8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED)

December 23, 2010

BREITBURN ENERGY PARTNERS L.P.

(Exact name of Registrant as specified in its charter)

Delaware	001-33055	74-3169953
(State or other jurisdiction of	(Commission	(I.R.S. Employer
incorporation or organization)	File Number)	Identification No.)

515 South Flower Street, Suite 4800

Los Angeles, CA 90071

(Address of principal executive office)

(213) 225-5900

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01  Other Events.

As previously described in a Current Report on Form 8-K filed on October 7, 2010, on October 1, 2010, BreitBurn Energy Partners L.P. (the “Partnership,” “we,” “us” or “our”), BreitBurn Finance Corporation, a Delaware corporation (together with the Partnership, the “Issuers”), and certain of our subsidiaries, as guarantors (the “Guarantors”), entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers as defined therein, pursuant to which the Issuers agreed to sell $305 million in aggregate principal amount of the Issuers’ 8.625% Senior Notes due 2020 (the “Notes”).  The Notes were offered and sold in private placements to qualified institutional buyers in the United States in reliance on Rule 144A under the Securities Act of 1933, as amended.

In connection with the issuance of the Notes, we entered into a registration rights agreement requiring us to file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) with respect to an offer to exchange the Notes for substantially identical notes that are registered under the Securities Act of 1933.   Certain, but not all, of our subsidiaries have issued full, unconditional and joint and several guarantees of the Notes, will guarantee the exchange offer notes and may guarantee future issuances of debt securities, in accordance with Rule 3-10(d) of Regulation S-X. We, therefore, are filing revised historical financial statements within exhibits to this Current Report on Form 8-K (this “Report”) to include condensed consolidating financial information for (a) the Issuers; (b) the Guarantors on a combined basis; and (c) the Partnership’s non-guarantor subsidiaries on a combined basis.

The condensed consolidating financial information has been added to the:

(1) audited Notes to Consolidated Financial Statements as of December 31, 2009 and 2008 and for the three years ended December 31, 2009 included in the Annual Report on Form 10-K for the year ended December 31, 2009 (the “2009 10-K”), filed as Exhibit 99.1 to this Report and incorporated herein by reference.

(2) Notes to the Unaudited Consolidated Financial Statements as of September 30, 2010 and December 31, 2009 and for the three months and nine months ended September 30, 2010 and 2009 included in the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 (the “Q3 2010 10-Q”), filed as Exhibit 99.2 to this Report and incorporated herein by reference.

Except as described above, we have not modified or updated other disclosures contained in the Consolidated Financial Statements and Notes thereto included in the 2009 10-K and the Q3 2010 10-Q.  Accordingly, this Report, with the exception of the foregoing, does not reflect events occurring after the date of filing of the 2009 10-K or the Q3 2010 10-Q, respectively, or modify or update those disclosures affected by subsequent events.  Consequently, all other information not affected by the additions described above is unchanged and reflects the disclosures and other information made at the date of the filing of the 2009 10-K and the Q3 2010 10-Q, respectively, and should be read in conjunction with our filings with the SEC subsequent to the filing of the 2009 10-K and the Q3 2010 10-Q, respectively, including amendments to those filings, if any.

Item 9.01  Financial Statements, Pro Forma Financial Information and Exhibits.

(d) Exhibits.

Exhibit No.	Exhibit Description
23.1	Consent of PricewaterhouseCoopers LLP.
99.1	The historical financial statements and revised related disclosure as of December 31, 2009 and 2008 and for the three years ended December 31, 2009.
99.2	The historical unaudited financial statements and revised related disclosure as of September 30, 2010 and December 31, 2009 and for the three months and nine months ended September 30, 2010 and 2009.

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: December 23, 2010	By:	/s/ James G. Jackson
		James G. Jackson
		Chief Financial Officer

EX-23.1

EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-149190), Form S-3 (No. 333-159888), and Form S-3/A (No. 333-153579) of BreitBurn Energy Partners L.P. of our report dated March 11, 2010 except with respect to our opinion on the consolidated financial statements insofar as it relates to the presentation of financial information of guarantor and non-guarantor subsidiaries discussed in Note 21, as to which the date is December 23, 2010, relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Current Report on Form 8-K.

/s/ Pricewaterhouse Coopers LLP

PricewaterhouseCoopers LLP

Los Angeles, California

December 23, 2010

EX-99.1

Exhibit 99.1
 

See Item 8.01 of the accompanying Current Report on Form 8-K for an explanation regarding the following disclosure. The following information replaces the Report of Independent Registered Public Accounting Firm and Consolidating Financial Statements and audited Notes thereto in Part IV—Item 15 “—Exhibits and Financial Statement Schedules,” incorporated by reference into Part II—Item 8 “ —Financial Statements and Supplementary Data,” previously filed in the Annual Report on Form 10-K for the year ended December 31, 2009 for BreitBurn Energy Partners L.P. (the “2009 10-K”).  Except as set forth in this Exhibit 99.1, the 2009 10-K has not been otherwise modified or updated.

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Report of Independent Registered Public Accounting Firm

Tothe 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 ("the Partnership") at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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, 2009, 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 Management's Report to Unitholders on Internal Control Over Financial Reporting (not presented herein) appearing under Item 9A of the Partnership's 2009 Annual Report on Form 10-K.  Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the 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 16 to the consolidated 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 11, 2010 except with respect to our opinion on the consolidated financial statements insofar as it relates to the presentation of financial information of guarantor and non-guarantor subsidiaries discussed in Note 21, as to which the date is December 23, 2010.

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BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Operations

	Year Ended December 31,
Thousands of dollars, except per unit amounts	2009			2008			2007
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	254,917		$	467,381		$	184,372
Gains (losses) on commodity derivative instruments, net (note 16)		(51,437	)		332,102			(110,418	)
Other revenue, net (note 11)		1,382			2,920			1,037
Total revenues and other income items		204,862			802,403			74,991
Operating costs and expenses:
Operating costs		138,498			162,005			73,989
Depletion, depreciation and amortization (note 6)		106,843			179,933			29,422
General and administrative expenses		36,367			31,111			26,928
Loss on sale of assets		5,965			-			-
Total operating costs and expenses		287,673			373,049			130,339
Operating income (loss)		(82,811	)		429,354			(55,348	)
Interest and other financing costs, net		18,827			29,147			6,258
Loss on interest rate swaps (note 16)		7,246			20,035			-
Other income, net		(99	)		(191	)		(111	)
Income (loss) before taxes		(108,785	)		380,363			(61,495	)
Income tax expense (benefit) (note 7)		(1,528	)		1,939			(1,229	)
Net income (loss)		(107,257	)		378,424			(60,266	)
Less: Net income attributable to noncontrolling interest		(33	)		(188	)		(91	)
Net income (loss) attributable to the partnership		(107,290	)		378,236			(60,357	)
General Partner's interest in net loss		-			(2,019	)		(672	)
Net income (loss) attributable to limited partners	$	(107,290	)	$	380,255		$	(59,685	)
Basic net income (loss) per unit (note 14)	$	(2.03	)	$	6.29		$	(1.83	)
Diluted net income (loss) per unit (note 14)	$	(2.03	)	$	6.28		$	(1.83	)

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

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BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Balance Sheets

	December 31,
Thousands	2009			2008
ASSETS
Current assets:
Cash	$	5,766		$	2,546
Accounts and other receivables, net (note 2)		65,209			47,221
Derivative instruments (note 16)		57,133			76,224
Related party receivables (note 8)		2,127			5,084
Inventory (note 9)		5,823			1,250
Prepaid expenses		5,888			5,300
Intangibles (note 10)		495			2,771
Other current assets		-			170
Total current assets		142,441			140,566
Equity investments (note 11)		8,150			9,452
Property, plant and equipment
Oil and gas properties (note 4)		2,058,968			2,057,531
Non-oil and gas assets (note 4)		7,717			7,806
		2,066,685			2,065,337
Accumulated depletion and depreciation (note 6)		(325,596	)		(224,996	)
Net property, plant and equipment		1,741,089			1,840,341
Other long-term assets
Intangibles (note 10)		-			495
Derivative instruments (note 16)		74,759			219,003
Other long-term assets		4,590			6,977
Total assets	$	1,971,029		$	2,216,834
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable	$	21,314		$	28,302
Book overdraft		-			9,871
Derivative instruments (note 16)		20,057			10,192
Related party payables (note 8)		13,000			-
Revenue and royalties payable		18,224			20,084
Salaries and wages payable		10,244			6,249
Accrued liabilities		9,051			5,292
Total current liabilities		91,890			79,990
Long-term debt (note 12)		559,000			736,000
Deferred income taxes (note 7)		2,492			4,282
Asset retirement obligation (note 13)		36,635			30,086
Derivative instruments (note 16)		50,109			10,058
Other long-term liabilities		2,102			2,987
Total  liabilities		742,228			863,403
Equity:
Partners' equity (note 14)		1,228,373			1,352,892
Noncontrolling interest (note 15)		428			539
Total equity		1,228,801			1,353,431
Total liabilities and equity	$	1,971,029		$	2,216,834
Limited partner units outstanding		52,784			52,636

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

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BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Cash Flows

	Year Ended December 31,
Thousands of dollars	2009			2008			2007
Cash flows from operating activities
Net income (loss)	$	(107,257	)	$	378,424		$	(60,266	)
Adjustments to reconcile net income (loss) to cash flow from operating activities:
Depletion, depreciation and amortization		106,843			179,933			29,422
Unit-based compensation expense		12,661			6,907			12,999
Unrealized (gain) loss on derivative instruments		213,251			(370,734	)		103,862
Distributions greater (less) than income from equity affiliates		1,302			1,198			(28	)
Deferred income tax		(1,790	)		1,207			(1,229	)
Amortization of intangibles		2,771			3,131			2,174
Loss on sale of assets		5,965			-			-
Other		3,294			2,643			2,182
Changes in net assets and liabilities:
Accounts receivable and other assets		(6,313	)		258			(24,713	)
Inventory		(4,573	)		4,454			4,829
Net change in related party receivables and payables		2,957			32,688			(39,202	)
Accounts payable and other liabilities		(4,753	)		(13,413	)		30,072
Net cash provided by operating activities		224,358			226,696			60,102
Cash flows from investing activities (a)
Capital expenditures		(29,513	)		(131,082	)		(23,549	)
Proceeds from sale of assets, net		23,284			-			-
Property acquisitions		-			(9,957	)		(996,561	)
Net cash used by investing activities		(6,229	)		(141,039	)		(1,020,110	)
Cash flows from financing activities
Issuance of common units, net of discount		-			-			663,338
Purchase of common units		-			(336,216	)		-
Distributions to predecessor members concurrent with initial public offering		-			-			581
Distributions (b)		(28,038	)		(121,349	)		(60,497	)
Proceeds from the issuance of long-term debt		249,975			803,002			574,700
Repayments of long-term debt		(426,975	)		(437,402	)		(205,800	)
Book overdraft		(9,871	)		7,951			(116	)
Long-term debt issuance costs		-			(5,026	)		(6,362	)
Net cash provided (used) by financing activities		(214,909	)		(89,040	)		965,844
Increase (decrease) in cash		3,220			(3,383	)		5,836
Cash beginning of period		2,546			5,929			93
Cash end of period	$	5,766		$	2,546		$	5,929

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

(b) 2009 and 2008 include distributions on equivalent units of $0.7 million and $2.3 million, respectively.

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

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BreitBurn Energy Partners L.P. and Subsidiaries

Consolidated Statements of Partners' Equity

Thousands	Common Units			Limited Partners			General Partner			Total
Balance, December 31, 2006		21,976		$	174,395		$	2,813		$	177,208
Issuance of units (a)		21,348			700,000			-			700,000
Private offering investment (b)		23,697			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		67,021		$	1,423,418		$	1,390		$	1,424,808
Redemption of common units from predecessors (c)		(14,405	)		(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)		-			380,255			(2,019	)		378,236
Contribution of general partner interest to the Partnership (d)		-			(1,063	)		1,063			-
BreitBurn Management purchase (e)		20			-			-			-
Other		-			30			-			30
Balance, December 31, 2008		52,636		$	1,352,892		$	-		$	1,352,892
Distributions		-			(27,371	)		-			(27,371	)
Distributions paid on unissued units under incentive plans		-			(667	)		-			(667	)
Units issued under incentive plans		148			7,488						7,488
Unit-based compensation					3,322			-			3,322
Net loss		-			(107,290	)		-			(107,290	)
Other		-			(1	)		-			(1	)
Balance, December 31, 2009		52,784		$	1,228,373		$	-		$	1,228,373

(a) Reflects the issuance of Common Units for the Quicksilver acquisition.

(b) Reflects the issuance of Common Units in three private placements.

(c) Reflects the purchase of Common Units from subsidiaries of Provident.

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

(e) Reflects issuance of Common Units to Co-CEOs in exchange for their interest in BreitBurn Management.

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

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Notes to Consolidated Financial Statements

Note 1.  Organization

The Partnership is a Delaware limited partnership formed on March 23, 2006.  In connection with our initial public offering in October 2006, BreitBurn Energy Company L.P. (“BEC”), our Predecessor, contributed to us certain properties, which included fields in the Los Angeles Basin in California and the Wind River and Big Horn Basins in central Wyoming.  In 2007, we acquired certain interests in oil leases and related assets located in Florida for approximately $110 million, assets located in California for approximately $93 million and properties located in Michigan, Indiana and Kentucky from Quicksilver Resources Inc. (“Quicksilver”) for approximately $1.46 billion (the “Quicksilver Acquisition”).

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 8 for information regarding our relationship with BreitBurn Management.

Our wholly owned subsidiary, BreitBurn Finance Corporation was incorporated on June 1, 2009 under the laws of the State of Delaware.  BreitBurn Finance Corporation is wholly owned by us, and has no assets or liabilities.  Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto.

As of December 31, 2009, 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, BOLP and BreitBurn Finance Corporation.

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.

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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 2009 presentation.

