes the liability. The objective of fair value measurement as defined in SFAS No. 157 is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.

Income taxes

Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.

We have three wholly owned subsidiaries, which are subject to corporate income taxes. We account for the taxes associated with one entity in accordance with SFAS No. 109, “Accounting for Income Taxes.” Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.

Effective January 1, 2007, we implemented FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.

We performed evaluations as of January 1, 2007, December 31, 2007 and December 31, 2008 and concluded that there were no uncertain tax positions requiring recognition in its financial statements. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows.

F-14

Net Income or loss per unit

Weighted average units outstanding for computing basic and diluted net income or loss per unit were:

	Successor						Predecessor
	Year Ended				October 10 to		January 1 to
	December 31,				December 31,		October 9,
	2008		2007		2006		2006
Weighted average number of Common Units used to calculate basic and diluted net income or loss per unit:
Basic		59,238,588		32,577,429		21,975,758		179,795,294
Dilutive (a)		1,322,107		-		43,150		-
Diluted		60,560,695		32,577,429		22,018,908		179,795,294

(a) 2007 does not include 310,513 potential anti-dilutive units issuable under the compensation plans.

We had 6,700,000 Common Units authorized for issuance under our long-term incentive compensation plans and there were approximately 1,422,171 partnership-based units outstanding that are eligible for receiving Common Units upon vesting at December 31, 2008.

Environmental expenditures

We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount any of these liabilities. At December 31, 2008 and 2007, we had a $2.0 million environmental liability related to a closure of a drilling pit in Michigan, which we assumed in the Quicksilver Acquisition.

3. Accounting Pronouncements

SFAS No. 157, Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 12, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually), to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. Earlier adoption is permitted, provided the company has not yet issued financial statements, including for interim periods, for that fiscal year. Effective January 1, 2008, we adopted SFAS No. 157, as amended by FSP 157-2. Adoption of SFAS No. 157 did not have a material impact on our results from operations or financial position.

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115” (“SFAS No. 159”). In February 2007, the FASB issued SFAS No. 159 which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value in situations in which they are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. The provisions of SFAS No. 159 became effective for us on January 1, 2008. We have elected not to adopt the fair value option allowed by SFAS No. 159, and, therefore, it had no impact on our financial position, results from operations or cash flows.

F-15

SFAS No. 141(revised 2007) “Business Combinations” (“SFAS No. 141R”). In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141R was issued in an effort to continue the movement toward the greater use of fair values in financial reporting and increased transparency through expanded disclosures. It changes how business acquisitions are accounted for and will impact financial statements at the acquisition date and in subsequent periods. Certain of these changes will introduce more volatility into earnings. The acquirer must now record all assets and liabilities of the acquired business at fair value, and related transaction and restructuring costs will be expensed rather than the previous method of being capitalized as part of the acquisition. SFAS No. 141R also impacts the goodwill impairment test associated with acquisitions, including those that close before the effective date of SFAS No. 141R. The definitions of a “business” and a “business combination” have been expanded, resulting in more transactions qualifying as business combinations. SFAS No. 141R is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 31, 2008 and earlier adoption is prohibited. We may experience a financial statement impact depending on the nature and extent of any new business combinations entered into after the effective date of SFAS No. 141R.

SFAS No. 160 “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51” (“SFAS No. 160”). In December 2007, the FASB issued SFAS No. 160 which requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The adoption of SFAS No. 160 is not expected to have a material impact on our results from operations or financial position.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS No. 161”). In March 2008, the FASB issued SFAS No. 161 which requires enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 has the same scope as Statement 133, and, accordingly, applies to all entities. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. This statement will require the additional disclosures detailed above.

FSP 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP 142-3”). In April 2008, the FASB issued FSP 142-3, which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of this FSP is to improve consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141 (revised 2007), “Business Combination” and other U.S. generally accepted accounting principles. FSP 142-3 is effective for fiscal years beginning after December 15, 2008. We do not expect the adoption of FSP 142-3 to have a material impact on our financial position, results of operations or cash flows.

SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). In May 2008, the FASB issued SFAS No. 162 which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). SFAS No. 162 became effective November 13, 2008. The adoption of SFAS No. 162 did not have an impact on our results from operations or financial position.

FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). In June 2008, the FASB issued FSP EITF 03-6-1. Under this FSP, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether they are paid or unpaid, are considered participating securities and should be included in the computation of earnings per share pursuant to the two-class method. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. In addition, all prior period earnings per share data presented should be adjusted retrospectively and early application is not permitted. We are currently evaluating the impact adoption of FSP EITF 03-6-1 may have on our earnings per share disclosures.

F-16

On December 31, 2008, the SEC issued Release No. 33-8995 for guidelines on new reserves estimate calculations and related disclosures. The new reserve estimate disclosures apply to all annual reports for fiscal years ending on or after December 31, 2009 and thereafter, and to all registration statements filed after that date. It does not permit companies to voluntarily comply at an earlier date. The revised proved reserve definition incorporates a new definition of “reasonable certainty” using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence” for deterministic method estimates, or a 90 percent recovery probability for probabilistic methods used in estimating proved reserves. The guideline also permits a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well. For reserve reporting purposes, it also replaces the end-of-the-year oil and gas reserve pricing with an unweighted average first-day-of-the-month pricing for the past 12 fiscal months. This would impact depletion calculations. Costs associated with reserves will continue to be measured on the last day of the fiscal year. A revised tabular presentation of reserves by development category, final product type, and oil and gas activity disclosure by geographic regions and significant fields and a general disclosure of the internal controls a company uses to assure objectivity in reserves estimation will be required. The adoption of SEC release No. 33-8995 is expected to have a material impact, which cannot be quantified at this point, on the calculation of our crude oil and natural gas reserves.

4. Acquisitions

On January 23, 2007, we completed the purchase of certain oil and gas properties, known as the “Lazy JL Field” in the Permian Basin of Texas, including related property and equipment. The purchase price for the Lazy JL Field acquisition was approximately $29.0 million in cash, and was financed through borrowings under our revolving credit facility. The transaction was accounted for using the purchase method in accordance with SFAS No. 141 and was effective January 1, 2007. The purchase price was allocated to the assets acquired and liabilities assumed as follows:

Thousands of dollars
Oil and gas properties	$	29,233
Current assets		2
Asset retirement obligation		(206	)
	$	29,029

In March 2007, we completed the purchase of certain oil and gas properties in California for approximately $1.0 million in cash.

In April 2007, we completed the purchase of additional interests in a certain oil and gas property in Wyoming for approximately $0.9 million in cash.

F-17

On May 24, 2007, BOLP entered into an Amended and Restated Asset Purchase Agreement with Calumet Florida, L.L.C. (“Calumet”), to acquire certain interests in oil leases and related assets located along the Sunniland Trend in South Florida through the acquisition of a limited liability company that owned all of the purchased assets (the “Calumet Acquisition” or “Calumet Properties”). The Calumet Properties are comprised of five separate oil fields, one 23-mile pipeline serving one field, one storage terminal and rights in a shipping terminal. The transaction closed on May 24, 2007. The purchase price was $100.0 million with an effective date of January 1, 2007. After adjustments for costs and revenues for the period between the effective date and the closing, including interest paid to the seller and after taking into account approximately 218,000 barrels of crude oil held in storage as of the closing date, and including acquisition related costs, our purchase price was approximately $109.9 million. The acquisition was financed through our sale of Common Units through a private placement (see Note 13 for additional information on the private placement). The acquiring subsidiary is a partnership and thus no deferred taxes were recognized for this transaction. The purchase price of $109.9 million, including approximately $0.4 million in acquisition costs was allocated to the assets acquired and liabilities assumed as follows:

Thousands of dollars
Inventories	$	10,533
Intangible assets		3,377
Oil and gas properties		100,584
Asset retirement obligation		(3,843	)
Other current liabilities		(729	)
	$	109,922

The purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, the most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and gas reserves were prepared by management. We applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a rate of approximately 10 percent. There were no estimated quantities of hydrocarbons other than proved reserves allocated in the purchase price of the Calumet Acquisition. The purchase price included the fair value attributable to the oil inventories held in storage at the closing date. We assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010. An intangible asset was established to value the portion of the crude oil contracts that were above market at closing in the purchase price allocation. Realized gains or losses from these contracts are recognized as part of oil sales and the intangible asset is being amortized over the life of the contracts.

On May 25, 2007, BOLP entered into a Purchase and Sale Agreement with TIFD X-III LLC (“TIFD”), pursuant to which it acquired TIFD’s 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) for a total purchase price of approximately $82 million (the “BEPI Acquisition”). BEPI owns properties in the East Coyote and Sawtelle Fields in the Los Angeles Basin in California. The general partner of BEPI is an affiliate of our general partner in which we have no ownership interest. As part of the transaction, BEPI distributed to an affiliate of TIFD a 1.5 percent overriding royalty interest in the oil and gas produced by BEPI from the two fields. The burden of the 1.5 percent override will be borne solely through our interest in BEPI. In connection with the acquisition, we also paid approximately $10.4 million to terminate existing hedge contracts related to future production from BEPI.

F-18

The BEPI Acquisition, including the termination of existing hedge contracts, was financed through our sale of Common Units in a private placement (see Note 13 for additional information on the private placement). The acquiring subsidiary is a partnership and thus no deferred taxes were recognized for this transaction. We allocated the purchase price of $92.5 million including approximately $0.1 million in acquisition costs to the assets acquired and liabilities assumed as follows:

Thousands of dollars
Current assets	$	2,813
Oil and gas properties		92,980
Current liabilities		(2,281	)
Asset retirement obligation		(582	)
Other		(398	)
	$	92,532

On November 1, 2007, we completed the acquisition of certain assets (the “QRI Assets”) and equity interests (the “Equity Interests”) in certain entities from Quicksilver Resources Inc. (“Quicksilver” or “QRI”) in exchange for $750 million in cash and 21,347,972 Common Units (the “Quicksilver Acquisition”). The issuance of Common Units to QRI was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(2) thereof. Pursuant to the terms and conditions of the Contribution Agreement entered into by BOLP and QRI, dated as of September 11, 2007 (the “Contribution Agreement”), BOLP completed the Quicksilver Acquisition. BOLP acquired all of QRI’s natural gas, oil and midstream assets in Michigan, Indiana and Kentucky. The midstream assets in Michigan, Indiana and Kentucky consist of gathering, transportation, compression and processing assets that transport and process our production and third party gas.

The purchase price allocations are based on reserve reports, quoted market prices and estimates by management. To estimate the fair values of acquired oil and gas reserves, we utilized the reserve engineers’ estimates of oil and natural gas proved reserves to arrive at estimates of future cash flows net of operating and development costs. The estimated future net cash flows were discounted using a rate of approximately ten percent. Included in the purchase price allocation is a $5.2 million intangible asset related to retention bonuses. In connection with the acquisition, we entered into an agreement with QRI which provides for QRI to fund retention bonuses payable for 139 retained employees from QRI in the event these employees remain continuously employed by us from November 1, 2007 through November 1, 2009 or in the event of termination without cause, disability or death.