In the first quarter of 2009, we began classifying regional operation management expenses as operating costs rather than general and administrative expenses to better align our operating and management costs with our organizational structure and to be more consistent with industry practices.  As such, we have revised classification of these expenses for the years ended December 31, 2008 and 2007, respectively.  The reclassification did not affect previously reported total revenues, net income or net cash provided by operating activities.  The following table reflects all classification changes for the years ended December 31, 2008 and 2007, respectively:

	Year Ended December 31,
Thousands of dollars	2008			2007
Operating costs
As previously reported	$	149,681		$	70,329
District expense reclass from G&A		12,324			3,660
As revised	$	162,005		$	73,989
G&A expenses
As previously reported	$	43,435		$	30,588
District expense reclass to operating costs		(12,324	)		(3,660	)
As revised	$	31,111		$	26,928

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 Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805 “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.

Business segment information

ASC 280 “Segment Reporting” establishes standards for reporting information about operating segments.  Segment reporting is not applicable because our oil and gas operating areas have similar economic characteristics.  We acquire, exploit, develop 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.

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Cash and cash equivalents

We consider all investments with original maturities of three months or less to be cash equivalents.  At December 31, 2009 and 2008 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.

At December 31, 2009, accounts receivable also included a $4.3 million receivable from our insurance company related to legal costs incurred during the lawsuit with Quicksilver and a $13.0 million receivable from our insurance company related to the settlement of the lawsuit.

As of December 31, 2009, we did not carry an allowance for doubtful accounts receivable.

During 2008 we terminated our crude oil derivative instruments with Lehman Brothers due to their bankruptcy.  On October 21, 2009, we completed the transfer and sale of our claims in the bankruptcy cases filed by Lehman Brothers Commodity Services Inc. and Lehman Brothers Holdings Inc. (together referred to as Lehman Brothers), to a third party.  We recognized a $1.9 million gain reflected in gains and losses on commodity derivative instruments on the consolidated statements of operations.  At December 31, 2008, we had an allowance of $4.6 million related to the Lehman Brothers crude oil derivative contracts.

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 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.

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 generally computed on a field-by-field basis where applicable 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.

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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 three to 20 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.  In 2009, our reserves disclosures were in accordance with Release No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release 33-8995”), issued by the SEC in December, 2008 as well as ASC 932 which incorporates the SEC release.  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 ASC 410 “Asset Retirement and Environmental Obligations.”  This topic 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 ASC 360 “Property, Plant and Equipment.”  Under ASC 360, 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 future cash flows are based on total proved and risk-adjusted probable and possible reserves and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six thereafter at 2.5 percent per year.  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.

We assess our long-lived assets for impairment generally on a field-by-field basis where applicable.  We did not record an impairment charge in 2009 or 2007.  Because of the low commodity prices that existed at year end 2008, we recorded $51.9 million in impairments and $34.5 million in price related depletion and depreciation adjustments.  Price related adjustments to depletion and depreciation in 2009 were immaterial.  See Note 6 for a discussion of our impairments and price related depletion and depreciation adjustments.

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.

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Equity-based compensation

ASC 718 “Compensation – Stock Compensation” establishes standards for charging compensation expenses based on fair value provisions.  BreitBurn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 17.  Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period.We recognize equity-based compensation costs on a straight line basis over the annual vesting periods.  Awards classified as liabilities were revalued at each reporting period and changes in the fair value of the options were recognized as compensation expense over the vesting schedules of the awards.

Fair market value of financial instruments

The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables, 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 have accounted for all business combinations using the purchase method, in accordance with ASC 805 “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 have not recognized any goodwill from any business combinations.

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.  At times, such balances may be in excess of the Federal Insurance Corporation insurance limit.  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.  We enter into commodity and interest rate derivative instruments.  Our derivative counterparties are all lenders under our credit facility and we periodically monitor their credit ratings.

Derivatives

ASC 815 “Derivatives and Hedging” 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 on 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 ASC 815, 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,” now codified within ASC 820, “Fair Value Measurements and Disclosures.”  ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.  Fair value measurement under ASC 820 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 ASC 820 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.

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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 ASC 740, “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.

ASC 740 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 December 31, 2009, 2008 and 2007 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

Net Income or loss per unit

ASC 260 “Earnings per Share” requires use of the “two-class” method of computing earnings per unit for all periods presented.  The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed.  Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation.  Our unvested restricted phantom units (“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security.  Accordingly, our calculation is prepared on a combined basis and is presented as earnings per Common Unit.  See Note 14 for our earnings per Common Unit calculation.

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, 2009 and 2008, 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.

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3.  Accounting Pronouncements

We adopted new accounting pronouncements during 2009 related to fair value measurements as discussed in Notes 13 and 16, the earnings per share impact of instruments granted in share-based payment transactions as discussed in Note 14, noncontrolling interests as discussed in Note 15, disclosures about derivative instruments and hedging activities as discussed in Note 16 and business combinations as discussed in Note 4, which we will apply prospectively to business combinations with acquisition dates after January 1, 2009.  We also adopted a new accounting pronouncement related to the determination of the useful lives of intangible assets and an accounting pronouncement related to the fair valuation of liabilities when a quoted price in an active market is not available, with no impact on our financial position, results of operations or cash flows.

Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 105 “Generally Accepted Accounting Principles” establishes the FASB ASC as the source of authoritative accounting principles recognized by the FASB to be applied in the preparation of financial statements in conformity with GAAP.  ASC 105 explicitly recognizes rules and interpretive releases of the SEC under federal securities laws as authoritative GAAP for SEC registrants.  This topic, which has changed the way we reference GAAP, is effective for financial statements ending after September 15, 2009.  This topic does not change GAAP and did not have an impact on our financial position, results of operations or cash flows.

SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting.”  In December 2008, the SEC issued Release 33-8995 adopting new rules for 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.  The new rules do 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 new rules also permit 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, the new rules also replace 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.  We use quarter-end reserves to calculate quarterly DD&A and, as such, adoption of the new standard had an impact on fourth quarter 2009 DD&A expense.  See Note 22.  The impact that adopting Release 33-8995 has had on our financial statements is not practical to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.  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.  See Note 22 for the impact Release 33-8995 has had on the calculation of our crude oil and natural gas reserves.

Accounting Standards Update (“ASU”) 2010-03 “Extractive Activities – Oil and Gas.”  In January 2010, the FASB issued ASU 2010-03 to align the oil and gas reserve estimation and disclosure requirements of Extractive Activities – Oil and Gas (Topic 932) with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements which was issued on December 31, 2008.We calculate total estimated proved reserves and disclose our oil and natural gas activities in accordance with ASC 932“Extractive Activities – Oil and Gas,” which incorporates SEC release No. 33-8995, “Modernization of Oil and Gas Reporting.” and ASU 2010-03 “Extractive Activities – Oil and Gas.”

ASU 2010-06 “Fair Value Measurements and Disclosures.”  In January 2010, the FASB issued ASU 2010-06 to make certain amendments to Subtopic 820-10 that require two additional disclosures and clarify two existing disclosures.  The new disclosures require details of significant transfers in and out of level 1 and level 2 measurements and the reasons for the transfers, and a gross presentation of activity within the level 3 roll forward that presents separately, information about purchases, sales, issuances and settlements.  The ASU clarifies the existing disclosures with regard to the level of disaggregation of fair value measurements by class of assets and liabilities rather than major category where the reporting entities would need to apply judgment to determine the appropriate classes of other assets and liabilities.  The second clarification relates to disclosures of valuation techniques and inputs for recurring and non recurring fair value measurements using significant other observable inputs and significant unobservable inputs for level 2 and level 3 measurements, respectively.  ASU 2010-06 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years.  We do not expect the adoption of ASU 2010-06 (ASC 820-10) to have an impact on our financial position, results of operations or cash flows.

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In June 2009, the FASB issued authoritative guidance for the consolidation of variable interest entities, which changed the consolidation guidance applicable to a variable interest entity ("VIE").  The guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis.  The qualitative analysis will include, among other things, consideration of who has the power to direct the activities of the entity that most significantly impact the entity’s economic performance and who has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE.  This guidance also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE.  Former guidance required reconsideration of whether an enterprise was the primary beneficiary of a VIE only when specific events had occurred.  The guidance also requires enhanced disclosures about an enterprise’s involvement with a VIE.  We will adopt this guidance effective January 1, 2010, and we are assessing the impact this guidance may have on our consolidated financial statements.

4.  Acquisitions

On June 17, 2008, we purchased Provident Energy Trust’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 using the purchase method.

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.

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Pro Forma Information

The following unaudited pro forma financial information presents a summary of our consolidated results of operations for 2007, assuming the Quicksilver Acquisition and the acquisitions in Florida and California had been completed as of the beginning of the year, including adjustments to reflect the allocation of the purchase price to the acquired net assets.  The pro forma financial information assumes our 2007 private placements of Common Units (see Note 14) 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
Thousands of dollars, except per unit amounts	December 31, 2007 (1)
Revenues	$	233,761
Net income (loss)		(43,966	)
Net income (loss) per unit
Basic	$	(0.65	)
Diluted		(0.65	)
(1) Results include losses on derivative instruments of $101.0 million for the year ended December 31, 2007.

Effective January 1, 2009, we will account for all business combinations using the acquisition method in accordance with ASC 805.

5.  Disposition of Assets

On July 17, 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas to a private buyer for $23 million in cash.  This transaction was effective July 1, 2009.  The proceeds from this transaction were used to reduce our outstanding borrowings under our credit facility.  In connection with the sale, the borrowing base under our credit facility was reduced by $3 million to $732 million.

The Lazy JL Field properties produced approximately 245 Boe per day during the first six months of 2009, of which 96 percent was crude oil.  The net carrying value at the date of sale was $28.5 million, of which $28.7 million was reflected in net property, plant and equipment on the balance sheet and $0.2 million was reflected in asset retirement obligation on the balance sheet.  We recognized a loss of $5.5 million in 2009 related to the sale of the field.

6.  Impairments and Price Related Depletion and Depreciation Adjustments

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.  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 oil and gas property 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.

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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.

For the years ended December 31, 2009 and 2007, we reviewed our long-lived oil and gas assets and did not record any material impairments or price related adjustments to depletion and depreciation expense.

7.  Income Taxes

We, and all of our subsidiaries, with the exception of Phoenix Production Company (“Phoenix”), Alamitos Company, BreitBurn Management and BreitBurn Finance Corporation, 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.

The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following:

	Year Ended December 31,
Thousands of dollars	2009			2008		2007
Federal income tax expense (benefit)
Current	$	247		$	257	$	-
Deferred (a)		(1,790	)		1,207		(1,229	)
State income tax expense (benefit) (b)		15			475		-
Total	$	(1,528	)	$	1,939	$	(1,229	)

(a) Related to Phoenix Production Company, our wholly owned subsidiary.

(b) Primarily in the states of Michigan, California and Texas.

We record income tax expense for Phoenix, a tax-paying corporation, in accordance with ASC 740 “Income Taxes.”  The following is a reconciliation of federal income taxes at the statutory rates to federal income tax expense (benefit) for Phoenix:

	Year Ended December 31,
Thousands of dollars	2009			2008			2007
Income (loss) subject to federal income tax		(4,052	)		3,904			(4,498	)
Federal income tax rate		34	%		34	%		34	%
Income tax at statutory rate		(1,378	)		1,327			(1,529	)
Other		(299	)		-			300
Income tax expense (benefit)	$	(1,677	)	$	1,327		$	(1,229	)

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At December 31, 2009 and 2008, a net deferred federal income tax liability of $2.5 million and $4.3 million, respectively, were reported in our consolidated balance sheet for Phoenix.  Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and the amount used for income tax purposes.  Significant components of our net deferred tax liabilities are presented in the following table.

	December 31,
Thousands of dollars	2009			2008
Deferred tax assets:
Net operating loss carryforwards	$	422		$	767
Asset retirement obligation		358			337
Unrealized hedge loss		85			-
Other		276			103
Deferred tax liabilities:
Depreciation, depletion and intangible drilling costs		(3,101	)		(3,404	)
Unrealized hedge gain		-			(2,085	)
Deferred realized hedge gain		(532	)		-
Net deferred tax liability	$	(2,492	)	$	(4,282	)

At December 31, 2009, we had $1.2 million of estimated unused operating loss carry forwards.  We did not provide a valuation allowance against this deferred tax asset as we expect sufficient future taxable income to offset the unused operating loss carry forwards.

On a consolidated basis, cash paid for federal and state income taxes totaled $0.6 million in 2009, $0.6 million in 2008 and $0.1 million in 2007.

ASC 740 “Income Taxes,” 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 topic 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 December 31, 2009 and 2008 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.

8.  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, 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 for indirect expenses.  The monthly fee was set at $775,000 for 2008.

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 BEC.  This transaction included the acquisition of a 96.02 percent indirect interest in BEC, previously owned by Provident Energy Trust (“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 is a separate Delaware oil and gas partnership with operations in California, was a separate U.S. subsidiary of Provident and was our Predecessor.

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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 the Second Amended and Restated Administrative Services Agreement (the “Administrative Services Agreement”) to manage BEC's properties for a term of five years.  In addition to the monthly fee, BreitBurn Management charges BEC for all direct expenses including incentive plan costs and direct payroll and administrative costs related to BEC properties and operations.  The monthly fee is contractually based on an annual projection of anticipated time spent by each employee who provides services to both us and BEC during the ensuing year and is subject to renegotiation annually by the parties during the term of the agreement.  For 2009, each BreitBurn Management employee estimated his or her time allocation independently based on 2008.  These estimates were then reviewed and approved by each employee’s manager or supervisor.  The results of this process were provided to both the audit committee of the board of directors of our General Partner (composed entirely of independent directors) (the “audit committee”) and the board of representatives of BEC’s parent (the “BEC board”).  The audit committee and the non-management members of the BEC board agreed on the 2009 monthly fee as provided in the Administrative Services Agreement.  Effective January 1, 2009, the monthly fee was renegotiated to $500,000.  The reduction in the monthly fee is attributable to the overall reduction in general and administrative expenses, excluding unit-based compensation, for BreitBurn Management in 2009, the new time allocation study described above and the fact that additional costs are being charged directly to us and BEC compared to prior years.  The monthly fee will be renegotiated for 2010.