Our final purchase price allocation including approximately $9.1 million of acquisition costs is presented below:

Thousands of dollars
Current assets	$	1,148
Investment		10,481
Intangible asset		5,193
Oil and gas properties - proved		1,132,955
Oil and gas properties - unproved		209,873
Pipelines and processing facilities		112,726
Long-term liabilities		(4,678	)
Asset retirement obligation		(8,248	)
	$	1,459,450

F-19

In December 2007, we acquired an additional interest in an oil and gas field located in Michigan for approximately $3.4 million.

Pro Forma Information

The following unaudited pro forma financial information presents a summary of our consolidated results of operations for 2007 and 2006, assuming the Calumet, BEPI and Quicksilver Acquisitions had been completed as of the beginning of each year, including adjustments to reflect the allocation of the purchase price to the acquired net assets. The pro forma financial information assumes that the initial public offering that occurred in 2006 occurred January 1, 2006. As such, the 2006 results are presented on a comparable basis to the Successor and are not presented as pro forma for the Predecessor. The pro forma financial information also assumes our 2007 private placements of Common Units (see Note 13) were completed as of the beginning of the year, since the private placements were contingent on two of the acquisitions. The revenues and expenses of these three acquisitions are included in the 2007 consolidated results of the Partnership effective May 24, May 25 and November 1, 2007. The pro forma financial information is not necessarily indicative of the results of operations if the acquisitions had been effective as of these dates.

	Pro Forma Year Ended December 31,
Thousands of dollars, except per unit amounts	2007 (1)			2006 (1)
Revenues	$	233,761		$	315,302
Net income (loss)		(43,966	)		66,720
Net income (loss) per unit
Basic	$	(0.65	)	$	0.99
Diluted		(0.65	)		0.99

(1) Results include losses on derivative instruments of $101.0 million for the year ended December 31, 2007 and $0.3 million for the year ended December 31, 2006.

On June 17, 2008, we purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management for a purchase price of approximately $10.0 million. This transaction resulted in BreitBurn Management becoming our wholly owned subsidiary and was accounted for as a business combination. The following table presents the purchase price allocation of the BreitBurn Management Purchase:

Thousands of dollars
Related party receivables - current, net	$	10,662
Other current assets		21
Oil and gas properties		8,451
Non-oil and gas assets		4,343
Related party receivables - non-current		6,704
Current liabilities		(13,510	)
Long-term liabilities		(6,704	)
	$	9,967

Certain of the current and long-term related party receivables are with the Partnership, so they are now eliminated in consolidation.

5. Impairments and Price Related Depletion and Depreciation Adjustments

Because of the low commodity prices at year end 2008, and the uncertainty surrounding future commodity prices as well as future costs, we performed impairment tests on our long-lived assets at December 31, 2008. For the year ended December 31, 2008, we recorded approximately $51.9 million for total impairments and $34.5 million for price related adjustments to depletion and depreciation expense.

F-20

We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved-reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for market supply and demand conditions for crude oil and natural gas. The impairment reviews and calculations are based on assumptions that are consistent with our business plans. See “Impairment of Assets” in Note 2. The low commodity price environment that existed at December 31, 2008 influenced our future commodity price projections. As a result, the expected discounted cash flows for many of our fields (i.e., fair values) were negatively impacted resulting in a charge to depletion and depreciation expense of approximately $51.9 million for field impairments for the year ended December 31, 2008.

An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.

Lower commodity prices also negatively impacted our oil and gas reserves in the fourth quarter of 2008 resulting in significant price related adjustments to our depletion and depreciation expense in the fourth quarter of 2008 as compared to the fourth quarter of 2007. These price related reserve reductions in 2008 resulted in additional depletion and depreciation charges of approximately $34.5 million for the fourth quarter and for the year ended December 31, 2008.

6. Income Taxes

We, our predecessor and all of our subsidiaries, with the exception of Phoenix Production Company, Alamitos Company and BreitBurn Management, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities. State income tax expenses are recorded for certain operations that are subject to state taxation in various states, primarily Michigan, California and Texas. The total state taxes paid were $0.5 million in 2008 and less than $0.1 million in 2007.

Our wholly-owned subsidiary, Phoenix Production Company, is a tax-paying corporation. We record an income tax provision in accordance with SFAS No. 109 “Accounting for Income Taxes.” In 2008 and 2007, Phoenix Production Company recorded $0.1 million and less than $0.1 million, respectively, for alternative minimum taxes. Phoenix Production Company also recorded a deferred federal income tax expense of $1.2 million in 2008 and a deferred federal income tax benefit of $1.3 million in 2007. The following is a reconciliation for Phoenix Production Company of federal income taxes at the statutory rates to federal income tax expense or benefit as reported in the consolidated statements of operations.

	Year Ended
	December 31,
Thousands of dollars	2008			2007
Income (loss) before taxes and minority interest	$	380,363		$	(61,495	)
Partnership income not subject to tax		376,459			(56,997	)
Income (loss) subject to tax		3,904			(4,498	)
Federal income tax rate		34	%		34	%
Income tax at statutory rate		1,327			(1,529	)
Other		-			300
Income tax expense (benefit)	$	1,327		$	(1,229	)

F-21

At December 31, 2008 and 2007, a net deferred federal income tax liability of $4.3 million and $3.1 million, respectively, was included in our consolidated balance sheet for Phoenix Production Company. As shown in the table below, the net deferred federal income tax liability primarily consisted of the tax effect of book and tax basis differences of certain assets and liabilities and the deferred federal income tax asset for net operating loss carry forwards. Management expects to utilize $2.3 million of estimated unused operating loss carry forwards to offset future taxable income. As such, no valuation allowance has been recorded against the deferred federal income tax asset.

	December 31,
Thousands of dollars	2008			2007
Deferred tax assets:
Net operating loss carryforwards	$	767		$	726
Asset retirement obligation		337			428
Unrealized hedge loss		-			1,104
Other		103			74
Deferred tax liabilities:
Depreciation, depletion and intangible drilling costs		(3,404	)		(5,356	)
Other		(2,085	)		(50	)
Net deferred tax liability	$	(4,282	)	$	(3,074	)

In 2008, our other wholly-owned tax-paying corporation, Alamitos Company, incurred a current federal tax expense of $0.1 million. No deferred federal or state income tax is recognized for this company as the temporary differences between the tax basis and the reported financial amounts of its assets and liabilities are immaterial. BreitBurn Management became our wholly-owned subsidiary and a taxable entity on June 17, 2008. However, no federal or state income tax expense is expected due to the nature of its business as expenses incurred are essentially offset by amounts recovered for services provided to the operating companies.

Cash paid for federal and state income taxes was $0.6 million in 2008, $0.1 million in 2007 and an immaterial amount in 2006.

New Accounting Pronouncement

7. Related Party Transactions

BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management became our wholly owned subsidiary and entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of $775,000 for indirect expenses. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct payroll and administrative costs. Beginning on June 17, 2008, all of the costs charged to BOLP are consolidated with our results.

F-22

During 2007, we incurred approximately $30.2 million in direct and indirect general and administrative expenses from BreitBurn Management, including accruals related to incentive compensation. We reimbursed BreitBurn Management $23.8 million under the Administrative Services Agreement during 2007. At December 31, 2007, we had a net short-term payable to BreitBurn Management of $9.2 million and a long-term payable of $1.5 million with both primarily relating to incentive compensation.

On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark, Greenhill and a third-party institutional investor, completed the acquisition of BEC, our Predecessor. This transaction included the acquisition of a 96.02 percent indirect interest in BEC previously owned by Provident and the remaining indirect interests in BEC previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management. BEC was an indirectly owned subsidiary of Provident.

In connection with the acquisition of Provident’s ownership in BEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into a five year Administrative Services Agreement to manage BEC's properties. The monthly fee charged to BEC remained $775,000 for indirect expenses through December 31, 2008. We expect this fee to be renegotiated annually during the term of the agreement and expect a monthly fee of less than $775,000 in 2009. In addition, we have entered into an Omnibus Agreement with BEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by BEC.

At December 31, 2008, we had current receivables of $4.4 million due from BEC related to the Administrative Services Agreement, outstanding liabilities for employee related costs and oil and gas sales made by BEC on our behalf from certain properties. At December 31, 2007, we had current receivables of $1.0 million due from BEC related to oil and gas sales made by BEC on our behalf from certain properties. In 2008 and 2007, total oil and gas sales made on our behalf for these properties were approximately $2.1 million and $1.7 million, respectively.

Mr. Greg L. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains All American GP LLC (“PAA”). Mr. Armstrong was a director of our General Partner until March 26, 2008 when his resignation became effective. We sell all of the crude oil produced from our Florida properties to Plains Marketing, L.P., a wholly owned subsidiary of PAA. In 2008, prior to Mr. Armstrong’s resignation on March 26, 2008, we sold $19.3 million of our crude oil to Plains Marketing, L.P. At December 31, 2007, the receivable from Plains Marketing, L.P. was $10.5 million, which was collected in the first quarter of 2008.

Through a transition services agreement through March 2008, Quicksilver provided services to us for accounting, land administration, and marketing and charged us $0.9 million for the first three months of 2008 and $0.6 million for the year ended December 31, 2007. These charges were included in general and administrative expenses on the consolidated statements of operations. At December 31, 2007, the net receivable from Quicksilver was approximately $22.7 million which reflected cash collections made on our behalf net of advances. In 2008, we collected these outstanding receivables from Quicksilver. Quicksilver also buys natural gas from us in Michigan. For the year ended December 31, 2008, total net gas sales to Quicksilver were approximately $8.0 million and the related receivable was $0.6 million as of December 31, 2008.

At December 31, 2008, we had a receivable of $0.1 million for management fees due from equity affiliates and operational expenses incurred on behalf of equity affiliates. At December 31, 2007, we had a receivable of $1.4 million, which primarily included a $1.3 million receivable for a cash advance made to an equity affiliate that was repaid in 2008.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the General Partner, Provident, Pro GP and BEC was terminated in all respects and Provident is no longer considered a related party. At December 31, 2007, we had a payable to Provident of $0.9 million relating primarily to the management agreement and insurance costs that were provided by Provident on our behalf.

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8. Inventory

Our crude oil inventory from our Florida operations at December 31, 2008 and December 31, 2007 was $1.3 million and $5.5 million respectively. At December 31, 2007, we had an additional $0.2 million in non-crude oil inventory. Inventories purchased through the Calumet Acquisition (see Note 4) were $10.5 million, which were sold and charged to the consolidated statement of operations as inventory cost during the year ended December 31, 2007. For the year ended December 31, 2008, we sold 762 MBbls of crude oil and produced 707 MBbls from our Florida operations. Crude oil inventory additions are at cost and represent our production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory. Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter.