In addition, we 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, 2009 and December 31, 2008, we had current receivables of $1.4 million and $4.4 million, respectively, 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.  During 2009, the monthly charges to BEC for indirect expenses totaled $6.5 million and charges for direct expenses including direct payroll and administrative costs totaled $6.1 million.  For the year ended December 31, 2009, total oil and gas sales made by BEC on our behalf were approximately $1.3 million.  For the year ended December 31, 2008, total oil and gas sales made by BEC on our behalf were approximately $2.1 million.  At December 31, 2009 and 2008, we had receivables of $0.3 million and $0.1 million, respectively, due from certain of our affiliates for management fees due from equity affiliates and operational expenses incurred on behalf of equity affiliates.

Pursuant to a transition services agreement through March 2008, Quicksilver provided to us services for accounting, land administration, and marketing and charged us $0.9 million for the first quarter of 2008.  These charges were included in general and administrative expenses on the consolidated statements of operations.  Quicksilver also buys natural gas from us in Michigan.  For the year ended December 31, 2009, total net gas sales to Quicksilver were approximately $2.8 million and the related receivable was $0.4 million as of December 31, 2009.  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.

On October 31, 2008, Quicksilver, an owner of approximately 40 percent of our Common Units, instituted a lawsuit in the District Court of Tarrant County, Texas naming us as a defendant along with others.  The primary claims were as follows:  Quicksilver alleged that BOLP breached the Contribution Agreement with Quicksilver, dated September 11, 2007, based on allegations that we made false and misleading statements relating to our relationship with Provident.  Quicksilver also alleged 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 also alleged 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 sought a 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.

In February 2010, we and Quicksilver agreed to settle all claims with respect to the litigation filed by Quicksilver (the “Settlement”).  We expect the terms of the Settlement to be implemented upon the dismissal of the lawsuit in Texas in early April 2010.  The parties have agreed to dismiss all pending claims before the Court and have mutually released each party, its affiliates, agents, officers, directors and attorneys from any and all claims arising from the subject matter of the pending case before the Court.  We have also agreed to pay Quicksilver $13.0 million and expect this amount to be paid by insurance.  In addition, Mr. Halbert S. Washburn and Mr. Randall H. Breitenbach will resign from the Board of Directors and the Board will appoint two new directors designated by Quicksilver, one of whom will qualify as an independent director and one of whom will be a current independent board member now serving on Quicksilver’s board of directors, provided that such director not be a member of Quicksilver’s management.

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At December 31, 2009, we recorded a $13.0 million payable to Quicksilver in connection with the monetary portion of the Settlement.

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. (“Plains Marketing”), 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. At December 31, 2007, the receivable from Plains Marketing was $10.5 million, which was collected in the first quarter of 2008.

9. Inventory

In Florida, crude oil inventory was $5.8 million and $1.3 million at December 31, 2009 and 2008, respectively. For the year ended December 31, 2009, we sold 529 MBbls of crude oil and produced 590 MBbls from our Florida operations. 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. We assessed our crude-oil inventory at December 31, 2009 and determined that the carrying value of our inventory was below market value and, therefore, no write-down was necessary. During the fourth quarter of 2008, commodity prices decreased substantially. As a result, we assessed our crude oil inventory 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, which could have a negative impact on our future consolidated financial position, results of operations and cash flows.

10. 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. Amortization expense of $1.0 million for 2009 and 2008, respectively, is included in the oil, natural gas and natural gas liquid sales line on the consolidated statements of operations. As of December 31, 2009, our intangible asset related to the crude oil sales contracts was $0.5 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. Amortization expense of $1.8 million and $2.1 million for 2009 and 2008, respectively, is included in the total operating expenses line on the consolidated statements of operations. As of December 31, 2009, the intangible asset related to these retention bonuses was fully amortized.

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11.  Equity Investments

We had equity investments at December 31, 2009 and December 31, 2008 of $8.2 million and $9.5 million, respectively which primarily represent investments in natural gas processing facilities. For the years ended December 31, 2009 and 2008, we recorded less than $0.1 million and $0.8 million, respectively, in earnings from equity investments and $1.4 million and $2.0 million, respectively, in dividends. Earnings from equity investments are reported in the other revenue, net line on the consolidated statements of operations.

At December 31, 2009, 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 $7.0 million. The remaining $1.2 million consists of smaller interests in several other investments. At December 31, 2008, our equity investment totaled $9.5 million. The decrease during 2009 is primarily due to dividends received during the year.

12. 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”).

The initial borrowing base of the Amended and Restated Credit Agreement was $700 million and was increased to $750 million on April 10, 2008. 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. Borrowings under the Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80 percent of the total value of our oil and gas properties.

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 on our ability to make distributions unless after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base, and we have the ability to borrow at least ten percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX); 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.

EBITDAX is not a defined GAAP measure. Our credit facility defines EBITDAX as net income plus interest expense and other financing costs, income tax provision, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, non-cash unit based compensation expense, loss or gain on sale of assets, cumulative effect of changes in accounting principles, amortization of intangible sales contracts and amortization of intangible asset related to employment retention allowance, excluding adjusted EBITDAX attributable to our BEPI limited partner interest and including the cash distribution received from BEPI.

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.

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 us 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, 2009 and December 31, 2008, we were in compliance with the credit facility’s covenants.

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In January 2009, we monetized certain in-the-money commodity hedges for approximately $46 million, the net proceeds of which were used to reduce outstanding borrowings under our credit facility. In April 2009, in connection with a scheduled redetermination, our borrowing base under our Amended and Restated Credit Agreement was redetermined at $760 million. In June 2009, we monetized additional in-the-money commodity hedges for approximately $25 million, the net proceeds of which were used to reduce outstanding borrowings under our credit facility. As a result of the monetization, our borrowing base was reset at $735 million.

On July 17, 2009, we sold the Lazy JL Field for $23 million in cash. The proceeds from this transaction were used to reduce outstanding borrowings under our credit facility and our borrowing base was reduced by $3 million to $732 million.

In October 2009, in connection with our semi-annual borrowing base redetermination, our borrowing base was reaffirmed at $732 million. Our next semi-annual borrowing base redetermination is scheduled for April 2010.

As of December 31, 2009 and December 31, 2008, we had $559.0 million and $736.0 million, respectively, in indebtedness outstanding under the credit facility, which will mature on November 1, 2011. At December 31, 2009, we had $173.0 million available under our borrowing base. At December 31, 2009, the 1-month LIBOR interest rate plus an applicable spread was 1.990 percent on the 1-month LIBOR portion of $552.0 million and the prime rate plus an applicable spread was 4.000 percent on the prime debt portion of $7.0 million. The amounts reported on our consolidated balance sheets for long-term debt approximate fair value due to the variable nature of our interest rates.

At December 31, 2009 and 2008, we had $0.3 million in letters of credit outstanding.

Our interest expense is detailed in the following table:

	Year Ended December 31,
Thousands of dollars	2009		2008		2007
Credit agreement (including commitment fees)	$	15,532	$	26,534	$	5,876
Amortization of discount and deferred issuance costs		3,295		2,613		382
Total	$	18,827	$	29,147	$	6,258
Cash paid for interest	$	28,350	$	29,767	$	3,545

13.  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 $257.4 million at December 31, 2009 and was $256.8 million at December 31, 2008.  Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years.  We expect our cash settlements to be approximately $1.1 million and less than $0.1 million for 2010 and 2012, respectively.  Cash settlements for the years after 2014 are expected to be $35.5 million.  Estimated cash flows have been discounted at our credit adjusted risk free rate of seven percent and adjusted for inflation using a rate of two percent.  Our credit adjusted risk free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.  Each year we review and, to the extent necessary, revise our asset retirement obligation estimates. During 2009, we obtained new estimates to evaluate the cost of abandoning our properties. As a result, we increased our ARO estimates by $4.9 million to reflect recent costs incurred for plugging and abandonment activities in Michigan and Florida.

ASC 820 “Fair Value Measurements and Disclosures” 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.  Level 2 includes inputs other than quoted prices that are included in Level 1, and can be derived from observable data, including third party data providers.  These inputs may also include observable transactions in the market place.  Level 3 is given to unobservable inputs.  We consider the inputs to our asset retirement obligation valuation to be Level 3 as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.

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Changes in the asset retirement obligation for the years ended December 31, 2009 and 2008 are presented in the following table:

	Year Ended December 31,
Thousands of dollars	2009			2008
Carrying amount, beginning of period	$	30,086		$	27,819
Liabilities settled in the current period		(470	)		(1,054	)
Revisions (a)		4,883			1,363
Acquisitions (dispositions) (b)		(252	)		-
Accretion expense		2,388			1,958
Carrying amount, end of period	$	36,635		$	30,086

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

(b) Relates to disposition of the Lazy JL Field.

14.  Partners’ Equity

At December 31, 2009, we had 52,784,201 Common Units outstanding.

At December 31, 2009 and December 31, 2008, we had 6,700,000 units authorized for issuance under our long-term incentive compensation plans.  At December 31, 2009 and December 31, 2008, there were 2,961,659 and 1,422,171, respectively, of partnership-based units outstanding that are eligible to be paid in Common Units upon vesting.

In February 2009, 134,377 Common Units were issued to employees under our 2006 Long-Term Incentive Plan.

In October 2009, 14,190 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2006 and vested in October 2009.

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.

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.

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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.

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 was 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 18 months after November 1, 2007.  In addition, the agreements gave 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.

Earnings per Common Unit

ASC 260 “Earnings per Share” requires use of the “two-class” method of computing earnings per unit for all periods presented.  The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed.  Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation.  Our unvested RPUs and CPUs participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security.  Accordingly, the presentation below is prepared on a combined basis and is presented as earnings per Common Unit.

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The following is a reconciliation of net earnings and weighted average units for calculating basic net earnings per Common Unit and diluted net earnings per Common Unit.  For the years ended December 31, 2009 and 2007, RPUs and CPUs have been excluded from the calculation of basic earnings per unit, as we were in a net loss position.

	Year Ended December 31,
Thousands, except per unit amounts	2009			2008		2007
Net income (loss) attributable to limited partners	$	(107,290	)	$	380,255	$	(59,685	)
Distributions on participating units not expected to vest		-			22		-
Net income (loss) attributable to common unitholders and participating securities	$	(107,290	)	$	380,277	$	(59,685	)
Weighted average number of units used to calculate basic and diluted net income (loss) per unit:
Common Units		52,757			59,239		32,577
Participating securities (a)		-			1,184		-
Denominator for basic earnings per Common Unit		52,757			60,423		32,577
Dilutive units (b)		-			142		-
Denominator for diluted earnings per Common Unit		52,757			60,565		32,577
Net income (loss) per common unit
Basic	$	(2.03	)	$	6.29	$	(1.83	)
Diluted	$	(2.03	)	$	6.28	$	(1.83	)

(a) The year ended December 31, 2009 excludes 2,636,800 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.  For the year ended December 31, 2008, basic earnings per unit is based upon the weighted average number of Common Units outstanding plus the weighted average number of potentially issuable RPUs and CPUs. The year ended December 31, 2007 had no potentially issuable weighted average RPUs and CPUs from participating securities.

(b) The years ended December 31, 2009 and 2007 exclude 102,090 and 150,813, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per Common Unit.  Weighted average dilutive units for the year ended December 31, 2008 include units potentially issuable under compensation plans that do not qualify as participating securities.

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.

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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 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.  During the three months ended March 31, 2009, we also paid cash equivalent to the distribution paid to our unitholders of $0.7 million to holders of outstanding Restricted Phantom Units and Convertible Phantom Units issued under our Long-Term Incentive Plans.

With the borrowing base redetermination in April 2009 (see Note 12), our borrowings exceeded 90 percent of the reset borrowing base and, therefore, under the terms of our credit facility we were restricted from making a distribution for the first quarter of 2009.  Although we were not restricted from making distributions under the terms of our credit facility for the second, third and fourth quarters of 2009, we elected not to declare distributions in light of total leverage levels and other factors.  We are restricted from paying distributions under our credit facility unless, after giving effect to such distribution, our outstanding debt is less than 90 percent of the borrowing base and we have the ability to borrow at least ten percent of the borrowing base while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is total indebtedness to EBITDAX).

15.  Noncontrolling interest

ASC 810 “Consolidation”requires that noncontrolling interests be classified as a component of equity and 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.

On May 25, 2007, we acquired the limited partner interest (99 percent) of BEPI from TIFD.  As such, we are fully consolidating the results of BEPI and thus are recognizing a noncontrolling interest representing the book value of the general partner’s interests.  At December 31, 2009 and December 31, 2008, the amount of this noncontrolling interest was $0.4 million and $0.5 million, respectively.  For the years ended December 31, 2009 and 2008, we recorded net income attributable to the noncontrolling interest of less than $0.1 million and $0.2 million, respectively, and $0.1 million and $0.2 million, respectively, in dividends.

BEPI’s general partner interest is held by a wholly owned subsidiary of BEC.  The general partner of BEPI holds a 35 percent reversionary interest under the existing limited partnership agreement applicable to the properties.  This reversionary interest is expected to occur at a defined payout, which is estimated to occur in 2015 based on year-end price and cost projections.

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16.  Financial Instruments

Fair Value of Financial Instruments

Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flow.  Routinely, we utilize derivative financial instruments to reduce this volatility.  To the extent we have hedged prices for a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increase, our margins would be adversely affected.

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable.  Our derivatives expose us to credit risk from counterparties.  As of December 31, 2009, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank N.A., JP Morgan Chase Bank N.A., Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion Bank.  We terminated all derivative financial instruments with Lehman Brothers on September 19, 2008.  Our counterparties are all lenders under our Amended and Restated Credit Agreement.  During 2008, there was extreme volatility and disruption in the capital and credit markets which reached unprecedented levels.  Continued volatility and disruption may adversely affect the financial condition of our derivative counterparties.  On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis.  We periodically obtain credit default swap information on our counterparties.  Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract.  This risk is managed by diversifying the derivative portfolio.  As of December 31, 2009, each of these financial institutions carried an S&P credit rating of A or above.  As of December 31, 2009, our largest derivative asset balances were with JP Morgan Chase Bank N.A., who accounted for approximately 64 percent of our derivative asset balances, and Credit Suisse International and Credit Suisse Energy LLC, who together accounted for approximately 26 percent of our derivative asset balances.