We carry inventory at the lower of cost or market. When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal. During the fourth quarter of 2008, commodity prices decreased substantially. As a result, we assessed our crude oil inventory for possible write-down, and recorded $1.2 million to write-down the Florida crude oil inventory to our net realizable value at December 31, 2008.

For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production in Florida, which could have a negative impact on our future consolidated financial position, results of operations or cash flows.

9. Intangibles

In May 2007, we acquired certain interests in oil leases and related assets through the acquisition of a limited liability company from Calumet Florida, L.L.C. As part of this acquisition, we assumed certain crude oil sales contracts for the remainder of 2007 and for 2008 through 2010. A $3.4 million intangible asset was established to value the portion of the crude oil contracts that were above market at closing in the purchase price allocation. Realized gains or losses from these contracts are recognized as part of oil sales and the intangible asset will be amortized over the life of the contracts. As of December 31, 2008, our intangible asset related to the crude oil sales contracts was $1.6 million.

In November 2007, we acquired oil and gas properties and facilities from Quicksilver. Included in the Quicksilver purchase price was a $5.2 million intangible asset related to retention bonuses. In connection with the acquisition, we entered into an agreement with Quicksilver which provides for Quicksilver to fund retention bonuses payable to 139 former Quicksilver employees in the event these employees remain continuously employed by BreitBurn Management from November 1, 2007 through November 1, 2009 or in the event of termination without cause, disability or death. The amortization expense of $2.1 million for 2008 and $1.4 million for 2007 are included in the total operating expenses line on the consolidated statement of operations. As of December 31, 2008, our intangible asset related to Quicksilver retention bonuses was $1.7 million.

10. Equity Investments

We had equity investments at December 31, 2008 and December 31, 2007 of $9.5 million and $15.6 million, respectively. These investments are reported in the “Equity investments” line caption on the consolidated balance sheet and primarily represent investments in natural gas processing facilities. For the years ended December 31, 2008 and 2007, we recorded $0.8 million and $0.3 million, respectively, in earnings from equity investments. Earnings from equity investments are reported in the “Other Revenue” line caption on the consolidated statement of operations.

At December 31, 2008, our equity investments consisted primarily of a 24.5 percent limited partner interest and a 25.5 percent general partner interest in Wilderness Energy Services LP, with a combined carrying value of $8.2 million. The remaining $1.3 million consists of smaller interests in several other investments. At December 31, 2007, our equity investment totaled $15.6 million. The decrease in 2008 is primarily due to the final purchase price allocations related to our Quicksilver asset purchase.

11. Long-Term Debt

On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly owned subsidiaries, as guarantors, entered into a four year, $1.5 billion amended and restated revolving credit facility with Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of banks (the “Amended and Restated Credit Agreement”).

F-24

The initial borrowing base of the Amended and Restated Credit Agreement was $700 million and was increased to $750 million on April 10, 2008. Under the Amended and Restated Credit Agreement, borrowings were allowed to be used (i) to pay a portion of the purchase price for the Quicksilver Acquisition, (ii) for standby letters of credit, (iii) for working capital purposes, (iv) for general company purposes and (v) for certain permitted acquisitions and payments enumerated by the credit facility. Borrowings under the Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of the Partnership’s and certain of its subsidiaries’ assets, representing not less than 80 percent of the total value of their oil and gas properties.

The Amended and Restated Credit Agreement contains (i) financial covenants, including leverage, current assets and interest coverage ratios, and (ii) customary covenants, including restrictions on the Partnership’s ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90 percent of its borrowing base; make dispositions; or enter into a merger or sale of its property or assets, including the sale or transfer of interests in its subsidiaries.

The events that constitute an Event of Default (as defined in the Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against the Partnership in excess of a specified amount; changes in management or control; loss of permits; failure to perform under a material agreement; certain insolvency events; assertion of certain environmental claims; and occurrence of a material adverse effect. At December 31, 2008 and December 31, 2007, the Partnership was in compliance with the credit facility’s covenants.

On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, we and our wholly owned subsidiaries entered into Amendment No. 1 to the Amended and Restated Credit Agreement, with Wells Fargo Bank, National Association, as administrative agent (the “Agent”). Amendment No. 1 to the Credit Agreement increased the borrowing base available under the Amended and Restated Credit Agreement, from $750 million to $900 million. In addition, Amendment No. 1 to the Credit Agreement enacted certain additional amendments, waivers and consents to the Amended and Restated Credit Agreement and the related Security Agreement, dated November 1, 2007, among BOLP, certain of its subsidiaries and the Agent, necessary to permit the Amendment No. 1 to the First Amended and Restated Limited Partnership Agreement and the transactions consummated in the Purchase, Contribution and Partnership Transactions. Under Amendment No. 1 to the Credit Agreement, the interest margins applicable to borrowings, the letter of credit fee and the commitment fee under the Amended and Restated Credit Agreement were increased by amounts ranging from 12.5 to 25 basis points.

As of December 31, 2008, approximately $736.0 million in indebtedness was outstanding under the Amended and Restated Credit Agreement. The credit facility will mature on November 1, 2011. At December 31, 2008, the LIBOR interest rate, a weighted average interest rate of our four outstanding LIBOR loans, was 2.350 percent on the LIBOR portion of $736.0 million.

As of December 31, 2007, approximately $370.4 million in indebtedness was outstanding under the Amended and Restated Credit Agreement. At December 31, 2007, the interest rate was the Prime Rate of 7.625 percent on the Prime Debt portion of $3.4 million and the LIBOR rate of 6.595 percent on the LIBOR portion of $367.0 million.

The credit facility contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders (including the restriction in our ability to make distributions if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.

As of December 31, 2008 and 2007, we were in compliance with the credit facility’s covenants. At December 31, 2008 and 2007, we had $0.3 million and $0.3 million, respectively, in letters of credit outstanding.

Previous to the amended and restated credit agreement, we had in place a $400 million revolving credit facility with Wells Fargo Bank, N.A., as lead arranger, administrative agent, and issuing lender, and a syndicate of banks. We entered the $400 million credit facility on October 10, 2006, in connection with our initial public offering. The credit facility’s initial borrowing base was $90 million and was increased to $100 million in December 2006. At December 31, 2006, the interest rate was the Prime Rate of 8.5 percent on the Prime Debt portion of $1.5 million.

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Our interest expense is detailed in the following table:

	Successor						Predecessor
	Year Ended				October 10 to		January 1 to
	December 31,				December 31,		October 9,
Thousands of dollars	2008		2007		2006		2006
Credit facility	$	25,487	$	5,373	$	11	$	2,510
Commitment fees		1,047		503		61		141
Amortization of discount and deferred issuance costs		2,613		382		-		-
Total	$	29,147	$	6,258	$	72	$	2,651
Cash paid for interest on Credit facility (including realized losses on interest rate swaps)	$	29,767	$	3,545	$	72	$	2,651

12. Asset Retirement Obligation

Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities as well as our estimate of the future timing of the costs to be incurred. The total undiscounted amount of future cash flows required to settle our asset retirement obligations is estimated to be $256.8 million at December 31, 2008 and was $225.2 million at December 31, 2007. The increase from prior year is attributable to increased cost estimates primarily for California fields. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from 7 to 50 years. Estimated cash flows have been discounted at our credit adjusted risk free rate of 7 percent and adjusted for inflation using a rate of 2 percent. Changes in the asset retirement obligation for the years ended December 31, 2008 and 2007 are presented in the following table:

	Year Ended December 31,
Thousands of dollars	2008			2007
Carrying amount, beginning of period	$	27,819		$	10,253
Liabilities settled in the current period		(1,054	)		(367	)
Revisions (1)		1,363			3,950
Acquisitions		-			12,955
Accretion expense		1,958			1,028

Carrying amount, end of period	$	30,086		$	27,819

(1) Increased cost estimates and revisions to reserve life.

13. Partners’ Equity

At December 31, 2008, we had 52,635,634 Common Units outstanding.

On June 17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at $23.26 per unit, for a purchase price of approximately $335 million. These units have been cancelled and are no longer outstanding. This transaction was accounted for as a repurchase of issued Common Units and a cancellation of those Common Units. This transaction decreased equity by $336.2 million, including $1.2 million in capitalized transaction costs. We also purchased Provident’s 95.55 percent limited liability company interest in BreitBurn Management, which owned the General Partner. Also on June 17, 2008, we entered into a Contribution Agreement with the General Partner, BreitBurn Management and BreitBurn Corporation, pursuant to which BreitBurn Corporation contributed its 4.45 percent limited liability company interest in BreitBurn Management to us in exchange for 19,955 Common Units and BreitBurn Management contributed its 100 percent limited liability company interest in the General Partner to us. On the same date, we entered into Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of the Partnership, pursuant to which the economic portion of the General Partner’s 0.66473 percent general partner interest in us was eliminated. As a result of these transactions, the General Partner and BreitBurn Management became our wholly owned subsidiaries.

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On December 22, 2008, we entered into a Unit Purchase Rights Agreement, dated as of December 22, 2008 (the “Rights Agreement”), between us and American Stock Transfer & Trust Company LLC, as Rights Agent. Under the Rights Agreement, each holder of Common Units at the close of business on December 31, 2008 automatically received a distribution of one unit purchase right (a “Right”), which entitles the registered holder to purchase from us one additional Common Unit at a price of $40.00 per Common Unit, subject to adjustment. We entered into the Rights agreement to increase the likelihood that our unitholders receive fair and equal treatment in the event of a takeover proposal.

The issuance of the Rights was not taxable to the holders of the Common Units, had no dilutive effect, will not affect our reported earnings per Common Unit, and will not change the method of trading the Common Units. The Rights will not trade separately from the Common Units unless the Rights become exercisable. The Rights will become exercisable if a person or group acquires beneficial ownership of 20 percent or more of the outstanding Common Units or commences, or announces its intention to commence, a tender offer that could result in beneficial ownership of 20 percent or more of the outstanding Common Units. If the Rights become exercisable, each Right will entitle holders, other than the acquiring party, to purchase a number of Common Units having a market value of twice the then-current exercise price of the Right. Such provision will not apply to any person who, prior to the adoption of the Rights Agreement, beneficially owns 20 percent or more of the outstanding Common Units until such person acquires beneficial ownership of any additional Common Units.

The Rights Agreement has a term of three years and will expire on December 22, 2011, unless the term is extended, the Rights are earlier redeemed or we terminate the Rights Agreement.

Cash Distributions

The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.

Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future.

Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.

We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.

On February 14, 2008, we paid a cash distribution of approximately $30.5 million to our General Partner and common unitholders of record as of the close of business on February 11, 2008. The distribution that was paid to unitholders was $0.4525 per Common Unit.

On May 15, 2008, we paid a cash distribution of approximately $33.7 million to our General Partner and common unitholders of record as of the close of business on May 9, 2008. The distribution that was paid to unitholders was $0.50 per Common Unit.

F-27

On August 14, 2008, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on August 11, 2008. The distribution that was paid to unitholders was $0.52 per Common Unit.

On November 14, 2008, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on November 10, 2008. The distribution that was paid to unitholders was $0.52 per Common Unit.

During the year ended December 31, 2008, we made payments equivalent to the distributions made to unitholders of $2.3 million on Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.

2007 Private Placements

On May 24, 2007, we sold 4,062,500 Common Units, at a negotiated purchase price of $32.00 per unit, to certain investors (the “Purchasers”). We used $108 million from such sale to fund the cash consideration for the Calumet Acquisition and the remaining $22 million of the proceeds was used to repay indebtedness under our credit facility. Most of the debt repaid was associated with our first quarter 2007 acquisition of the Lazy JL Field properties in West Texas.

On May 25, 2007, we sold an additional 2,967,744 Common Units to the same Purchasers at a negotiated purchase price of $31.00 per unit. We used the proceeds of approximately $92 million to fund the BEPI Acquisition, including the termination of existing hedge contracts related to future production from BEPI.

On November 1, 2007, we sold 16,666,667 Common Units, at a negotiated purchase price of $27.00 per unit, to certain investors in a third private placement. We used the proceeds from such sale to fund a portion of the cash consideration for the Quicksilver Acquisition. Also on November 1, 2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration for the Quicksilver Acquisition as a private placement.

In connection with the private placements of Common Units to finance the Quicksilver Acquisition, we entered into registration rights agreements with the institutional investors in our private placements and Quicksilver to file shelf registration statements to register the resale of the Common Units sold or issued in the Private Placements and to use our commercially reasonable efforts to cause the registration statements to become effective with respect to the Common Units sold to the institutional investors not later than August 2, 2008 and, with respect to the Common Units issued to Quicksilver, within one year from November 1, 2007. Quicksilver is prohibited from selling any of the Common Units issued to it prior to the first anniversary of November 1, 2007 or more than 50 percent of such Common Units prior to eighteen months after November 1, 2007. In addition, the agreements give the institutional investors and Quicksilver piggyback registration rights under certain circumstances. These registration rights are transferable to affiliates of the institutional investors and Quicksilver and, in certain circumstances, to third parties.

On July 31, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to the institutional investors was declared effective. On October 28, 2008, the registration statement relating to the resale of the Common Units issued in the private placement to Quicksilver was declared effective.

F-28

14. Financial Instruments

Fair Value of Financial Instruments

Our commodity price risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash flow and distributions. Routinely, we utilize derivative financial instruments to reduce this volatility. During 2008, there has been extreme volatility and disruption in the capital and credit markets which has reached unprecedented levels and may adversely affect the financial condition of our derivative counterparties. Although each of our derivative counterparties carried an S&P credit rating of A or above at December 31, 2008, we could be exposed to losses if a counterparty fails to perform in accordance with the terms of the contract. This risk is managed by diversifying the derivative portfolio among counterparties meeting certain financial criteria.

Commodity Activities

The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under SFAS No. 133. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges and instead recognize changes in the fair value immediately in earnings. For the year ended December 31, 2008 we had realized losses of $55.9 million and unrealized gains of $388.0 million relating to our market based commodity contracts. We had net financial instruments receivable relating to our commodity contracts of $292.3 million at December 31, 2008.

For the year ended December 31, 2007, we had realized losses of $6.6 million and unrealized losses of $103.9 million relating to our market based commodity contracts. We had net financial instruments payable of $99.9 million at December 31, 2007. For the period October 10, 2006 to December 31, 2006, we had realized gains of $2.2 million and unrealized losses of $1.3 million relating to our market based commodity contracts. We had net financial instruments receivable of $3.9 million at December 31, 2006.

For the period from January 1, 2006 to October 9, 2006, the predecessor had realized losses of $3.7 million and unrealized gains of $6.0 million relating to various market based contracts.

On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated our crude oil derivative instruments with Lehman Brothers. Our derivative contract with Lehman Brothers, commonly referred to as a “zero cost collar,” was for oil volumes of 1,000 Bbls/d for the full year 2011. This represented approximately 8 percent of our total 2011 oil and natural gas hedge portfolio. The floor price for the collar was $105.00 per Bbl and the ceiling price was $174.50 per Bbl. This contract was replaced with contracts by substantially similar terms, with different counterparties, for oil volumes of 1,000 Bbls/d covering January 1, 2011 to January 31, 2011 and March 1, 2011 to December 31, 2011.

F-29

We had the following contracts in place at December 31, 2008:

	Year			Year			Year			Year
	2009			2010			2011			2012
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		45,802			43,869			25,955			19,129
Average Price ($/MMBtu)	$	8.14		$	8.20		$	9.21		$	10.12
Collars:
Hedged Volume (MMBtu/d)		1,740			3,405			16,016			19,129
Average Floor Price ($/MMBtu)	$	9.00		$	9.00		$	9.00		$	9.00
Average Ceiling Price ($/MMBtu)	$	16.36		$	12.79		$	11.28		$	11.89
Total:
Hedged Volume (MMMBtu/d)		47,542			47,275			41,971			38,257
Average Price ($/MMBtu)	$	8.17		$	8.26		$	9.13		$	9.56

Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		1,838			2,308			2,116			1,939
Average Price ($/Bbl)	$	75.51		$	83.12		$	88.26		$	90.00
Participating Swaps: (a)
Hedged Volume (Bbls/d)		2,847			1,993			1,439			-
Average Price ($/Bbl)	$	62.86		$	64.40		$	61.29		$	-
Average Part. %		60.9	%		55.5	%		53.2	%		-
Collars:
Hedged Volume (Bbls/d)		594			1,279			2,048			3,077
Average Floor Price ($/Bbl)	$	92.31		$	102.84		$	103.43		$	110.00
Average Ceiling Price ($/Bbl)	$	122.92		$	136.16		$	152.61		$	145.39
Floors:
Hedged Volume (Bbls/d)		500			500			-			-
Average Floor Price ($/Bbl)	$	100.00		$	100.00		$	-		$	-
Total:
Hedged Volume (Bbls/d)		5,778			6,080			5,603			5,016
Average Price ($/Bbl)	$	73.12		$	82.52		$	86.88		$	102.27

(a) A participating swap combines a swap and a call option with the same strike price.

Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of December 31, 2008, our total debt outstanding was $736.0 million. In order to mitigate our interest rate exposure, we had the following interest rate swaps in place at December 31, 2008, to fix a portion of floating LIBOR-base debt on our credit facility:

Notional amounts in thousands of dollars	Notional Amount		Fixed Rate
Period Covered
January 1, 2009 to January 8, 2009	$	50,000		3.6200	%
January 1, 2009 to January 20, 2009		200,000		3.6825	%
January 1, 2009 to July 8, 2009		50,000		3.0450	%
January 1, 2009 to January 8, 2010		100,000		3.3873	%
January 20, 2009 to July 20, 2009		250,000		3.6825	%
July 20, 2009 to December 20, 2010		300,000		3.6825	%
December 20, 2010 to October 20, 2011		200,000		2.9900	%

F-30

On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no cost, our interest rate swap with Lehman Brothers on $50 million at a fixed rate of 3.438 percent, which covered the period from January 8, 2008 to July 8, 2009. On October 2, 2008, we entered into a new interest rate swap on $50 million at a fixed rate of 3.0450 percent, for the period from September 8, 2008 to July 8, 2009. These transactions are reflected in the table above.

For the year ended December 31, 2008, we had realized losses of $2.7 million and unrealized losses of $17.3 million relating to our interest rate swaps. We had net financial instruments payable related to our interest rate swaps of $17.3 million at December 31, 2008.

Balance Sheet presentation of commodity and interest derivatives is as follows:

Thousands of dollars	Oil Commodity Derivatives			Natural Gas Commodity Derivatives		Interest Rate Derivatives			Total Financial Instruments
Balance, December 31, 2008
Short-term assets	$	44,086		$	32,138	$	-		$	76,224
Long-term assets		145,061			73,942		-			219,003
Total assets		189,147			106,080		-			295,227

Short-term liabilities		(1,115	)		-		(9,077	)		(10,192	)
Long-term liabilities		(1,820	)		-		(8,238	)		(10,058	)
Total liabilities		(2,935	)		-		(17,315	)		(20,250	)

Net assets (liabilities)	$	186,212		$	106,080	$	(17,315	)	$	274,977

While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.

SFAS No. 157 requires valuation techniques consistent with the market approach, income approach or the cost approach to be used to measure fair value. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to convert future cash flows or earnings to a single present value amount and is based upon current market expectations about those future amounts. The cost approach, sometimes referred to as the current replacement cost approach, is based upon the amount that would currently be required to replace the service capacity of an asset.

We principally use the income approach for our recurring fair value measurements and strive to use the best information available. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements.

SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. The highest priority of Level 1 is given to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 is given to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs as defined in SFAS No. 157 are described further as follows:

F-31

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are markets in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. An example of a Level 1 input would be quoted prices for exchange traded commodity futures contracts.

Level 2 – Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. These models include industry standard models that consider standard assumptions such as quoted forward prices for commodities, interest rates, volatilities, current market and contractual prices for underlying assets as well as other relevant factors. Substantially all of these inputs are evident in the market place throughout the terms of the financial instruments and can be derived by observable data, including third party data providers. These inputs may also include observable transactions in the market place. We consider the over the counter (OTC) commodity and interest rate swaps in our portfolio to be Level 2. These are assets and liabilities that can be bought and sold in active markets and quoted prices are available from multiple potential counterparties.

Level 3 – Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. These inputs generally reflect management’s estimates of the assumptions market participants would use when pricing the instruments. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Level 3 instruments primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Level 3 also includes complex structured transactions that sometimes require the use of non-standard models.

Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. We include these assets and liabilities in Level 3 as required by current interpretations of SFAS 157. As of December 31, 2008, our Level 3 assets and liabilities consisted entirely of OTC commodity put and call options.

Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data or the interpretation of Level 2 criteria is modified in practice to include non-binding market corroborated data.

As mentioned in Note 7, our wholly owned subsidiary BreitBurn Management provides us with general management services, including risk management activities. Pursuant to a transition services agreement that terminated on December 31, 2008, BreitBurn Management contracted with Provident for the risk management services provided to us.

Provident’s risk management group calculated the fair values of our commodity swaps using risk management software that marks to market monthly fixed price delivery swap volumes using forward commodity price curves and market interest rates. This pricing approach is commonly used by market participants to value commodity swap contracts for sale to the market. Inputs are obtained from third party data providers and are verified to published data where available (e.g., NYMEX).