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 ASC 815 “Derivatives and Hedging.”  Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes and instead recognize changes in the fair value immediately in earnings.  We had a realized gain of $167.7 million and an unrealized loss of $219.1 million for the year ended December 31, 2009 relating to our various market-based commodity contracts.  We had a net derivative asset relating to our commodity contracts of $73.2 million at December 31, 2009.

In January 2009, we terminated a portion of our 2011 and 2012 crude oil derivative contracts and replaced them with new contracts with the same counterparty for the same volumes at market prices.  We realized $32.3 million from this termination.  In January 2009, we also terminated a portion of our 2011 and 2012 natural gas derivative contracts 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 outstanding borrowings under our credit facility.

In June 2009, we terminated an additional portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices.  We realized $18.9 million from the termination of natural gas derivative contracts and $6.1 million from the termination of crude oil contracts.  Proceeds from these contracts were used to pay down outstanding borrowings under our credit facility.

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.  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 eight 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 by contracts with 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.

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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.

Including the impact of the changes noted above we had the following contracts in place at December 31, 2009:

	Year
	2010			2011			2012		2013		2014
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		43,869			25,955			19,129		27,000		-
Average Price ($/MMBtu)	$	8.20		$	7.26		$	7.10	$	6.92	$	-
Collars:
Hedged Volume (MMBtu/d)		3,405			16,016			19,129		-		-
Average Floor Price ($/MMBtu)	$	9.00		$	9.00		$	9.00	$	-	$	-
Average Ceiling Price ($/MMBtu)	$	12.79		$	11.28		$	11.89	$	-	$	-
Total:
Hedged Volume (MMBtu/d)		47,275			41,971			38,257		27,000		-
Average Price ($/MMBtu)	$	8.26		$	7.92		$	8.05	$	6.92	$	-
Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		2,808			2,616			2,539		3,500		748
Average Price ($/Bbl)	$	81.35		$	66.22		$	67.24	$	76.79	$	88.65
Participating Swaps: (a)
Hedged Volume (Bbls/d)		1,993			1,439			-		-		-
Average Price ($/Bbl)	$	64.40		$	61.29		$	-	$	-	$	-
Average Participation %		55.5	%		53.2	%		-		-		-
Collars:
Hedged Volume (Bbls/d)		1,279			2,048			2,477		500		-
Average Floor Price ($/Bbl)	$	102.85		$	103.42		$	110.00	$	77.00	$	-
Average Ceiling Price ($/Bbl)	$	136.16		$	152.61		$	145.39	$	103.10	$	-
Floors:
Hedged Volume (Bbls/d)		500			-			-		-		-
Average Floor Price ($/Bbl)	$	100.00		$	-		$	-	$	-	$	-
Total:
Hedged Volume (Bbls/d)		6,580			6,103			5,016		4,000		748
Average Price ($/Bbl)	$	81.81		$	77.54		$	88.35	$	76.82	$	88.65

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

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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, 2009, our total debt outstanding was $559 million.  In order to mitigate our interest rate exposure, we had the following interest rate swaps in place at December 31, 2009, 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, 2010 to January 8, 2010	$	100,000		3.3873	%
January 1, 2010 to December 20, 2010		300,000		3.6825	%
January 20, 2010 to October 20, 2011		100,000		1.6200	%
December 20, 2010 to October 20, 2011		200,000		2.9900	%

For the year ended December 31, 2009, we had realized losses of $13.1 million and unrealized gains of $5.9 million relating to our interest rate swaps.  We had net financial instruments payable related to our interest rate swaps of $11.4 million at December 31, 2009.

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.  On September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no cost, our interest rate swap with Lehman Brothers for $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 for $50 million at a fixed rate of 3.0450 percent, for the period from September 8, 2008 to July 8, 2009.

ASC 815 requires disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under ASC 815, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.  This topic requires the disclosures detailed below.

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Fair value of derivative instruments not designated as hedging instruments under ASC 815:

Balance sheet location, thousands of dollars	Oil Commodity Derivatives			Natural Gas Commodity Derivatives		Interest Rate Derivatives			Commodity derivative netting (a)			Total Financial Instruments
December 31, 2009
Assets
Current assets - derivative instruments	$	17,666		$	39,467	$	-		$	-		$	57,133
Other long-term assets - derivative instruments		35,382			42,620		-			(3,243	)		74,759
Total assets		53,048			82,087		-			(3,243	)		131,892
Liabilities
Current liabilities - derivative instruments		(10,234	)		-		(9,823	)		-			(20,057	)
Long-term liabilities - derivative instruments		(51,730	)		-		(1,622	)		3,243			(50,109	)
Total liabilities		(61,964	)		-		(11,445	)		3,243			(70,166	)
Net assets (liabilities)	$	(8,916	)	$	82,087	$	(11,445	)	$	-		$	61,726
December 31, 2008
Assets
Current assets - derivative instruments	$	44,086		$	32,138	$	-		$	-		$	76,224
Other long-term assets - derivative instruments		145,061			73,942		-			-			219,003
Total assets		189,147			106,080		-			-			295,227
Liabilities
Current liabilities - derivative instruments		(1,115	)		-		(9,077	)		-			(10,192	)
Long-term liabilities - derivative instruments		(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

(a) Represents counterparty netting under derivative netting agreements - these contracts are reflected net on the balance sheet.

Gains and losses on derivative instruments not designated as hedging instruments under ASC 815:

Location of gain/loss, thousands of dollars	Oil Commodity Derivatives (a)			Natural Gas Commodity Derivatives (a)			Interest Rate Derivatives (b)			Total Financial Instruments
Year Ended December 31, 2009
Realized gains (losses)		66,176			101,507			(13,115	)	$	154,568
Unrealized gains (losses)		(195,127	)		(23,993	)		5,869			(213,251	)
Net gains (losses)	$	(128,951	)	$	77,514		$	(7,246	)	$	(58,683	)
Year Ended December 31, 2008
Realized losses	$	(35,146	)	$	(20,800	)	$	(2,721	)	$	(58,667	)
Unrealized gains (losses)		293,720			94,328			(17,314	)		370,734
Net gains (losses)	$	258,574		$	73,528		$	(20,035	)	$	312,067

(a) Included in gains (losses) on commodity derivative instruments on the consolidated statements of operations.

(b) Included in loss on interest rate swaps on the consolidated statements of operations.

Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,” now codified within ASC 820 “Fair Value Measurements and Disclosures.” ASC 820 defines fair value, establishes a framework for measuring fair value and establishes required disclosures about fair value measurements.  Fair value measurement under ASC 820 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 ASC 820 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.

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ASC 820 requires valuation techniques consistent with the market approach, income approach or 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.

ASC 820 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 ASC 820 are described further as follows:

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 ASC 820.  As of December 31, 2009 and December 31, 2008, our Level 3 derivative 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.

Through December 2009, we contracted with Provident on a month-to-month basis for certain derivative instrument valuation services.  Provident’s risk management group calculated the fair values of our commodity and interest rate hedges using software that marks to market our hedge contracts using forward commodity price curves and interest rates.  Inputs were obtained from third party data providers and were verified to published data where available (e.g., NYMEX).

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Beginning in the fourth quarter of 2009, our Treasury/Risk Management group began calculating the fair value of our commodity and interest rate swaps and options.  For the fourth quarter of 2009, we compared our fair value calculations to those received from the counterparties to our derivative instruments and to those received from Provident, our former fair valuation provider, and determined that our valuation results were consistent with those of our counterparties and Provident.  As such, we used our valuation for December 31, 2009.  Beginning January 1, 2010, we no longer obtain fair value calculations for our derivative instruments from Provident, but calculate them internally and continue to compare these fair value amounts to the fair value amounts that we receive from the counterparties on a monthly basis.  Any differences will be resolved and any required changes will be recorded prior to the issuance of our financial statements.
 

The model we utilize to calculate the fair value of our commodity derivative instruments is a standard option pricing model.  Inputs to the option pricing models include 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 are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX).
 

 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 at December 31, 2009 and December 31, 2008:
 

	As of December 31, 2009
Thousands of dollars	Level 1		Level 2			Level 3		Total
Assets (Liabilities):
Commodity Derivatives (swaps, put and call options)	$	-	$	(29,303	)	$	102,475	$	73,172
Other Derivatives (interest rate swaps)		-		(11,446	)		-		(11,446	)
Total	$	-	$	(40,749	)	$	102,475	$	61,726

	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 primarily of changes in fair value of our derivative instruments classified as Level 3:

	Year Ended December 31,
Thousands of dollars	2009			2008
Assets (Liabilities):
Beginning balance	$	153,218		$	44,236
Realized and unrealized gains (losses)		(44,713	)		106,154
Purchases and issuances		-			7,452
Settlements (a)		(6,030	)		(4,624	)
Ending balance	$	102,475		$	153,218

(a) Settlements reflect the monetization of oil collar contracts in June 2009 and the termination of derivative contracts with Lehman in September 2008 due to the Lehman bankruptcy.

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Unrealized losses of $63.8 million for the year ended December 31, 2009 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 gains of $19.1 million for the year ended December 31, 2009 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.  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 ASC 820 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.

17.  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 addition, 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 BreitBurn Management’s costs that were not charged to BEC are consolidated with our results.

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, it is terminated by us.

Unit Based Compensation

ASC 718 “Compensation – Stock Compensation” establishes standards for charging compensation expenses based on fair value provisions.  At December 31, 2009, the Restricted Phantom Units (RPUs) and the Convertible Phantom Units (CPUs) granted under the BreitBurn Management LTIP as well as the outstanding Directors RPUs discussed below were all classified as equity awards under the provisions of ASC 718.  These awards are being recognized as compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.
 

Prior year awards classified as liabilities were revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options were recognized as compensation expense over the vesting schedules of the awards.  These awards were settled in cash or had the option of being settled in cash or units at the choice of the holder, and were indexed to either our Common Units or to Provident Trust Units.  The liability-classified option awards were distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders received cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units.

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In connection with the changes to BreitBurn Management’s executive compensation program during 2007, employees of BreitBurn Management began to receive two new types of awards under our LTIP, namely, Restricted Phantom Units (RPUs) and Convertible Phantom Units (CPUs).

We recognized $12.7 million of compensation expense related to our various plans for the year ended December 31, 2009.

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.  Certain employees of BreitBurn Management including its executives are eligible to receive RPU awards.  We believe that RPUs properly incentivize holders of these awards to grow stable distributions for our common unitholders.  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.

RPU awards were granted to BreitBurn Management employees in 2009, 2008 and 2007 as shown in the table below.  We recorded compensation expense of $9.1 million in 2009, $3.4 million in 2008 and $7.0 million in 2007.  As of December 31, 2009, there was $13.7 million of total unrecognized compensation cost remaining for the unvested RPUs.  This amount is expected to be recognized over the remaining two year vesting period.

 Compensation expense recorded in 2009 and 2008 relates to the amortization of outstanding RPUs over their related vesting periods.  Compensation expense of $7.0 million recorded in 2007 was primarily due to the exchange of executive phantom options awards for RPUs in 2007.  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 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 quarterly distributions at the same rate payable to common unitholders immediately after grant.  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 is being expensed ratably over a three-year period beginning in 2008.  The remaining 188,545 RPUs issued in 2007 were issued to the top seven executives – including the Co-Chief Executive Officers - at a grant price of $30.29 per Common Unit.

- 33 - -

The following table summarizes information about RPUs:

	December 31,
	2009					2008					2007 (a)
	Number of			Weighted		Number of			Weighted		Number of		Weighted
	RPU			Average		RPU			Average		RPU		Average
	Units			Fair Value *		Units			Fair Value*		Units		Fair Value*
Outstanding , beginning of period		607,263		$	26.91		372,945		$	30.98		-	$	-
Granted		1,790,589			8.17		245,290			20.44		372,945		30.98
Exercised		(808,700	)		13.08		-			-		-		-
Cancelled		(14,402	)		14.45		(10,972	)		20.83		-		-
Outstanding, end of period		1,574,750		$	12.82		607,263		$	26.91		372,945	$	30.98
Exercisable, end of period		-		$	-		-		$	-		-	$	-

* At grant date

(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.

Convertible Phantom Units (CPUs)

In December 2007, seven executives received 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.  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 will be 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.

 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.

Under the original CPU Agreements, one Common Unit Equivalent (CUE) underlies each CPU at the time it was awarded to the grantee.  However, the number of CUEs underlying the CPUs would 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 CUEs underlying the CPUs would 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.

On October 29, 2009, the Compensation and Governance Committee approved an amendment to each of the existing CPU Agreements entered into with each named executive officer.  Originally under the CPU Agreements, the number of CUEs per CPU could be reduced over the five year life of the agreement to a minimum of zero, or be multiplied by a maximum of 4.768 times, based on our distribution levels.  We suspended the payment of distributions in April 2009; therefore, holders of CPU’s did not receive any distributions under the CPU Agreements as long as distributions were suspended.  Under the original chart, if the CPU’s were to vest currently – for instance in the case of the death or disability of a holder – zero units would vest to that holder.  The Committee determined that the elimination of multipliers between zero and one best represented the original incentive and retention purpose of the CPU Agreements.  With this modification to the CPU Agreements, the number of CUEs per CPU can no longer be less than one, regardless of Common Unit distribution levels.