Fair value measurements for our interest rate swaps were also provided by Provident. Monthly outstanding notional amounts are marked to market for each specific swap using forward interest rate curves. This pricing approach is commonly used by market participants to value interest rate swap contracts for sale to the market. Inputs are obtained from third party data providers and are verified to published data where available (e.g., LIBOR).

Provident’s risk management group used industry standard option pricing models contained in their risk management software to calculate the fair values associated with our commodity options. Inputs to the option pricing models included fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs were obtained from third party data providers and are verified to published data where available (e.g., NYMEX).

We reviewed the fair value calculations for our derivative instruments that we received from Provident’s risk management group on a monthly basis. We also compared these fair value amounts to the fair value amounts that we receive from the counterparties to our derivative instruments. We investigated differences and resolve and recorded any required changes prior to the issuance of our financial statements.

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Financial assets and liabilities carried at fair value on a recurring basis are presented in the table below. Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are categorized.

Recurring fair value measurements were:

	As of December 31, 2008
Thousands of dollars	Level 1		Level 2			Level 3		Total
Assets (Liabilities):
Commodity Derivatives (swaps, put and call options)	$	-	$	139,074		$	153,218	$	292,292
Other Derivatives (interest rate swaps)		-		(17,315	)		-		(17,315	)
Total	$	-	$	121,759		$	153,218	$	274,977

The following table sets forth a reconciliation of our derivative instruments classified as Level 3:

Thousands of dollars	Year Ended December 31, 2008
Assets (Liabilities):
Beginning balance	$	44,236
Realized and unrealized gains (losses)		106,154
Purchases and issuances		7,452
Settlements		(4,624	)
Balance at December 31, 2008	$	153,218

Following the termination of the Lehman Brothers interest rate swap and crude oil zero cost collar, we entered into similar contracts with other counterparties. Our net cost to replicate the terminated Lehman contracts was $4.2 million and we have recorded a provision related to the contract default in 2008. We have a claim of approximately $4.6 million in the Lehman bankruptcy case relating to the terminations.

Unrealized gains of $112.2 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations. Realized losses of $6.0 million for the year ended December 31, 2008 related to our derivative instruments classified as Level 3 are also included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations. Determination of fair values incorporates various factors as required by SFAS No. 157 including but not limited to the credit standing of the counterparties, the impact of guarantees as well as our own abilities to perform on our liabilities.

15. Unit and Other Valuation-Based Compensation Plans

BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. On June 17, 2008, in connection with the Purchase, Contribution and Partnership Transactions, BreitBurn Management became our wholly owned subsidiary and entered into an Amended and Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn Management agreed to continue to provide administrative services to BEC, in exchange for a monthly fee of $775,000 for indirect expenses. In addition to the monthly fee, BreitBurn Management agreed to continue to charge BEC for direct expenses including incentive plan costs and direct payroll and administrative costs. Beginning on June 17, 2008, all of BMC’s costs that were not charged to BEC are consolidated with our results.

F-33

Prior to June 17, 2008, BreitBurn Management provided services to us and to BEC, and allocated its expenses between the two entities. We were managed by our General Partner, the executive officers of which were and are employees of BreitBurn Management. We had entered into an Administrative Services Agreement with BreitBurn Management. Under the Administrative Services Agreement, we reimbursed BreitBurn Management for all direct and indirect expenses it incurred in connection with the services it performed on our behalf (including salary, bonus, certain incentive compensation and other amounts paid to executive officers and other employees).

Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long-Term Incentive Plan (BreitBurn Management LTIP) and the Unit Appreciation Rights Plan (UAR plan) of the predecessor as previously amended. The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (Founders Plan), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as described in the subject plan discussions below.

We may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. We also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants or, if earlier, its termination by us.

Unit Based Compensation

Prior to January 1, 2006, our predecessor applied the recognition and measurement principles of Accounting Principles Board (‘‘APB’’) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for those plans. Our predecessor used the method prescribed under FASB Interpretation No. 28, Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans—and interpretation of APB Opinions No. 15 and 25, to calculate compensation expense associated with its awards.

Effective January 1, 2006, our predecessor adopted the fair value recognition provisions of SFAS No. 123(R), Share-Based Payments, using the modified-prospective transition method. BreitBurn Management as successor is following the same method as BEC, our predecessor. Under this transition method, equity-based compensation expense for the January 1, 2006 to October 9, 2006 period and October 10, 2006 to December 31, 2006 period included compensation expense for all equity-based compensation awards granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123 and for options granted subsequent to January 1, 2006 in accordance with the provisions of SFAS No. 123(R). Unit based compensation awards granted prior to but not yet vested as of January 1, 2006 that are classified as liabilities were charged to compensation expense based on the fair value provisions of SFAS No. 123(R). For the liability-based plans, we and our predecessor recognize these compensation expenses on a graded-vesting method. Under the graded-vesting method, a company recognizes compensation expense over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. For our RPU and CPU equity-based plans, we recognize our compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.

Awards classified as liabilities are revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options are recognized as compensation expense over the vesting schedules of the awards. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period(s). Option awards outstanding at the end of 2008 are liability-classified because the awards are settled in cash or have the option of being settled in cash or units at the choice of the holder, and they are indexed to either our Common Units or to Provident Trust Units. The liability-classified option awards are distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders receive cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units. In the Black-Scholes option pricing model, the expected volatilities are based primarily on the historical volatility of Provident’s units for Provident indexed units and the Alerian MLP Index for Partnership indexed units. We and our predecessor use historical data to estimate option exercises and employee terminations within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. The expected term of options granted is based on historical exercise behavior and represents the period of time that options granted are expected to be outstanding. The risk free rate for periods within the contractual life of the option is based on U.S. Treasury rates. Due to the distribution protection provision of the plans, zero distribution yield is assumed in the pricing model; however, compensation cost is recognized based on the units adjusted for the Adjustment Ratio and for certain plans, it includes distribution amounts accumulated to the reporting date.

F-34

For the period January 1, 2006 to October 9, 2006, the predecessor’s net income was approximately $0.6 million higher than if the share based compensation was still accounted for under APB 25. The Predecessor’s cumulative effect of adoption of SFAS No. 123(R) in 2006 was a benefit of approximately $0.6 million.

Executive Phantom Option Plan

Effective on the initial public offering date of October 10, 2006, the Phantom Options awarded to the Co-Chief Executive Officers during 2006, were adopted by BreitBurn Management and converted into three separate awards. The first award represented a one and one half percent interest with respect to the operations of the properties that were not transferred to us for the 2006 fiscal year. Its unit value was determined on the basis of an assessment of the valuation of the properties at the beginning of the fiscal period as compared to an assessment of the valuation of the properties at the end of the fiscal period plus distributions paid less a hurdle rate of eight percent. The second award represented a one and one half percent interest with respect to the operations of the properties that were transferred to us for the period of January 1, 2006 to the initial public offering date of October 10, 2006. Its unit value was determined on the basis of an assessment of the valuation of the properties at the beginning of the fiscal period as compared to the valuation of the properties at the end of the fiscal period as determined using the initial public offering price plus distributions paid less a prorated hurdle rate. The third award represented a one and one half percent interest with respect to the operations of the properties that were transferred to us for the period beginning on the initial public offering date of October 10, 2006 and ending on December 31, 2006. Its unit value was determined using the initial public offering price of $18.50 at October 10, 2006 as compared to the closing unit price of $24.10 on December 29, 2006 less a prorated hurdle rate. The first two awards were charged to the predecessor as compensation expense during 2006. The predecessor recorded compensation expense of $5.9 million for the period January 1, 2006 to October 9, 2006. The third award was charged to us resulting in an expense of $3.6 million for the period from October 10, 2006 to December 31, 2006. All phantom options granted for each plan year were settled in cash before March 1 of the following year.

Pursuant to the employment agreements between the predecessor and the Co-Chief Executive Officers, which were adopted by us and BreitBurn Management, at January 1, 2007, the Co-Chief Executive Officers were each awarded 336,364 phantom option units at a grant price of $24.10 per unit under the executive phantom option plan. These phantom units, in late 2007, were cancelled and terminated in exchange for the right to receive a lump-sum payment of $2.4 million and 184,400 of Restricted Phantom Units (RPUs) at a grant price of $31.68 per unit, which has a fair value of $5.8 million. The RPUs generally will vest and be paid in Common Units in three equal, annual installments on each anniversary date of the vesting commencement date of the award. They will receive distributions quarterly at the same rate payable to common unitholders immediately after grant. For detailed information on the RPUs, see discussions at the end of this note regarding “Restricted Phantom Units and Convertible Phantom Units.”

The RPUs are classified as equity awards. Under the provisions of SFAS No.123(R), we recorded compensation expense of $7.0 million for the exchange of executive phantom options awards in 2007. Of the total amount expensed in 2007, $4.6 million was recorded to equity. The remaining fair value of the awards in the amount of $1.2 million will be expensed ratably over a three-year period beginning in 2008 and is included later in this note under the Restricted Phantom Units and Convertible Phantom Units disclosure.

Founders Plan

Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units. The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period. The base price and vesting terms were determined by BreitBurn Management at the time of the grant. Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements.

F-35

Effective on the initial public offering date of October 10, 2006, all outstanding unit appreciation rights under the Founders Plan were adopted by BreitBurn Management and converted into three separate awards. The first award represented 2.2 million unit appreciation rights at a weighted average grant price of $0.76 per unit with respect to the operations of the properties that were not transferred to us. The value of these unit appreciation rights at year-end 2006 was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to an assessment of the valuation of the properties at the end of the fiscal period plus distributions paid. The second award represented 309,570 unit appreciation rights at a weighted average grant price of $4.70 per unit with respect to the operations of the properties that were transferred to us for the period from the original date of grant to the initial public offering date of October 10, 2006. The value of the unit appreciation rights was determined on the basis of an assessment of the valuation of the properties at the original grant date as compared to the valuation of the properties at the end of the fiscal period as determined using the initial public offering price plus distributions paid. The aggregate values of the vested and unvested units for the first two awards were $4 million and $2.4 million respectively, at December 31, 2006. The predecessor had recorded $2.0 million of compensation expense under the plan in the period ended October 9, 2006.

The third award represented 309,570 Partnership unit appreciation rights at a base price of $18.50 per unit with respect to the operations of the properties that were transferred to us for the period beginning on the initial public offering date of October 10, 2006. The award is liability-classified and is being charged to us as compensation expense over the remaining vesting schedule. The value of the outstanding Partnership unit appreciation rights is remeasured each period using a Black-Scholes option pricing model. Market prices of $7.05 and $28.90 were used in the model for the periods ending December 31, 2008 and December 31, 2007, respectively. Expected volatility ranged from 9 percent to 21 percent and had a weighted average volatility of 9.8 percent. The average risk free rate used was approximately 3.3 percent. The expected option terms ranged from one half year to two and one half years.

We recorded approximately $(0.3), $ 2.7 and $0.3 million of compensation expense/(income) under the plan for the year ended December 31, 2008, December 31, 2007 and the period ended December 31, 2006, respectively. The aggregate value of the vested unit appreciation rights was $0.4 million and the unvested obligation was zero at December 31, 2008.

The following table summarizes information about Appreciation Rights Units issued under the Founders Plan:

	December 31,
	2008					2007					2006
	Number of			Weighted		Number of			Weighted		Number of		Weighted
	Appreciation			Average		Appreciation			Average		Appreciation		Average
	Rights Units			Exercise Price		Rights Units			Exercise Price		Rights Units		Exercise Price
Outstanding , beginning of period		214,107		$	18.50		305,570		$	18.50		305,570	$	18.50
Exercised		(91,463	)		18.50		(91,463	)		18.50		-		-
Outstanding, end of period		122,644		$	18.50		214,107		$	18.50		305,570	$	18.50

Exercisable, end of period		-		$	-		-		$	-		91,463	$	18.50

BreitBurn Management LTIP and the Partnership LTIP

In September 2005, certain employees of the predecessor were granted restricted units (RTUs) and/or performance units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units indexed to Provident Energy Trust Units. The grants are based on personal performance objectives. This plan replaced the Unit Appreciation Right Plan for Employees and Consultants for the period after September 2005 and subsequent years. RTUs vest one third at the end of year one, one third at end of year two and one third at the end of year three after grant. In general, cash payments equal to the value of the underlying notional units were made on the anniversary dates of the RTU to the employees entitled to receive them. PTUs vest three years from the end of third year after grant and payout can range from zero to two hundred percent of the initial grant depending on the total return of the underlying notional units as compared to the returns of selected peer companies. The total return of the Provident Energy Trust unit is compared with the return of 25 selected Canadian trusts and funds. The Provident indexed PTUs granted in 2005 and 2006 entitle employees to receive cash payments equal to the market price of the underlying notional units. Under our LTIP, Partnership indexed PTUs were granted in 2007 and are payable in cash or may be paid in Common Units of the Partnership if elected at least 60 days prior to vesting by the grantees. The total return of the Partnership unit is compared with the return of 49 companies in the Alerian MLP Index for the payout multiplier. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.

F-36

On June 17, 2008, we entered into the BreitBurn Management Purchase agreement with Pro LP and Pro GP. The BreitBurn Management Purchase Agreement contains certain covenants of the parties relating to the allocation of responsibility for liabilities and obligations under certain pre-existing equity-based compensation plans adopted by BreitBurn Management, BEC and us. The pre-existing compensation plans include the outstanding 2005 and 2006 LTIP grants which are indexed to the Provident Trust Units. As a result, we paid $0.9 million for our share of the 2005 LTIP grants that vested in June 2008 in accordance with the agreed allocation of liability.

In September 2008, BreitBurn Management made an offer to holders of the 2006 LTIP grants to cash out their Provident-indexed units at $10.32 per share before the normal vesting date of December 31, 2008. By the end of September 2008, the offer was accepted by all employees who had outstanding 2006 LTIP grants. Consequently, compensation expense was recognized for the full amount of the remaining unvested liability during 2008. BreitBurn Management paid employees $0.6 million in 2008 for its share of the 2006 LTIP grants in accordance with the agreed allocation of liability.

Under our LTIP, Partnership-indexed restricted units (RTUs) and/or performance units (PTUs) were granted in 2007 and are payable in cash or in Common Units of the Partnership if elected by the grantee at least 60 days prior to the vesting date. For PTUs, a performance multiplier is applied and is determined by comparing our total return to the returns of 49 companies in the Alerian MLP Index. All of the grants are liability-classified. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with RTUs and PTUs is expensed in the statement of income over the vesting period.

We recognized $(0.5), $2.5 and $0.3 million of compensation expense/(income) for the years ended December 31, 2008, December 31, 2007 and for the period ended December 31, 2006. Our share of the aggregate liability under the BreitBurn Management LTIP was $0.8 million at December 31, 2008. The aggregate value of the vested and unvested units under the plan was $0.6 million and $0.2 million respectively, at December 31, 2008.

The following table summarizes information about the restricted/performance units granted in 2005 and 2006:

	Successor															Predecessor
	BreitBurn Management Company															BreitBurn Energy Company L.P.
	PVE indexed units															PVE indexed units
	December 31,										October 10 to					January 1 to
	2008					2007					December 31, 2006					October 9, 2006
				Weighted					Weighted					Weighted					Weighted
	Number of			Average		Number of			Average		Number of			Average		Number of			Average
	Units			Grant Price		Units			Grant Price		Units (a)			Grant Price		Units (a)			Grant Price
Outstanding , beginning of period		267,702		$	10.77		318,389		$	10.82		372,203		$	11.05		232,740		$	9.91
Granted		-			-		-			-		-			-		169,633			12.41
Exercised		(267,351	)		10.77		(36,203	)		10.87		(13,289	)		12.41		(22,615	)		9.91
Cancelled (b)		(351	)		10.73		(14,484	)		11.53		(40,525	)		12.41		(7,555	)		9.97
Outstanding, end of period		-		$	10.77		267,702		$	10.77		318,389		$	10.82		372,203		$	11.05

Exercisable, end of period		-		$	-		-		$	-		-		$	-		-		$	-

(a) Amounts exclude units attributable to the adjustment ratio.

(b) Cancelled units for October 10 to December 31, 2006 includes 40,290 PVE indexed units awarded to the Chief Financial Officer which were converted to Partnership indexed units.

F-37

The following table summarizes information about the restricted/performance units granted in 2007. Market prices of $7.05 and $28.90 were used in the model for the periods ending December 31, 2008 and December 31, 2007, respectively. Expected volatility ranged from 9 percent to 15 percent and had a weighted average volatility of 9.8 percent. The average risk free rate ranged from 2 to 3.3 percent. The expected option terms ranged from one year to two years.

	PTUs and RTUs
	December 31,
	2008					2007
				Weighted					Weighted
	Number of			Average		Number of			Average
	Units			Grant Price		Units			Grant Price
Outstanding , beginning of period		108,717		$	23.64		20,483		$	21.67
Granted		-			-		91,834			24.10
Exercised		(20,645	)		20.39		(98	)		24.10
Cancelled		(1,080	)		24.10		(3,502	)		24.10
Outstanding, end of period		86,992		$	24.10		108,717		$	23.64

Exercisable, end of period		-		$	-		-		$	-

Unit Appreciation Right Plan

In 2004, the predecessor adopted the Unit Appreciation Right Plan for Employees and Consultants (the ‘‘UAR Plan’’). Under the UAR Plan, certain employees of the predecessor were granted unit appreciation rights (‘‘UARs’’). The UARs entitle the employee to receive cash compensation in relation to the value of a specified number of underlying notional trust units of Provident (‘‘Phantom Units’’). The exercise price and the vesting terms of the UARs were determined at the sole discretion of the Plan Administrator at the time of the grant. The UAR Plan was replaced with the BreitBurn Management LTIP at the end of September 2005. The grants issued prior to the replacement of the UAR Plan fully vested in 2008.

UARs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant. Upon vesting, the employee is entitled to receive a cash payment equal to the excess of the market price of Provident Energy Trust’s units (PVE units) over the exercise price of the Phantom Units at the grant date, adjusted for an additional amount equal to any Excess Distributions, as defined in the plan. The predecessor settles rights earned under the plan in cash.

The total compensation expense for the UAR plan is allocated between us and our predecessor. Our share of expense was an immaterial amount in 2008, $0.4 million in 2007 and $0.2 million for the period from October 10 to December 31, 2006 under the UAR Plan. Our share of the aggregate liability under the UAR Plan was approximately $0.1 million at December 31, 2008. The liability primarily represents accrued expense related to unpaid distributions on the fully vested UARs. In the Black-Scholes option pricing model for this plan, the expected volatility used was 29 percent and the risk rate was 3.3 percent. The expected option term is less than one half year.

The following table summarizes the information about UARs:

	Successor															Predecessor
	BreitBurn Management Company															BreitBurn Energy Company L.P.
	PVE indexed units															PVE indexed units
	December 31,										October 10 to					January 1 to
	2008					2007					December 31, 2006					October 9, 2006
	Number of			Weighted		Number of			Weighted		Number of			Weighted		Number of			Weighted
	Appreciation			Average		Appreciation			Average		Appreciation			Average		Appreciation			Average
	Rights			Exercise Price		Rights			Exercise Price		Rights			Exercise Price		Rights			Exercise Price

Outstanding , beginning of period		154,323		$	9.16		474,521		$	8.41		515,410		$	8.34		770,026		$	8.34
Exercised		(69,994	)		9.18		(316,183	)		8.96		(40,889	)		8.20		(241,951	)		8.20
Cancelled		-			-		(4,015	)		9.16		-			-		(12,665	)		8.90
Outstanding, end of period		84,329		$	9.96		154,323		$	9.65		474,521		$	8.41		515,410		$	8.39

Exercisable, end of period		84,329		$	9.96		115,003		$	9.53		86,882		$	8.47		111,104		$	8.24

F-38

Director Performance Units

Effective with the initial public offering, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner. Each phantom unit is accompanied by a distribution equivalent unit right entitling the holder to an additional number of phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement. Upon vesting, the majority of the phantom units will be paid in Common Units, except for certain directors’ awards which will be settled in cash. The unit-settled awards are classified as equity and the cash-settled awards are classified as liabilities. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. The accumulated compensation expense for unit-settled awards is reported in equity and for cash-settled grants, it is reflected as a liability on the consolidated balance sheet.

We recorded compensation expense for the director’s phantom units of approximately $0.1 million in 2008 and $0.5 million in 2007. Compensation expense recorded for the period October 10, 2006 through December 31, 2006 amounted to an immaterial amount. Our aggregate liability under the outstanding grants was $0.8 million at December 31, 2008 of which $0.4 million represents the unvested portion.

The following table summarizes information about the Director Performance Units:

	December 31,
	2008					2007				2006
	Number of			Weighted		Number of		Weighted		Number of		Weighted
	Performance			Average		Performance		Average		Performance		Average
	Units			Grant Price		Units		Grant Price		Units		Grant Price
Outstanding , beginning of period		37,473		$	21.11		20,026	$	18.50		-	$	-
Granted		20,146			27.35		17,447		24.10		20,026		18.50
Exercised		(22,190	)		23.05		-		-		-		-
Outstanding, end of period		35,429		$	23.44		37,473	$	21.11		20,026	$	18.50

Exercisable, end of period		-		$	-		-	$	-		-	$	-

Restricted Phantom Units and Convertible Phantom Units

In connection with the changes to BreitBurn Management’s executive compensation program, the board of directors of our General Partner has approved two new types of awards under our LTIP, namely, Restricted Phantom Units (RPUs) and Convertible Phantom Units (CPUs). In December 2007, seven executives of our General Partner received 188,545 units of RPUs and 681,500 units of CPUs at a grant price of $30.29 per Common Unit. Each of the awards has the vesting commencement date of January 1, 2008. In November 2007, the Co-Chief Executive Officers also received 184,400 of Restricted Phantom Units (RPUs) at a grant price of $31.68 per Common Unit under our Long-Term Incentive Plan. Those executive officers received CPU grants because they are in the best position to influence our operating results and, therefore, the amount of distributions we make to holders of our Common Units. As discussed below, payments under CPUs are significantly tied to the amount of distributions we make to holders of our Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives is based upon the level of distributions to common unitholders achieved during the term of the CPUs. The CPU grants vest over a longer-term period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made at the board’s discretion at a future date after the present CPU grants have vested. A holder of an RPU is entitled to receive payments equal to quarterly distributions in cash at the time they are made. As a result, we believe that RPUs better incentivize holders of these awards to grow stable distributions for our common unitholders than do performance units. In 2008, the board of directors of the General Partner granted 245,290 RPUs to employees at a weighted average price of $20.44.