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On January 29, 2010, the Committee also approved an amendment to each of the existing Convertible Phantom Unit (“CPU”) Agreements entered into with each named executive officer.Under these agreements, each CPU entitles its holder to receive (i) a number of our Common Units at the time of vesting equal to the number of “common unit equivalents” (“CUEs”) underlying the CPU at vesting, and (ii) current distributions on Common Units during the vesting period based on the number of CUEs underlying the CPU at the time of such distribution.  The number of CUEs underlying each CPU is determined by reference to Common Unit distribution levels during the applicable vesting period, generally calculated based upon the aggregate amount of distributions made per Common Unit for the four quarters preceding vesting.  The amendment to the CPU agreements now limits the multiplier for 20 percent of the total number of CPUs and related CUEs granted in each award to “1.”  As a result, upon vesting, CPUs for 20 percent of each award will convert to Common Units on a 1:1 basis, and with respect to that portion of the award, holders will lose the ability to earn additional Common Units based on increased distributions on Common Units.  No other modification was made to the CPU Agreements under this amendment.  Because we were accruing compensation expense using a CPU multiplier of one, these amendments had no impact on compensation expense recorded.

In the event that the CPUs vest on January 1, 2013 or if 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 subject to the 80 percent limitation put in place on January 29, 2010 as noted above).

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 the date of death or disability.  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 (subject to the 80 percent limitation noted above).  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.

For the CPUs, we recorded compensation expense of $4.1 million in 2009 and $4.1 million in 2008.  At December 31, 2009, there was $12.3 million of total unrecognized compensation cost related to the unvested CPUs remaining.  This amount is expected to be recognized over the next three years.

Founders Plan Awards

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.

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 and second awards became the obligations of our predecessor.  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 $10.59, $7.05 and $28.90 were used in the model for the periods ending December 31, 2009, 2008 and 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 credits of approximately $0.4 million and $0.3 million and a charge of $2.7 million of compensation expense under the plan for the years ended December 31, 2009, December 31, 2008 and December 31, 2007, respectively.  The aggregate value of the vested and unvested unit appreciation rights was zero at December 31, 2009.

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

	December 31,
	2009					2008					2007
	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		122,644		$	18.50		214,107		$	18.50		305,570		$	18.50
Exercised		-			-		(91,463	)		18.50		(91,463	)		18.50
Cancelled (a)		(101,856	)		18.50		-			-		-			-
Outstanding, end of period		20,788		$	18.50		122,644		$	18.50		214,107		$	18.50
Exercisable, end of period		-		$	-		-		$	-		-		$	-

(a) These units expired out of the money and the remaining units outstanding at year end will vest one half in 2010 and one half in 2011.

BreitBurn Management LTIP and the Partnership LTIP

BreitBurn Management LTIP

In September 2005, certain employees other than the Co-Chief Executive Officers 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 the 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 the third year after grant and the 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 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.

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.

       We recognized no expense for the year ended December 31, 2009, $0.9 million and $0.4 million of compensation expense for the years ended December 31, 2008 and, December 31, 2007, respectively.  The following table summarizes information about the restricted/performance units granted in 2005 and 2006:

- 36 - -

	PVE indexed units
	December 31,
	2008					2007
				Weighted					Weighted
	Number of			Average		Number of			Average
	Units			Grant Price		Units			Grant Price
Outstanding , beginning of period		267,702		$	10.77		318,389		$	10.82
Granted		-			-		-			-
Exercised		(267,351	)		10.77		(36,203	)		10.87
Cancelled		(351	)		10.73		(14,484	)		11.53
Outstanding, end of period		-		$	10.77		267,702		$	10.77
Exercisable, end of period		-		$	-		-		$	-

Partnership LTIP
 

Under our LTIP, Partnership-indexed restricted units (RTUs) and/or performance units (PTUs) were granted in 2007 certain individuals other than the Co-Chief Executive Officers.  RTUs 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.  In general, cash payments equal to the value of the underlying notional units were made on the anniversary dates of the RTUs.  PTUs vest three years from the end of third year after grant 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.  PTU payouts are further determined by a performance multiplier which 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 a selected peer group of companies.  The multiplier is determined by comparing our total return to the returns of 49 companies in the Alerian MLP Index.  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 credits of $0.5 million and $1.4 million and a charge of $2.1 million of compensation expense for the years ended December 31, 2009, December 31, 2008 and December 31, 2007, respectively.  Our share of the aggregate liability or the remaining unvested value under the BreitBurn Management LTIP was less than $0.1 million at December 31, 2009.

 Due to the suspension of our distribution in April 2009, the multiplier as calculated at the end of 2009 was below that required to generate a payout.  As a result, all outstanding PTUs vested and expired January 1, 2010 and no payout was made.

- 37 - -

The following table summarizes information about the restricted/performance units granted in 2007.  Market prices of $10.59, $7.05 and $28.90 were used in the model for the periods ending December 31, 2009 December 31, 2008 and December 31, 2007, respectively.

	PTUs and RTUs
	December 31,
	2009					2008					2007
				Weighted					Weighted					Weighted
	Number of			Average		Number of			Average		Number of			Average
	Units			Grant Price		Units			Grant Price		Units			Grant Price
Outstanding , beginning of period		86,992		$	24.10		108,717		$	23.64		20,483		$	21.67
Granted		-			-		-			-		91,834			24.10
Exercised		(6,357	)		24.10		(20,645	)		20.39		(98	)		24.10
Cancelled		(75,034	)		24.10		(1,080	)		24.10		(3,502	)		24.10
Outstanding, end of period		5,601		$	24.10		86,992		$	24.10		108,717		$	23.64
Exercisable, end of period		-		$	-		-		$	-		-		$	-

Unit Appreciation Right Plan Awards

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’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.  All of the outstanding UAR units at December 31, 2008 expired during 2009.

The total compensation expense for the UAR plan is allocated between us and our predecessor.  Our share of expense was an immaterial amount in 2009 and 2008.  We recorded $0.4 million in expense for 2007 under the UAR Plan.

Director Restricted Phantom 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 $0.4 million in 2009, $0.1 million in 2008 and $0.5 million in 2007.  As of December 31, 2009, there was $0.5 million of total unrecognized compensation cost for the unvested Director Performance Units and such cost is expected to be recognized over the next two years.  The total fair value of units vested in 2009 was $0.2 million.

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The following table summarizes information about the Director Restricted Phantom Units:

	December 31,
	2009					2008					2007
	Number of			Weighted		Number of			Weighted		Number of		Weighted
	Performance			Average		Performance			Average		Performance		Average
	Units			Fair Value *		Units			Fair Value *		Units		Fair Value *
Outstanding , beginning of period		35,429		$	22.60		37,473		$	21.11		20,026	$	18.50
Granted		56,736			9.20		20,146			25.02		17,447		24.10
Exercised		(10,810	)		18.50		(22,190	)		22.28		-		-
Outstanding, end of period		81,355		$	13.80		35,429		$	22.60		37,473	$	21.11
Exercisable, end of period		-		$	-		-		$	-		-	$	-

* At grant date
 

18.  Commitments and Contingencies

Lease Rental Obligations

We had operating leases for office space and other property and equipment having initial or remaining non-cancelable lease terms in excess of one year.  Our future minimum rental payments for operating leases at December 31, 2009 are presented below:

	Payments Due by Year
Thousands of dollars	2010		2011		2012		2013		2014		after 2014		Total
Operating leases	$	2,838	$	2,636	$	2,174	$	814	$	465	$	543	$	9,470

Net rental payments made under non-cancelable operating leases were $2.6 million, $2.8 million and $0.4 million in 2009, 2008 and 2007, respectively.  As of December 31, 2009, we had no purchase obligations for the next five years.
 

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, 2009, we had $10.6 million in surety bonds and $0.3 million in letters of credit outstanding.  At December 31, 2008, we had $10.1 million in surety bonds and $0.3 million in letters of credit outstanding.
 

Legal Proceedings
 

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 the Quicksilver lawsuit, which was settled in February 2010 (see Note 21).  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.

We have no independent assets or operations other than those of our subsidiaries.  BOLP or BOGP may guarantee debt securities that may be issued by us and BreitBurn Finance Corporation, our wholly owned subsidiary.  See Note 1 for a description of BreitBurn Finance Corporation.  The guarantees will be full and unconditional and joint and several.

- 39 - -

19.  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, through November 30, 2007, covered substantially all of its employees who had completed at least three months of service and, starting December 1, 2007, covers substantially all of its employees on the first day of the month following the month of hire.  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, 2009, the matching contribution paid by us was $1.0 million.  For the year ended December 31, 2008 and December 31, 2007, the matching contributions paid by us were $0.4 million and $0.1 million, respectively.

20.  Significant Customers
 

We sell oil, natural gas and natural gas liquids primarily to large domestic refiners.  For the year ended December 31, 2009, purchasers that accounted for ten percent or more of our net sales were ConocoPhillips which accounted for 30 percent of net sales, Marathon Oil Company which accounted for 16 percent of net sales, and Plains Marketing & Transportation LLC which accounted for 11 percent of net sales.  For the years ended December 31, 2008 and 2007, ConocoPhillips purchased approximately 25 percent and 20 percent of our production, respectively, and Marathon Oil Company purchased approximately 13 percent and 24 percent of our production, respectively.  Plains Marketing & Transportation LLC accounted for less than ten percent of our total production for the years ended December 31, 2008 and 2007, respectively.

21.  Subsequent Events

In January 2010, 496,194 Common Units were issued to employees under our 2006 Long-Term Incentive Plan and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2007 and vested in January 2010.

On February 19, 2010, we entered into a crude oil fixed price swap contract for 500 Bbl/d for 2013 at a price of $84.55.  On March 3, 2010, we entered into a crude oil fixed price swap contract for 400 Bbl/d for 2011 through 2013 at $84.30 per Bbl.  On March 10, 2010, we entered into a crude oil fixed price swap contract for 600 Bbl/d for 2011 through 2013 at $86.35 per Bbl.

In February 2010, we and Quicksilver agreed to settle all claims with respect to the litigation filed by Quicksilver.  The terms of the Settlement which we expect to be implemented in April 2010 include a monetary settlement to Quicksilver, which we expect will be paid by insurance.  See Note 8 for a discussion of the monetary settlement.  In addition, Mr. Halbert S. Washburn and Mr. Randall H. Breitenbach will resign from the Board of Directors and the Board will appoint two new directors designated by Quicksilver, one of whom will qualify as an independent director and the other will be a current independent board member now serving on Quicksilver’s board of directors, provided that such director not be a member of Quicksilver’s management. 

- 40 - -

Condensed Consolidating Financial Information

BreitBurn Energy Partners L.P. (the “Partnership,” “we,” “us” or “our”), BreitBurn Finance Corporation, a Delaware corporation (together with the Partnership, the “Issuers”), and certain of our 100% owned subsidiaries, as guarantors (the “Guarantors”), entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers as defined therein, pursuant to which the Issuers agreed to sell $305 million in aggregate principal amount of the Issuers’ 8.625% Senior Notes due 2020 (the “Notes”).  The Notes were offered and sold in private placements to qualified institutional buyers in the United States in reliance on Rule 144A under the Securities Act of 1933, as amended.

In connection with the issuance of the Notes, we entered into a registration rights agreement requiring us to file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) with respect to an offer to exchange the Notes for substantially identical notes that are registered under the Securities Act of 1933.   Certain, but not all, of our subsidiaries have issued full, unconditional and joint and several guarantees of the Notes, will guarantee the exchange offer notes and may guarantee future issuances of debt securities, in accordance with Rule 3-10(d) of Regulation S-X.

We are, therefore, presenting condensed consolidating financial information as of December 31, 2009 and 2008, and for the three years ended December 31, 2009 on a parent/co-issuer, guarantor subsidiaries, non-guarantor subsidiary, eliminating entries, and consolidated basis. Eliminating entries presented are necessary to combine the parent/co-issuer, the guarantor subsidiaries and the non-guarantor subsidiary. For purposes of the following tables, we and BreitBurn Finance Corporation are referred to as “Parent/Co-Issuer” and the “Guarantor Subsidiaries” are all our subsidiaries other than BreitBurn Energy Partners I, L.P. We hold a 99 percent limited partner interest in BreitBurn Energy Partners I, L.P. (the “Non-Guarantor Subsidiary”).

BreitBurn Finance Corporation, our wholly-owned subsidiary, was organized for the sole purpose of being a co-issuer of certain of our indebtedness, including the Notes. BreitBurn Finance Corporation has no operations and no revenue other than as may be incidental to its activities as co-issuer of our indebtedness.

Condensed Consolidating Statements of Operations

	Year Ended December 31, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	-		$	236,266		$	18,651		$	-		$	254,917
Losses on commodity derivative instruments, net		-			(51,437	)		-			-			(51,437	)
Other revenue, net		-			1,382			-			-			1,382
Total revenues and other income items		-			186,211			18,651			-			204,862
Operating costs and expenses:
Operating costs		11			129,542			8,945			-			138,498
Depletion, depreciation and amortization		387			104,274			2,182			-			106,843
General and administrative expenses		482			35,890			(5	)		-			36,367
Loss on sale of assets		-			5,965			-			-			5,965
Total operating costs and expenses		880			275,671			11,122			-			287,673
Operating income (loss)		(880	)		(89,460	)		7,529			-			(82,811	)
Interest and other financing costs, net		-			18,827			-			-			18,827
Loss on interest rate swaps		-			7,246			-			-			7,246
Other income, net		-			(98	)		(1	)		-			(99	)
Income (loss) before taxes		(880	)		(115,435	)		7,530			-			(108,785	)
Income tax expense (benefit)		61			(1,590	)		1			-			(1,528	)
Equity in earnings (losses) of subsidiaries		(106,391	)		7,454			-			98,937			-
Net income (losses)		(107,332	)		(106,391	)		7,529			98,937			(107,257	)
Less: Net income attributable to noncontrolling interest		-			-			-			(33	)		(33	)
Net income (losses) attributable to the partnership		(107,332	)		(106,391	)		7,529			98,904			(107,290	)

- 41 - -

Condensed Consolidating Statements of Operations
 

	Year Ended December 31, 2008
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	-		$	437,883		$	29,498		$	-		$	467,381
Gains on commodity derivative instruments, net		-			332,102			-			-			332,102
Other revenue, net		-			3,439			(519	)		-			2,920
Total revenues and other income items		-			773,424			28,979			-			802,403
Operating costs and expenses:
Operating costs		-			152,673			9,332			-			162,005
Depletion, depreciation and amortization		211			177,641			2,081			-			179,933
General and administrative expenses		767			30,362			(18	)		-			31,111
Total operating costs and expenses		978			360,676			11,395			-			373,049
Operating income (loss)		(978	)		412,748			17,584			-			429,354
Interest and other financing costs, net		-			29,147			-			-			29,147
Loss on interest rate swaps		-			20,035			-			-			20,035
Other income, net		-			(100	)		(91	)		-			(191	)
Income (loss) before taxes		(978	)		363,666			17,675			-			380,363
Income tax expense		1			1,936			2			-			1,939
Equity in earnings of subsidiaries		379,226			17,496			-			(396,722	)		-
Net income		378,247			379,226			17,673			(396,722	)		378,424
Less: Net income attributable to noncontrolling interest		-			-			-			(188	)		(188	)
Net income attributable to the partnership		378,247			379,226			17,673			(396,910	)		378,236
General Partner's interest in net loss		(2,019	)		-			-			-			(2,019	)
Net income attributable to limited partners	$	380,266		$	379,226		$	17,673		$	(396,910	)	$	380,255

- 42 - -

Condensed Consolidating Statements of Operations

	Year Ended December 31, 2007
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	-		$	170,086		$	14,286		$	-		$	184,372
Losses on commodity derivative instruments, net		-			(99,952	)		(10,466	)		-			(110,418	)
Other revenue, net		-			1,375			(338	)		-			1,037
Total revenues and other income items		-			71,509			3,482			-			74,991
Operating costs and expenses:
Operating costs		-			69,242			4,747			-			73,989
Depletion, depreciation and amortization		-			27,484			1,938			-			29,422
General and administrative expenses		3			26,892			33			-			26,928
Total operating costs and expenses		3			123,618			6,718			-			130,339
Operating loss		(3	)		(52,109	)		(3,236	)		-			(55,348	)
Interest and other financing costs, net		-			6,255			3			-			6,258
Other (income) expense, net		24			(55	)		(80	)		-			(111	)
Loss before taxes		(27	)		(58,309	)		(3,159	)		-			(61,495	)
Income tax expense		-			(1,229	)		-			-			(1,229	)
Equity in losses of subsidiaries		(60,207	)		(3,127	)		-			63,334			-
Net loss		(60,234	)		(60,207	)		(3,159	)		63,334			(60,266	)
Less: Net income attributable to noncontrolling interest		-			-			-			(91	)		(91	)
Net loss attributable to the partnership		(60,234	)		(60,207	)		(3,159	)		63,243			(60,357	)
General Partner's interest in net loss		(672	)		-			-			-			(672	)
Net loss attributable to limited partners	$	(59,562	)	$	(60,207	)	$	(3,159	)	$	63,243		$	(59,685	)

- 43 - -

Condensed Consolidating Balance Sheets

	As of December 31, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
ASSETS
Current assets:
Cash	$	149		$	4,917		$	700		$	-		$	5,766
Accounts and other receivables, net		13,000			50,196			2,013			-			65,209
Derivative instruments		-			57,133			-			-			57,133
Related party receivables		-			2,127			-			-			2,127
Inventory		-			5,823			-			-			5,823
Prepaid expenses		-			5,888			-			-			5,888
Intangibles		-			495			-			-			495
Total current assets		13,149			126,579			2,713			-			142,441
Investments in subsidiaries		1,201,492			47,074			-			(1,248,566	)		-
Intercompany receivables (payables)		18,743			(32,209	)		13,466			-			-
Equity investments		-			8,150			-			-			8,150
Property, plant and equipment
Oil and gas properties		8,467			2,005,619			44,882			-			2,058,968
Non-oil and gas assets		-			7,717			-			-			7,717
		8,467			2,013,336			44,882			-			2,066,685
Accumulated depletion and depreciation		(597	)		(315,567	)		(9,432	)		-			(325,596	)
Net property, plant and equipment		7,870			1,697,769			35,450			-			1,741,089
Other long-term assets
Derivative instruments		-			74,759			-			-			74,759
Other long-term assets		74			4,459			57			-			4,590
Total assets	$	1,241,328		$	1,926,581		$	51,686		$	(1,248,566	)	$	1,971,029
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable	$	2		$	20,386		$	926		$	-		$	21,314
Derivative instruments		-			20,057			-			-			20,057
Related party payables		13,000			-			-			-			13,000
Revenue and royalties payable		-			16,888			1,336			-			18,224
Salaries and wages payable		-			10,244			-			-			10,244
Accrued liabilities		-			8,531			520			-			9,051
Total current liabilities		13,002			76,106			2,782			-			91,890
Long-term debt		-			559,000			-			-			559,000
Deferred income taxes		-			2,492			-			-			2,492
Asset retirement obligation		-			35,280			1,355			-			36,635
Derivative instruments		-			50,109			-			-			50,109
Other long-term liabilities		-			2,102			-			-			2,102
Total  liabilities		13,002			725,089			4,137			-			742,228
Equity:
Partners' equity		1,228,326			1,201,492			47,549			(1,248,994	)		1,228,373
Noncontrolling interest		-			-			-			428			428
Total equity		1,228,326			1,201,492			47,549			(1,248,566	)		1,228,801
Total liabilities and equity	$	1,241,328		$	1,926,581		$	51,686		$	(1,248,566	)	$	1,971,029

- 44 - -

Condensed Consolidating Balance Sheets

	As of December 31, 2008
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated
ASSETS
Current assets:
Cash	$	2		$	731		$	1,813		$	-		$	2,546
Accounts receivable		-			46,606			615			-			47,221
Derivative instruments		-			76,224			-			-			76,224
Related party receivables		-			5,084			-			-			5,084
Inventory		-			1,250			-			-			1,250
Prepaid expenses		-			5,220			80			-			5,300
Intangibles		-			2,771			-			-			2,771
Other current assets		-			95			75			-			170
Total current assets		2			137,981			2,583			-			140,566
Investments in subsidiaries		1,347,910			40,014			-			(1,387,924	)		-
Intercompany receivables (payables)		(3,215	)		(1,379	)		4,594			-			-
Equity investments		-			9,452			-			-			9,452
Property, plant and equipment
Oil and gas properties		8,467			2,004,825			44,239			-			2,057,531
Non-oil and gas assets		-			7,806			-			-			7,806
		8,467			2,012,631			44,239			-			2,065,337
Accumulated depletion and depreciation		(211	)		(217,420	)		(7,365	)		-			(224,996	)
Net property, plant and equipment		8,256			1,795,211			36,874			-			1,840,341
Other long-term assets
Intangibles		-			495			-			-			495
Derivative instruments		-			219,003			-			-			219,003
Other long-term assets		75			6,902			-			-			6,977
Total assets	$	1,353,028		$	2,207,679		$	44,051		$	(1,387,924	)	$	2,216,834
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable	$	-		$	27,462		$	840		$	-		$	28,302
Book overdraft		-			9,871			-			-			9,871
Derivative instruments		-			10,192			-			-			10,192
Revenue and royalties payable		-			19,916			168			-			20,084
Salaries and wages payable		-			6,249			-			-			6,249
Accrued liabilities		1			3,840			1,451			-			5,292
Total current liabilities		1			77,530			2,459			-			79,990
Long-term debt		-			736,000			-			-			736,000
Deferred income taxes		-			4,282			-			-			4,282
Asset retirement obligation		-			28,912			1,174			-			30,086
Derivative instruments		-			10,058			-			-			10,058
Other long-term liabilities		-			2,987			-			-			2,987
Total  liabilities		1			859,769			3,633			-			863,403
Equity:
Partners' equity		1,353,027			1,347,910			40,418			(1,388,463	)		1,352,892
Noncontrolling interest		-			-			-			539			539
Total equity		1,353,027			1,347,910			40,418			(1,387,924	)		1,353,431
Total liabilities and partners' equity	$	1,353,028		$	2,207,679		$	44,051		$	(1,387,924	)	$	2,216,834

- 45 - -

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(107,332	)	$	(106,391	)	$	7,529		$	98,937		$	(107,257	)
Adjustments to reconcile net income (loss) to cash flow from operating activities:
Depletion, depreciation and amortization		387			104,274			2,182			-			106,843
Unit-based compensation expense		-			12,661			-			-			12,661
Unrealized losses on derivative instruments		-			213,251			-			-			213,251
Income from equity affiliates, net		-			1,302			-			-			1,302
Equity in (earnings) losses of subsidiaries		106,391			(7,454	)		-			(98,937	)		-
Deferred income tax		-			(1,790	)		-			-			(1,790	)
Amortization of intangibles		-			2,771			-			-			2,771
Loss on sale of assets		-			5,965			-			-			5,965
Other		-			3,294			-			-			3,294
Changes in net assets and liabilities:					-
Accounts receivable and other assets		-			(5,013	)		(1,300	)		-			(6,313	)
Inventory		-			(4,573	)		-			-			(4,573	)
Net change in related party receivables and payables		-			2,957			-			-			2,957
Accounts payable and other liabilities		-			(5,078	)		325			-			(4,753	)
Net cash provided (used) by operating activities		(554	)		216,176			8,736			-			224,358
Cash flows from investing activities
Capital expenditures		-			(28,828	)		(685	)		-			(29,513	)
Proceeds from sale of assets, net		-			23,284			-			-			23,284
Net cash used by investing activities		-			(5,544	)		(685	)		-			(6,229	)
Cash flows from financing activities
Distributions		(28,038	)		-			-			-			(28,038	)
Proceeds from the issuance of long-term debt		-			249,975			-			-			249,975
Repayments of long-term debt		-			(426,975	)		-			-			(426,975	)
Book overdraft		-			(9,871	)		-			-			(9,871	)
Intercompany activity		28,739			(19,575	)		(9,164	)		-			-
Net cash provided (used) by financing activities		701			(206,446	)		(9,164	)		-			(214,909	)
Increase (decrease) in cash		147			4,186			(1,113	)		-			3,220
Cash beginning of period		2			731			1,813			-			2,546
Cash end of period	$	149		$	4,917		$	700		$	-		$	5,766

- 46 - -

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2008
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
Cash flows from operating activities
Net income	$	378,247		$	379,226		$	17,673		$	(396,722	)	$	378,424
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation and amortization		211			177,641			2,081			-			179,933
Unit-based compensation expense		-			6,907			-			-			6,907
Unrealized gains on derivative instruments		-			(370,734	)		-			-			(370,734	)
Income from equity affiliates, net		-			1,198			-			-			1,198
Equity in earnings of subsidiaries		(379,226	)		(17,496	)		-			396,722			-
Deferred income tax		-			1,207			-			-			1,207
Amortization of intangibles		-			3,131			-			-			3,131
Other		-			2,643			-			-			2,643
Changes in net assets and liabilities:					-
Accounts receivable and other assets		(71	)		(547	)		876			-			258
Inventory		-			4,454			-			-			4,454
Net change in related party receivables and payables		-			32,688			-			-			32,688
Accounts payable and other liabilities		1			(13,663	)		249			-			(13,413	)
Net cash provided (used) by operating activities		(838	)		206,655			20,879			-			226,696
Cash flows from investing activities
Capital expenditures		-			(130,002	)		(1,080	)		-			(131,082	)
Property acquisitions		(8,467	)		(1,490	)		-			-			(9,957	)
Net cash used by investing activities		(8,467	)		(131,492	)		(1,080	)		-			(141,039	)
Cash flows from financing activities
Purchase of common units		(336,216	)		-			-			-			(336,216	)
Distributions		(121,349	)		-			-			-			(121,349	)
Proceeds from the issuance of long-term debt		-			803,002			-			-			803,002
Repayments of long-term debt		-			(437,402	)		-			-			(437,402	)
Book overdraft		-			7,951			-			-			7,951
Long-term debt issuance costs		-			(5,026	)		-			-			(5,026	)
Intercompany activity		466,870			(443,157	)		(23,713	)		-			-
Net cash provided (used) by financing activities		9,305			(74,632	)		(23,713	)		-			(89,040	)
Increase (decrease) in cash		-			531			(3,914	)		-			(3,383	)
Cash beginning of period		2			200			5,727			-			5,929
Cash end of period	$	2		$	731		$	1,813		$	-		$	2,546

- 47 - -

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2007
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
Cash flows from operating activities
Net loss	$	(60,234	)	$	(60,207	)	$	(3,159	)	$	63,334		$	(60,266	)
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		-			27,484			1,938			-			29,422
Deferred stock based compensation		-			12,999			-			-			12,999
Unrealized losses on derivative instruments		-			103,862			-			-			103,862
Income from equity affiliates, net		-			(28	)		-			-			(28	)
Equity in losses of subsidiaries		60,207			3,127			-			(63,334	)		-
Deferred income tax		-			(1,229	)		-			-			(1,229	)
Amortization of intangibles		-			2,174			-			-			2,174
Other		-			2,182			-			-			2,182
Changes in net assets and liablities:
Accounts receivable and other assets		-			(27,597	)		2,884			-			(24,713	)
Inventory		-			4,829			-			-			4,829
Net change in related party receivables and payables		-			(39,202	)		-			-			(39,202	)
Accounts payable and other liabilities		1			31,728			(1,657	)		-			30,072
Net cash provided (used) by operating activities		(26	)		60,122			6			-			60,102
Cash flows from investing activities
Capital expenditures		-			(22,835	)		(714	)		-			(23,549	)
Property acquisitions		-			(996,561	)		-			-			(996,561	)
Net cash used by investing activities		-			(1,019,396	)		(714	)		-			(1,020,110	)
Cash flows from financing activities
Issuance of common units, net of discount		663,338			-			-			-			663,338
Repayments of initial distributions by predecessor members		581			-			-			-			581
Distributions		(60,497	)		-			-			-			(60,497	)
Proceeds from the issuance of long-term debt		-			574,700			-			-			574,700
Repayments of long-term debt		-			(205,800	)		-			-			(205,800	)
Book overdraft		-			(116	)		-			-			(116	)
Long-term debt issuance costs		-			(6,362	)		-			-			(6,362	)
Intercompany activity		(603,397	)		596,516			6,881			-			-
Net cash provided by financing activities		25			958,938			6,881			-			965,844
Increase (decrease) in cash		(1	)		(336	)		6,173			-			5,836
Cash beginning of period		3			536			(446	)		-			93
Cash end of period	$	2		$	200		$	5,727		$	-		$	5,929