Restricted Phantom Units (RPUs). RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. RPUs generally vest in three equal, annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.

F-39

Convertible Phantom Units (CPUs). CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or “disability” of the grantee or his or her termination without “cause” or for “good reason” (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management.

Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution. Initially, one Common Unit equivalent underlies each CPU at the time it was awarded to the grantee. However, the number of Common Unit equivalents underlying the CPUs increase at a compounded rate of 25 percent upon the achievement of each 5 percent compounded increase in the distributions paid by us to our common unitholders. Conversely, the number of Common Unit equivalents underlying the CPUs decrease at a compounded rate of 25 percent if the distributions paid by us to our common unitholders decreases at a compounded rate of 5 percent.

In the event that the CPUs vest on January 1, 2013 or because the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters).

In the event that CPUs vest due to the death or disability of the grantee or his or her termination without cause or good reason, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time, pro-rated based on when the death or disability occurred. First, the number of Common Unit equivalents would be calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters or, if such calculation would provide for a greater number of Common Unit equivalents, the most recently announced quarterly distribution level by us on an annualized basis. Then, this number would be pro rated by multiplying it by a percentage equal to:

if such termination occurs on or before December 31, 2008, a percentage equal to 40 percent;

if such termination occurs on or before December 31, 2009, a percentage equal to 60 percent;

if such termination occurs on or before December 31, 2010, a percentage equal to 80 percent; and

if such termination occurs on or after January 1, 2011, a percentage equal to 100 percent.

In 2008, we recognized compensation expense of $7.5 million related to its CPUs and RPUs.

The following table summarizes information about the CPUs and RPUs:

	December 31,
	2008					2007				2006
	Number of			Weighted		Number of		Weighted		Number of		Weighted
	RPU			Average		RPU		Average		CPU		Average
	Units			Grant Price		Units		Grant Price		Units		Grant Price
Outstanding , beginning of period (a)		372,945		$	30.98		372,945	$	30.98		681,500	$	30.29
Granted		245,290			20.44		-		-		-		-
Cancelled		(10,972	)		20.83		-		-		-		-
Outstanding, end of period		607,263		$	26.91		372,945	$	30.98		681,500	$	30.29

Exercisable, end of period		-		$	-		-	$	-		-	$	-

(a) 2007 includes Co-Chief Executive Officers' 184,400 RPUs received as a result of the termination of the executive phantom option plan in November 2007.

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16. Commitments and Contingencies

Lease Rental Obligations

We had operating leases for office space and other property and equipment having initial or remaining noncancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2008 are presented below:

	Payments Due by Year
Thousands of dollars	2009		2010		2011		2012		2013		after 2013		Total
Operating leases	$	2,232	$	2,126	$	1,989	$	1,656	$	1,272	$	2,143	$	11,418

BreitBurn Management, our wholly owned subsidiary, has office, vehicle (primarily work vehicles used in our field operations) and office equipment leases. Net rental payments made under non-cancelable operating leases were $2.88 million in 2008, $0.4 million in 2007 and $0.1 million for the period from October 10, 2006 to December 31, 2006. For the period from January 1, 2006 to October 9, 2006, the predecessor’s net rental payments were $0.3 million.

Surety Bonds and Letters of Credit

In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2008, we had $10.1 million in surety bonds and we had $0.3 million in letters of credit outstanding. At December 31, 2007, we had $7.6 million in surety bonds and $0.3 million in letters of credit outstanding.

Other

On October 31, 2008, Quicksilver, an owner of more than five percent of our Common Units, instituted a lawsuit in the District Court of Tarrant County, Texas naming us as a defendant along with BreitBurn GP, BOLP, BOGP, Randall H. Breitenbach, Halbert S. Washburn, Gregory J. Moroney, Charles S. Weiss, Randall J. Findlay, Thomas W. Buchanan, Grant D. Billing and Provident. On December 12, 2008, Quicksilver filed an Amended Petition and asserted twelve different counts against the various defendants. The primary claims are as follows: Quicksilver alleges that BOLP breached the Contribution Agreement with Quicksilver, dated September 11, 2007, based on allegations that we made false and misleading statements relating to its relationship with Provident. Quicksilver also alleges common law and statutory fraud claims against all of the defendants by contending that the defendants made false and misleading statements to induce Quicksilver to acquire Common Units in us. Finally, Quicksilver alleges claims for breach of the Partnership’s First Amended and Restated Agreement of Limited Partnership, dated as of October 10, 2006 (“Partnership Agreement”), and other common law claims relating to certain transactions and an amendment to the Partnership Agreement that occurred in June 2008. Quicksilver seeks a temporary and permanent injunction, a declaratory judgment relating primarily to the interpretation of the Partnership Agreement and the voting rights in that agreement, indemnification, punitive or exemplary damages, avoidance of BreitBurn GP's assignment to us of all of its economic interest in us, attorneys’ fees and costs, pre- and post-judgment interest, and monetary damages. The parties to the lawsuit are engaged in discovery pursuant to an agreed scheduling order. On February 17, 2009, we filed a motion for summary judgment which is scheduled to be heard on March 26, 2009. A hearing on Quicksilver’s request for a temporary injunction is scheduled for April 6, 2009.

We are defending ourselves vigorously in connection with the allegations in the lawsuit. Because this lawsuit still is at an early stage, we cannot predict the manner and timing of the resolution of the lawsuit or its outcome, or estimate a range of possible losses, if any, that could result in the event of an adverse verdict in the lawsuit.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings other than as mentioned above. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.

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17. Supplemental property tax billings

In May 2006, the predecessor received supplemental property tax billings from Los Angeles County amounting to approximately $0.3 million (net of expected recoveries from working interest and mineral interest owners) related to a reassessment of mineral values associated with its oil and gas properties located in Los Angeles County. This reassessment was performed by Los Angeles County as a result of Provident’s purchase of BEC on June 15, 2004. The supplemental billings covered the period from July 1, 2005 to June 30, 2006.

In June 2006, the predecessor received supplemental property tax billings from Los Angeles County amounting to approximately $1.3 million related to a reassessment of mineral values associated with those properties as a result of Provident’s purchase of BEC. After projecting recoveries from outside working interest and mineral interest owners, the predecessor’s net property tax liability was approximately $1.1 million for the period July 1, 2004 to June 30, 2005.

At year end 2004, a review of California counties’ recent practices of oil and gas property value assessments indicated that a value reassessment of BEC’s California oil and gas properties would likely not occur until the annual lien date of January 1, 2005. The predecessor employed third party property tax experts to assist with this review. As a result, the predecessor concluded that its property tax liabilities accrued at year end 2004 were proper.

In 2005, the predecessor received property tax billings from Los Angeles County that reflected substantially increased assessed values over the 2004 Los Angeles County oil and gas properties’ assessed values. Due to this increase in assessed values and earlier discussions with the predecessor’s third party property tax experts, the predecessor concluded that the Los Angeles County property tax billings it received in 2005 included amounts due for any reassessment Los Angeles County would have performed. As a result, the predecessor concluded that its property tax liabilities accrued at year end 2005 were reasonable.

In accordance with paragraph 8 of SFAS No. 5, Accounting for Contingencies, the predecessor has accrued the full amount of the supplemental property tax billings in its 2006 financial statements. This accrual increased property tax expense by $1.6 million (net of expected recoveries from working interest and mineral interest owners). In July 2006, the predecessor filed an appeal with Los Angeles County challenging the reassessed values used in the supplemental property tax billings. In 2007, the appeal was withdrawn as the reassessment calculations for the properties fair values were determined to have been performed within acceptable limits and were in accordance with the regulations.

18. Retirement Plan

BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. BreitBurn Management has a defined contribution retirement plan, which covers substantially all of its employees who have completed at least three months of service. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. BEC is charged for a portion of the matching contributions made by BreitBurn Management. For the year ended December 31, 2008, the matching contribution paid by us was $0.4 million. For the year ended December 31, 2007 and the period from October 10, 2006 to December 31, 2006, the matching contributions paid by us were $0.1 million and a negligible amount, respectively. The Predecessor paid $0.1 million in matching contributions for the period ended October 9, 2006.

19. Significant Customers

We sell oil, natural gas and natural gas liquids primarily to large domestic refiners. For the year ended December 31, 2008, our purchasers which accounted for 10 percent or more of net sales were ConocoPhillips which accounted for 25 percent of net sales and Marathon Oil Company which accounted for 13 percent of net sales. For the years ended December 31, 2007 and 2006, ConocoPhillips purchased approximately 20 percent and 45 percent of our production, respectively, and Marathon Oil Company purchased approximately 24 percent and 28 percent of our production, respectively.

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20. Minority Interest

Through our BEPI Acquisition (see Note 4 - Acquisitions), we acquired the limited partner interest (99 percent) of BEPI. As such, we are fully consolidating the results of BEPI and thus are recognizing a minority interest liability representing the book value of the general partner’s interests. At December 31, 2008, the amount of this minority interest liability was $0.5 million. The general partner of BEPI holds a 35 percent reversionary interest under the existing limited partnership agreement applicable to the properties. Based on year end price and cost projections, the revisionary interest payout is not expected to occur.

21. Subsequent Events

On January 22, 2009, we terminated a portion of our 2011 and 2012 crude oil swaps (1,939 Bbls/d at $90.00 per Bbl) and replaced them with new contracts with the same counterparty for the same volumes at market prices ($63.30 per Bbl). We realized $32.3 million from this termination. On January 26, 2009, we terminated a portion of our 2011 and 2012 natural gas swaps and replaced them with new contracts with the same counterparty for the same volumes at market prices. We realized $13.3 million from this termination. Proceeds from these contracts were used to pay down debt.

On February 13, 2009, we paid a cash distribution of approximately $27.4 million to our common unitholders of record as of the close of business on February 9, 2009. The distribution that was paid to unitholders was $0.52 per Common Unit. In February 2009 we also made payments equivalent to the distribution made to unitholders of $0.7 million on Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.