- 48 - -

EX-99.2

Exhibit 99.2

See Item 8.01 of the accompanying Current Report on Form 8-K for an explanation regarding the following disclosure. The following information replaces the Part I—Item 1 “—Financial Statements,” previously filed in the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 for BreitBurn Energy Partners L.P. (the “Q3 2010 10-Q”). Except as set forth in this Exhibit 99.2, the Q3 2010 10-Q has not been otherwise modified or updated.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars, except per unit amounts	2010			2009			2010			2009
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	77,055		$	62,674		$	239,603		$	180,189
Gains (losses) on commodity derivative instruments, net (note 10)		(7,973	)		12,719			95,742			(14,520	)
Other revenue, net		719			261			1,838			930
Total revenues and other income items		69,801			75,654			337,183			166,599
Operating costs and expenses
Operating costs		33,207			33,888			108,429			100,273
Depletion, depreciation and amortization		23,636			24,130			69,599			81,393
General and administrative expenses		12,740			9,318			33,957			27,265
(Gain) loss on sale of assets		(359	)		5,470			137			5,470
Total operating costs and expenses		69,224			72,806			212,122			214,401
Operating income (loss)		577			2,848			125,061			(47,802	)
Interest and other financing costs, net		5,147			4,549			13,762			14,682
Losses on interest rate swaps (note 10)		1,629			3,792			5,290			5,557
Other income, net		(3	)		(84	)		(7	)		(124	)
Income (loss) before taxes		(6,196	)		(5,409	)		106,016			(67,917	)
Income tax expense (benefit) (note 3)		(470	)		(13	)		235			(354	)
Net income (loss)		(5,726	)		(5,396	)		105,781			(67,563	)
Less: Net income attributable to noncontrolling interest		(28	)		(12	)		(127	)		(14	)
Net income (loss) attributable to the partnership	$	(5,754	)	$	(5,408	)	$	105,654		$	(67,577	)
Basic net income (loss) per unit (note 8)	$	(0.11	)	$	(0.10	)	$	1.86		$	(1.28	)
Diluted net income (loss) per unit (note 8)	$	(0.11	)	$	(0.10	)	$	1.86		$	(1.28	)

See accompanying notes to consolidated financial statements.

-1-

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Balance Sheets

	September 30,			December 31,
Thousands of dollars, except units outstanding	2010			2009
ASSETS
Current assets
Cash	$	3,409		$	5,766
Accounts and other receivables, net		52,248			65,209
Derivative instruments (note 10)		75,534			57,133
Related party receivables (note 4)		2,062			2,127
Inventory (note 5)		4,621			5,823
Prepaid expenses		7,235			5,888
Intangibles		124			495
Total current assets		145,233			142,441
Equity investments		7,857			8,150
Property, plant and equipment
Property, plant and equipment		2,121,173			2,066,685
Accumulated depletion and depreciation		(392,917	)		(325,596	)
Net property, plant and equipment		1,728,256			1,741,089
Other long-term assets
Derivative instruments (note 10)		78,347			74,759
Other long-term assets		11,909			4,590
Total assets	$	1,971,602		$	1,971,029
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	25,345		$	21,314
Derivative instruments (note 10)		23,418			20,057
Related party payables (note 4)		-			13,000
Revenue and royalties payable		16,830			18,224
Salaries and wages payable		9,272			10,244
Accrued liabilities		10,170			9,051
Total current liabilities		85,035			91,890
Long-term debt (note 6)		516,000			559,000
Deferred income taxes (note 3)		2,680			2,492
Asset retirement obligation (note 7)		37,261			36,635
Derivative instruments (note 10)		22,672			50,109
Other long-term liabilities		2,102			2,102
Total liabilities		665,750			742,228
Equity
Partners' equity (note 8)		1,305,394			1,228,373
Noncontrolling interest (note 9)		458			428
Total equity		1,305,852			1,228,801
Total liabilities and equity	$	1,971,602		$	1,971,029
Common Units outstanding (in thousands)		53,308			52,784

See accompanying notes to consolidated financial statements.

-2-

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

	Nine Months Ended
	September 30,
Thousands of dollars	2010			2009
Cash flows from operating activities
Net income (loss)	$	105,781		$	(67,563	)
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		69,599			81,393
Unit based compensation expense		15,386			9,736
Unrealized (gains) losses on derivative instruments		(46,065	)		160,319
Income from equity affiliates, net		293			766
Deferred income tax expense (benefit)		188			(897	)
Amortization of intangibles		371			2,334
Loss on sale of assets		137			5,470
Other		2,850			2,472
Changes in net assets and liabilities
Accounts receivable and other assets		13,315			3,590
Inventory		1,202			(3,710	)
Net change in related party receivables and payables		(12,935	)		340
Accounts payable and other liabilities		(6,822	)		(10,279	)
Net cash provided by operating activities		143,300			183,971
Cash flows from investing activities
Capital expenditures		(46,418	)		(18,603	)
Proceeds from sale of assets		225			23,034
Property acquisitions		(1,550	)		-
Net cash provided (used) by investing activities		(47,743	)		4,431
Cash flows from financing activities
Distributions		(43,043	)		(28,038	)
Proceeds from long-term debt		683,500			218,475
Repayments of long-term debt		(726,500	)		(369,475	)
Book overdraft		-			(9,711	)
Long-term debt issuance costs		(11,871	)		-
Net cash used by financing activities		(97,914	)		(188,749	)
Decrease in cash		(2,357	)		(347	)
Cash beginning of period		5,766			2,546
Cash end of period	$	3,409		$	2,199

See accompanying notes to consolidated financial statements.

-3-

Notes to Consolidated Financial Statements

1. Organization and Basis of Presentation

The accompanying unaudited consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the year ended December 31, 2009 (the “Annual Report”). The financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation of our financial position at September 30, 2010, our operating results for the three months and nine months ended September 30, 2010 and 2009, and our cash flows for the nine months ended September 30, 2010 and 2009, have been included. Operating results for the three months and nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010. The consolidated balance sheet at December 31, 2009 has been derived from the audited consolidated financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. For further information, refer to the consolidated financial statements and footnotes thereto included in our Annual Report.

We follow the successful efforts method of accounting for oil and gas activities. Depletion, depreciation and amortization of proved oil and gas properties is computed using the units-of-production method, net of any estimated residual salvage values.

As of December 31, 2009, Quicksilver Resources Inc. (“Quicksilver”) held approximately 21.3 million of our common units (“Common Units”), representing approximately 40 percent of our outstanding Common Units. On May 11, 2010, Quicksilver partially paid for an acquisition of assets from Marshall R. Young Oil Co. (“Young”) with 3.6 million Common Units. During the period from June 7, 2010 through September 23, 2010, Young sold all of these Common Units. In September 2010, Quicksilver sold 1.4 million Common Units, resulting in Quicksilver’s ownership being reduced to 16.3 million Common Units, and as of September 30, 2010, with that sale, Quicksilver owned approximately 31 percent of our Common Units.

2. Accounting Pronouncements

Effective January 1, 2010, we adopted guidance issued by the Financial Accounting Standards Board (“FASB”) in June 2009 related to the consolidation of variable interest entities with no impact on our financial position, results of operations or cash flows.

ASU 2010-06 “Fair Value Measurements and Disclosures.” In January 2010, the FASB issued ASU 2010-06 to make certain amendments to Subtopic 820-10 that require two additional disclosures and clarify two existing disclosures. The new disclosures require details of significant transfers in and out of level 1 and level 2 measurements and the reasons for the transfers, and a gross presentation of activity within the level 3 roll forward that presents separately information about purchases, sales, issuances and settlements. The ASU clarifies the existing disclosures with regard to the level of disaggregation of fair value measurements by class of assets and liabilities rather than major category where the reporting entities would need to apply judgment to determine the appropriate classes of other assets and liabilities. The second clarification relates to disclosures of valuation techniques and inputs for recurring and non recurring fair value measurements using significant other observable inputs and significant unobservable inputs for level 2 and level 3 measurements, respectively. ASU 2010-06 (ASC 820-10) is prospectively effective for financial statements issued for interim or annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010 and for interim periods within those fiscal years. We adopted ASU 2010-06, effective January 1, 2010. See Note 10 for the disclosures required by ASU 2010-06.

-4-

3. Income Taxes

Our deferred income tax liability was $2.7 million and $2.5 million at September 30, 2010 and December 31, 2009, respectively. The following table presents our income tax expense/benefit for the three months and nine months ended September 30, 2010 and 2009, respectively:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars	2010			2009			2010			2009
Federal current tax expense	$	77		$	407		$	224		$	432
Deferred federal tax expense (benefit) (a)		(434	)		(276	)		188			(946	)
State income tax expense (benefit) (b)		(113	)		(144	)		(177	)		160
Total income tax expense (benefit)	$	(470	)	$	(13	)	$	235		$	(354	)

(a) Related to Phoenix Production Company, a tax-paying corporation and our wholly-owned subsidiary.

(b) Related to various forms of state taxes imposed on gross receipts, profit margin or net income in the states where we have operations.

4. Related Party Transactions

BreitBurn Management Company, LLC (“BreitBurn Management”), our wholly-owned subsidiary, 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 also provides administrative services to BreitBurn Energy Company L.P. (“BEC”), our predecessor, under an administrative services agreement, in exchange for a monthly fee for indirect expenses and reimbursement for all direct expenses including incentive compensation plan costs and direct payroll and administrative costs related to BEC properties and operations. In 2010, the monthly fee paid by BEC for indirect expenses is approximately $456,000.

At September 30, 2010 and December 31, 2009, we had current receivables of $1.5 million and $1.4 million, respectively, 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. During the three months and nine months ended September 30, 2010, the monthly charges to BEC for indirect expenses totaled $1.2 million and $4.0 million, respectively, and charges for direct expenses including incentive compensation plan costs, direct payroll and administrative costs totaled $1.1 million and $5.0 million, respectively. During the three months and nine months ended September 30, 2009, the monthly charges to BEC for indirect expenses totaled $1.5 million and $4.5 million, respectively, and charges for direct expenses including incentive compensation plan costs, direct payroll and administrative costs totaled $1.2 million and $3.5 million, respectively. For the three months and nine months ended September 30, 2010, total oil and gas sales made by BEC on our behalf were approximately $0.4 million and $1.3 million, respectively. For the three months and nine months ended September 30, 2009, total oil and gas sales made by BEC on our behalf were approximately $0.4 million and $0.9 million, respectively.

At September 30, 2010 and December 31, 2009, we had receivables of $0.3 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

Quicksilver buys natural gas from us in Michigan. For the three months and nine months ended September 30, 2010, total net gas sales to Quicksilver were approximately $0.8 million and $2.6 million, respectively. For the three months and nine months ended September 30, 2009, total net gas sales to Quicksilver were approximately $0.5 million and $2.1 million, respectively. At September 30, 2010 and December 31, 2009, the related receivable was $0.3 million and $0.4 million, respectively.

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On October 31, 2008, Quicksilver instituted a lawsuit (the “Litigation”) against us and certain of our subsidiaries and directors in the 48th District Court in Tarrant County, Texas (the “Court”). In February 2010, we agreed to settle all claims with respect to the Litigation (the “Original Settlement”). A final settlement agreement (the “Settlement Agreement”), which superseded the Original Settlement, was executed in April 2010. Pursuant to the Settlement Agreement, the parties agreed to dismiss all pending claims before the Court and mutually released each party, its affiliates, agents, officers, directors and attorneys from any and all claims arising from the subject matter of the Litigation. At December 31, 2009, we had a $13.0 million payable to Quicksilver in connection with the monetary portion of the settlement, which was paid in April 2010 after the Settlement Agreement was executed. On April 6, 2010, an order dismissing all claims in the Litigation was entered by the Court. In June 2010, we received $3 million from our insurers as partial reimbursement. While discussions with our insurers are continuing and we may be required to invoke our legal remedies to obtain payment, we expect to receive reimbursement for the full amount paid to Quicksilver and all or substantially all related fees and costs.

5. Inventory

Our crude oil inventory from our Florida operations at September 30, 2010 and December 31, 2009 was $4.6 million and $5.8 million, respectively. In the nine months ended September 30, 2010, we sold 550 gross MBbls and produced 552 gross MBbls of crude oil from our Florida operations. 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. 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.

6. Long-Term Debt

On November 1, 2007, 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 “First Amended and Restated Credit Agreement”). On June 17, 2008, we and our wholly owned subsidiaries entered into Amendment No. 1 to the Amended and Restated Credit Agreement.

On May 7, 2010, BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into the Second Amended and Restated Credit Agreement, a four-year, $1.5 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the “Second Amended and Restated Credit Agreement”). The Second Amended and Restated Credit Agreement increased our borrowing base to $735 million from $732 million and will mature on May 7, 2014.

On September 17, 2010, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which included a consent to the formation of a new wholly owned subsidiary, BreitBurn Collingwood Utica LLC (“Utica”), and its designation as an unrestricted subsidiary under our bank credit facility. Utica is not a guarantor of indebtedness under our bank credit facility. On October 6, 2010, we and BreitBurn Finance Corporation, and certain of our subsidiaries, as guarantors, issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “Notes”). See Note 13 for a discussion of the Notes.

As of September 30, 2010 and December 31, 2009, we had $516.0 million and $559.0 million, respectively, in indebtedness outstanding under our credit facility. At September 30, 2010, the 1-month LIBOR interest rate plus an applicable spread on our long-term debt was 2.760 percent. The amounts reported on our consolidated balance sheets for long-term debt approximate fair value due to the variable nature of our interest rates.