On February 19, 2009, 134,377 Common Units were issued to employees under our 2006 Long-Term Incentive Plan, increasing our outstanding Common Units to 52,770,011. See Note 15 for information regarding our unit based compensation plans.

22. Oil and Natural Gas Activities (Unaudited)

Costs incurred

Our oil and natural gas activities are conducted in the United States. The following table summarizes the costs incurred by us, as successor, and BEC, as the Predecessor:

	Successor						Predecessor
	Year Ended		Year Ended		October 10 to		January 1 to
	December 31,		December 31,		December 31,		October 9,
Thousands of dollars	2008		2007		2006		2006
Property acquisition costs (1)
Proved	$	-	$	1,437,129	$	-	$	-
Unproved		-		213,344		-		-
Development costs		129,503		26,959		1,248		36,941
Asset retirement costs		1,363		3,583		2,633		-
Pipelines and processing facilities (1)		-		48,810		-		-
Total	$	130,866	$	1,729,825	$	3,881	$	36,941

(1) See Note 4 - Acquisitions for additional information

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Capitalized costs

The following table presents the aggregate capitalized costs subject to depreciation, depletion and amortization relating to oil and gas activities, and the aggregate related accumulated allowance.

	At December 31,			At December 31,
Thousands of dollars	2008			2007
Proved properties and related producing assets	$	1,734,932		$	1,648,787
Pipelines and processing facilities		112,726			48,810
Unproved properties		209,873			213,344
Accumulated depreciation, depletion and amortization		(223,575	)		(46,877	)
	$	1,833,956		$	1,864,064

The average DD&A rate per equivalent unit of production for our year ended December 31, 2008 was $26.42 per Boe. The average DD&A rate per equivalent unit of production for us over the year ended December 31, 2007 was $9.75 per Boe. The increase in the DD&A rate was primarily due to our 2007 acquisitions, price related depletion and depreciation adjustments of $34.5 million and field impairments totaling $51.9 million.

Results of operations for oil and gas producing activities

The results of operations from oil and gas producing activities below exclude non-oil and gas revenues and expenses, general and administrative expenses, interest expenses and interest income.

	Successor									Predecessor
	Year Ended						October 10 to			January 1 to
	December 31,						December 31,			October 9,
Thousands of dollars	2008			2007			2006			2006
Oil, natural gas and NGL sales	$	467,381		$	184,372		$	18,452		$	110,329
Realized gain (loss) on derivative instruments		(55,946	)		(6,556	)		2,181			(3,692	)
Unrealized gain (loss) on derivative instruments		388,048			(103,862	)		(1,299	)		5,983
Operating costs		(149,681	)		(70,329	)		(7,159	)		(33,583	)
Depreciation, depletion, and amortization		(178,657	)		(29,277	)		(2,488	)		(10,554	)
Pre-tax Income		471,145			(25,652	)		9,687			68,483
Income tax expense (benefit)		1,939			(1,229	)		(40	)		90
Results of producing operations	$	469,206		$	(24,423	)	$	9,727		$	68,393

Supplemental reserve information

The following information summarizes our estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the years ended December 31, 2008 and 2007 and the period from October 10, 2006 to December 31, 2006. The information for BEC, the Predecessor, is presented for the period from January 1, 2006 to October 9, 2006. The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms. The estimates are prepared in accordance with SEC regulations.

Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. The beginning balance of the successor in 2006, which is reflected on the table as contributions from predecessor, represents the estimated reserves in place at the time the initial public offering was completed on October 10, 2006. Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.

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The following table sets forth certain data pertaining to our estimated proved and proved developed reserves for the years ended December 31, 2008 and 2007, data for the period from October 10, 2006 to December 31, 2006 representing us as successor and the predecessor’s data for the year 2006.

	Successor																		Predecessor
	Year Ended December 31,												October 10-
	2008						2007						December 31, 2006 (b)						2006 (a)
	Oil			Gas			Oil			Gas			Oil			Gas			Oil			Gas
In Thousands	(MBbl)			(MMcf)			(MBbl)			(MMcf)			(MBbl)			(MMcf)			(MBbl)			(MMcf)
Proved Reserves
Beginning balance		58,095			505,069			30,042			4,190			-			-			58,185			17,022
Contribution from Predecessor (c) (d)		-			-			-			-			30,408			4,270			(30,408	)		(4,270	)
Revision of previous estimates (d)		(29,106	)		(16,251	)		3,260			(534	)		-			-			521			1,498
Extensions, discoveries and other additions (d)		-			-			118			-			-			-			1,898			-
Purchase of reserves in-place		-			-			27,005			505,547			-			-			-			-
Production (a) (b)		(3,079	)		(22,384	)		(2,330	)		(4,134	)		(366	)		(80	)		(2,036	)		(657	)
Ending balance		25,910			466,434			58,095			505,069			30,042			4,190			28,160			13,593

Proved Developed Reserves

Beginning balance		52,103			457,444			27,786			4,190			-			-			45,195			8,359
Ending balance		23,346			433,780			52,103			457,444			27,786			4,190			17,292			4,588

(a)	2006 production for predecessor is from January 1 - October 9 for Contributed Properties and January 1 - December 31 for Retained Properties.

(b)	2006 production for Successor is from October 10 - December 31, 2006 for Contributed Properties.

(c)	Contribution from predecessor to the Successor as of October 10, 2006. The contributed amount was determined by subtracting Successor production for the period from October 10 to December 31, 2006 from the year-end reserve balance of the Successor.

(d)

Additions due to infill drilling are classified in Revisions and were approximately 741 MBbl for oil and 35,834 MMcf for natural gas in 2008 and 1,422 MBbl for oil and 19 MMcf for natural gas in 2007. For 2006, revisions attributable to extensions, discoveries, additions and revisions of previous estimates were determined at year-end. Because these adjustments were not determinable at October 10, 2006, all adjustments appear in the predecessor's reserve amounts. For 2006, additions due to infill drilling were not reclassified from extensions, discoveries and other additions.

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Standardized measure of discounted future net cash flows

The Standardized Measure of discounted future net cash flows relating to our estimated proved crude oil and natural gas reserves as of December 31, 2008 and 2007, and the predecessor’s data as of the year ended December 31, 2006 is presented below:

	December 31,
Thousands of dollars	2008			2007			2006
Future cash inflows		3,523,524			8,154,921		$	1,572,245
Future development costs		(212,951	)		(370,594	)		(126,171	)
Future production expense		(1,843,986	)		(3,360,451	)		(788,287	)
Future net cash flows		1,466,587			4,423,876			657,787
Discounted at 10% per year		(874,327	)		(2,511,409	)		(345,288	)
Standardized measure of discounted future net cash flows	$	592,260		$	1,912,467		$	312,499

The standardized measure of discounted future net cash flows discounted at ten percent from production of proved reserves was developed as follows:

An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our estimated proved properties and the present value thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various arrangements to fix or limit the prices relating to a portion of our oil and gas production. Arrangements in effect at December 31, 2008 are discussed in Note 14. Such risk management arrangements are not reflected in the reserve reports. Representative market prices at the as-of date for the reserve reports as of December 31, 2008, 2007 and 2006 were $44.60 ($20.12 for Wyoming), $95.95 ($54.52 for Wyoming) and $60.85 per barrel of oil, respectively, and $5.71, $6.80 and $5.64 per MMBTU of gas, respectively.

The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for two tax paying corporations whose future income tax liabilities on a discounted basis are insignificant.

The principal sources of changes in the Standardized Measure of the future net cash flows for the year ended December 31, 2008, December 31, 2007 and the period ended from October 10 to December 31, 2006 is presented below:

	Successor
	December 31,			December 31,			Oct 10-Dec 31,
Thousands of dollars	2008			2007			2006
Beginning balance	$	1,912,467		$	312,499			-
Contribution from Predecessor		-			-			323,792
Sales, net of production expense		(317,700	)		(114,041	)		(11,293	)
Net change in sales and transfer prices, net of production expense		(1,306,752	)		243,374			-
Previously estimated development costs incurred during year		57,694			15,451			-
Changes in estimated future development costs		(98,064	)		(22,683	)		-
Extensions, discoveries and improved recovery, net of costs		-			2,602			-
Purchase of reserves in place		-			1,386,133			-
Revision of quantity estimates and timing of estimated production		153,368			57,882			-
Accretion of discount		191,247			31,250			-
Net change in income taxes		-			-			-
Ending balance	$	592,260		$	1,912,467		$	312,499

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23. Quarterly Financial Data (Unaudited)

	Year Ended December 31, 2008
	First			Second			Third			Fourth
Thousands of dollars	Quarter			Quarter			Quarter			Quarter
Oil, natural gas and natural gas liquid sales	$	115,849		$	139,962		$	130,249		$	81,321
Gains (losses) on derivative instruments		(83,387	)		(353,282	)		407,441			361,330
Other revenue, net		875			643			806			596
Total revenue	$	33,337		$	(212,677	)	$	538,496		$	443,247

Operating income (loss) (1)		(34,455	)		(282,267	)		468,625			277,451

Net income (loss) (1)		(41,140	)		(286,240	)		454,454			251,162

Limited Partners' interest in loss (1)		(40,867	)		(284,494	)		454,454			251,162

Basic net loss per limited partner unit (2)		(0.61	)		(4.39	)		8.63			4.77
Diluted net loss per limited partner unit (2)		(0.61	)		(4.39	)		8.41			4.65

Basic units outstanding		67,020,641			64,807,563			52,635,634			52,635,634
Diluted units outstanding		67,020,641			64,807,563			54,062,291			54,019,830

	Year Ended December 31, 2007
	First			Second			Third			Fourth
Thousands of dollars	Quarter			Quarter			Quarter			Quarter
Oil, natural gas and natural gas liquid sales	$	21,389		$	32,413		$	49,528		$	81,042
Gains (losses) on derivative instruments		(6,668	)		(7,551	)		(24,767	)		(71,432	)
Other revenue, net		241			237			130			429
Total revenue	$	14,962		$	25,099		$	24,891		$	10,039

Operating loss		(4,361	)		(670	)		(7,195	)		(43,122	)

Net loss		(4,756	)		(1,068	)		(7,467	)		(47,066	)

Limited Partners' interest in loss		(4,661	)		(1,052	)		(7,353	)		(46,619	)

Basic net loss per limited partner unit (2)		(0.21	)		(0.04	)		(0.25	)		(0.86	)
Diluted net loss per limited partner unit (2)		(0.21	)		(0.04	)		(0.25	)		(0.86	)

Basic units outstanding		21,975,758			24,816,419			29,006,002			54,349,093
Diluted units outstanding		21,975,758			24,816,419			29,006,002			54,349,093

(1) Fourth quarter 2008 includes $86.4 million for total impairments and price related adjustments and depreciation expense.

(2) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the earnings per unit amounts for certain quarters may not be additive.

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