The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless after giving effect to such distribution, the availability to borrow under the facility is the lesser of (i) 10 percent of the borrowing base and (ii) the greater of (a) $50 million and (b) twice the amount of the proposed distribution), while remaining in compliance with all terms and conditions of our credit facility, including the leverage ratio not exceeding 3.75 to 1.00 (which is total indebtedness to EBITDAX); 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.

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The Second Amended and Restated Credit Agreement no longer requires that in order to make a distribution to our unitholders, we also must have the ability to borrow 10 percent of our borrowing base after giving effect to such distribution, and remain in compliance with all terms and conditions of our credit facility. In addition, the requirement that we maintain a leverage ratio (defined as the ratio of total debt to EBITDAX) as of the last day of each quarter, on a last twelve month basis of no more than 3.50 to 1.00 was increased to 3.75 to 1.00. The Second Amended and Restated Credit Agreement continues to require us to maintain a current ratio as of the last day of each quarter, of not less than 1.00 to 1.00 and to maintain an interest coverage ratio (defined as the ratio of EBITDAX to consolidated interest expense) as of the last day of each quarter, of not less than 2.75 to 1.00. As of September 30, 2010 and December 31, 2009, we were in compliance with the credit facility’s covenants.

The pricing grid was adjusted by increasing the applicable margins (as defined in the Second Amended and Restated Credit Agreement) between 75 and 100 basis points, depending on the percentage of the borrowing base borrowed, in line with the current credit market for similar facilities. At our debt level as of September 30, 2010, the applicable margin on our borrowings was 250 basis points. The Second Amended and Restated Credit Agreement permits us to incur or guaranty additional debt up to $350 million in senior unsecured notes, and requires that our borrowing base be reduced by 25 percent of the original stated principal amount of such senior unsecured notes when we incur such additional indebtedness. See Note 13 for a discussion of Notes issued on October 6, 2010.

The Second Amended and Restated Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5 percent of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination.

The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims.

EBITDAX is not a defined GAAP measure. The Second Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments), cumulative effect of changes in accounting principles, excluding adjusted EBITDAX attributable to our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and BEPI limited partner interest and including the cash distribution received from unrestricted entities and BEPI.

Our interest and other financing costs, as reflected in interest and other financing costs, net on the consolidated statements of operations, are detailed in the following table:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Thousands of dollars	2010		2009		2010		2009
Credit agreement (including commitment fees)	$	4,084	$	3,726	$	10,912	$	12,213
Amortization of discount and deferred issuance costs		1,063		823		2,850		2,469
Total	$	5,147	$	4,549	$	13,762	$	14,682

In connection with entry into the Second Amended and Restated Credit Agreement, we incurred $11.9 million in debt issuance costs, to be amortized over the life of the debt.

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7. 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 together with our estimate of the future timing of the costs to be incurred. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years. Estimated cash flows have been discounted at our credit-adjusted risk free rate of seven percent and adjusted for inflation using a rate of two percent. Our credit-adjusted risk free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk.

ASC 820 “Fair Value Measurements and Disclosures” 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. Level 2 includes inputs other than quoted prices that are included in Level 1 and can be derived by observable data, including third party data providers. These inputs may also include observable transactions in the market place. Level 3 is defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions. We consider the inputs to our asset retirement obligation valuation to be Level 3, as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.

Changes in the asset retirement obligation for the periods ended September 30, 2010 and December 31, 2009 are presented in the following table:

	Nine Months Ended			Year Ended
Thousands of dollars	September 30, 2010			December 31, 2009
Carrying amount, beginning of period	$	36,635		$	30,086
Liabilities settled in the current period		(1,014	)		(470	)
Revisions (a)		(313	)		4,883
Dispositions (b)		-			(252	)
Accretion expense		1,953			2,388
Carrying amount, end of period	$	37,261		$	36,635

(a) Changes to cost estimates and revisions to reserve life.

(b) Relates to disposition of the Lazy JL Field in Texas, which was sold effective July 1, 2009.

8. Partners’ Equity

During the first nine months of 2010, 510,437 Common Units were issued to employees pursuant to vested grants under our long-term incentive compensation plan, and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights that were granted in 2007 and vested in January 2010.

At September 30, 2010 and December 31, 2009, we had 53,308,255 and 52,784,201 Common Units outstanding, respectively. At September 30, 2010 and December 31, 2009, we had 6,700,000 units authorized for issuance under our long-term incentive compensation plans, and there were 3,640,449 and 2,961,659, respectively, of units outstanding under grants that were eligible to be paid in Common Units upon vesting.

Cash Distributions

On May 14, 2010, we paid a cash distribution of approximately $20.0 million to our common unitholders of record as of the close of business on May 10, 2010. The distribution that was paid to unitholders was $0.375 per Common Unit.

On August 13, 2010, we paid a cash distribution of approximately $20.4 million to our common unitholders of record as of the close of business on August 9, 2010. The distribution that was paid to unitholders was $0.3825 per Common Unit.

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During the nine months ended September 30, 2010, we also paid $2.7 million in cash at a rate equal to the distributions paid to our unitholders, to holders of outstanding unvested Restricted Phantom Units (“RPUs”) and Convertible Phantom Units (“CPUs”) issued under our long-term incentive plan.

Earnings per unit

ASC 260 “Earnings per Share” requires use of the “two-class” method of computing earnings per unit for all periods presented. The “two-class” method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested RPUs and CPUs participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as earnings per common unit.

The following is a reconciliation of net earnings and weighted average units for calculating basic net earnings per common unit and diluted net earnings per common unit.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands, except per unit amounts	2010			2009			2010		2009
Net income (loss) attributable to the partnership	$	(5,754	)	$	(5,408	)	$	105,654	$	(67,577	)
Distributions on participating units not expected to vest		15			-			15		24
Net income (loss) attributable to common unitholders and participating securities	$	(5,739	)	$	(5,408	)	$	105,669	$	(67,553	)
Weighted average number of units used to calculate basic and diluted earnings per unit (in thousands):
Common Units		53,303			52,770			53,297		52,748
Participating securities		-			-			3,442		-
Denominator for basic earnings per common unit (a)		53,303			52,770			56,739		52,748
Dilutive units (b)		-			-			133		-
Denominator for diluted earnings per common unit		53,303			52,770			56,872		52,748
Net income (loss) per common unit
Basic	$	(0.11	)	$	(0.10	)	$	1.86	$	(1.28	)
Diluted	$	(0.11	)	$	(0.10	)	$	1.86	$	(1.28	)

(a) Basic earnings per unit is based on the weighted average number of Common Units outstanding plus the weighted average number of potentially issuable RPUs and CPUs. The three months ended September 30, 2010 and 2009 and the nine months ended September 30, 2009 exclude 3,504, 2,849 and 2,599, respectively, of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.

(b) The nine months ended September 30, 2010 includes dilutive units potentially issuable to directors under compensation plans. The three months ended September 30, 2010 and 2009 and the nine months ended September 30, 2009 exclude 144, 106 and 105, respectively, of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit.

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9. Noncontrolling Interest

ASC 810 “Consolidation”requires that noncontrolling interests be classified as a component of equity and 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.

On May 25, 2007, we acquired the limited partner interest (99 percent) of BEPI from TIFD. As such, we are fully consolidating the results of BEPI and thus are recognizing a noncontrolling interest representing the book value of the general partner’s interests. At September 30, 2010 and December 31, 2009, the amount of this noncontrolling interest was $0.5 million and $0.4 million, respectively. For the three months and nine months ended September 30, 2010, we recorded net income attributable to the noncontrolling interest of less than $0.1 million and $0.1 million, respectively, and dividends of less than $0.1 million and $0.1 million, respectively. For the three months and nine months ended September 30, 2009, we recorded net income attributable to the noncontrolling interest of less than $0.1 million in each period, and dividends of less than $0.1 million and $0.1 million, respectively.

10. Financial Instruments

Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flow and distributions. Routinely, we utilize derivative financial instruments to reduce this volatility. To the extent we have hedged a significant portion of our expected production through commodity derivative instruments and the cost for goods and services increase, our margins would be adversely affected.

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of September 30, 2010, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of September 30, 2010, each of these financial institutions had an investment grade credit rating. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of September 30, 2010, our largest derivative asset balances were with JP Morgan Chase Bank N.A. and Credit Suisse Energy LLC, who accounted for approximately 61 percent and 19 percent of our derivative asset balance, respectively. As of September 30, 2010, our largest derivative liability balances were with Wells Fargo Bank National Association and Barclays Bank PLC, who accounted for approximately 78 percent and 12 percent of our derivative liability balance, respectively.

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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 ASC 815 “Derivatives and Hedging.” Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial reporting purposes and instead recognize changes in fair value immediately in earnings.

We had the following commodity derivative contracts in place at September 30, 2010:

	Year
	2010			2011			2012		2013		2014
Gas Positions:
Fixed price swaps:
Hedged volume (MMBtu/d)		43,113			25,955			19,128		32,000		-
Average price ($/MMBtu)	$	8.22		$	7.26		$	7.10	$	6.70	$	-
Collars:
Hedged volume (MMBtu/d)		3,837			16,016			19,129		-		-
Average floor price ($/MMBtu)	$	9.00		$	9.00		$	9.00	$	-	$	-
Average ceiling price ($/MMBtu)	$	12.65		$	11.28		$	11.89	$	-	$	-
Total:
Hedged volume (MMBtu/d)		46,950			41,971			38,257		32,000		-
Average price ($/MMBtu)	$	8.29		$	7.92		$	8.05	$	6.70	$	-
Oil Positions:
Fixed price swaps:
Hedged volume (Bbls/d)		2,267			3,890			3,539		5,000		2,748
Average price ($/Bbl)	$	83.67		$	72.78		$	72.40	$	79.32	$	89.25
Participating swaps: (a)
Hedged volume (Bbls/d)		1,433			1,439			-		-		-
Average price ($/Bbl)	$	65.67		$	61.29		$	-	$	-	$	-
Average participation %		58.0	%		53.2	%		-		-		-
Collars:
Hedged volume (Bbls/d)		2,140			2,048			2,477		500		-
Average floor price ($/Bbl)	$	105.72		$	103.42		$	110.00	$	77.00	$	-
Average ceiling price ($/Bbl)	$	140.02		$	152.61		$	145.39	$	103.10	$	-
Floors:
Hedged volume (Bbls/d)		500			-			-		-		-
Average floor price ($/Bbl)	$	100.00		$	-		$	-	$	-	$	-
Total:
Hedged volume (Bbls/d)		6,340			7,377			6,016		5,500		2,748
Average price ($/Bbl)	$	88.33		$	79.02		$	87.88	$	79.11	$	89.25

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

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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 September 30, 2010, our total debt outstanding was $516.0 million. In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at September 30, 2010, that fixed rates for a portion of floating LIBOR-base debt under our credit facility:

Notional amounts in thousands of dollars	Notional Amount		Fixed Rate
Period Covered
October 1, 2010 to December 20, 2010		300,000		3.6825	%
October 1, 2010 to October 20, 2011		100,000		1.6200	%
December 20, 2010 to October 20, 2011		200,000		2.9900	%
November 21, 2011 to December 20, 2012		100,000		1.1550	%

Fair Value of Financial Instruments

ASC 815 requires disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for under ASC 815, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. This topic requires the disclosures detailed below.

Fair value of derivative instruments not designated as hedging instruments under ASC 815:

Balance sheet location, thousands of dollars	Oil Commodity Derivatives			Natural Gas Commodity Derivatives		Interest Rate Derivatives			Commodity Derivatives Netting (a)			Total Financial Instruments
As of September 30, 2010
Assets
Current assets - derivative instruments	$	19,072		$	57,611	$	-		$	(1,149	)	$	75,534
Other long-term assets - derivative instruments		26,170			67,209		-			(15,032	)		78,347
Total assets		45,242			124,820		-			(16,181	)		153,881
Liabilities
Current liabilities - derivative instruments		(17,254	)		-		(7,313	)		1,149			(23,418	)
Long-term liabilities - derivative instruments		(37,043	)		-		(661	)		15,032			(22,672	)
Total liabilities		(54,297	)		-		(7,974	)		16,181			(46,090	)
Net assets (liabilities)	$	(9,055	)	$	124,820	$	(7,974	)	$	-		$	107,791
As of December 31, 2009
Assets
Current assets - derivative instruments	$	17,666		$	39,467	$	-		$	-		$	57,133
Other long-term assets - derivative instruments		35,382			42,620		-			(3,243	)		74,759
Total assets		53,048			82,087		-			(3,243	)		131,892
Liabilities
Current liabilities - derivative instruments		(10,234	)		-		(9,823	)		-			(20,057	)
Long-term liabilities - derivative instruments		(51,730	)		-		(1,622	)		3,243			(50,109	)
Total liabilities		(61,964	)		-		(11,445	)		3,243			(70,166	)
Net assets (liabilities)	$	(8,916	)	$	82,087	$	(11,445	)	$	-		$	61,726

(a) Represents counterparty netting under derivative netting agreements. These contracts are reflected net on the balance sheet.

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The location of gains and losses on derivative instruments not designated as hedging instruments under ASC 815 are detailed below:

Income Statement location, thousands of dollars	Oil Commodity Derivatives (a)			Natural Gas Commodity Derivatives (a)			Interest Rate Derivatives (b)			Total Financial Instruments
Three Months Ended September 30, 2010
Realized gains (losses)	$	6,298		$	16,269		$	(2,943	)	$	19,624
Unrealized gains (losses)		(46,721	)		16,181			1,314			(29,226	)
Net gains (losses)	$	(40,423	)	$	32,450		$	(1,629	)	$	(9,602	)
Three Months Ended September 30, 2009
Realized gains (losses)	$	3,646		$	20,710		$	(3,411	)	$	20,945
Unrealized gains (losses)		9,728			(21,365	)		(381	)		(12,018	)
Net gains (losses)	$	13,374		$	(655	)	$	(3,792	)	$	8,927
Nine Months Ended September 30, 2010
Realized gains (losses)	$	8,030		$	45,118		$	(8,761	)	$	44,387
Unrealized gains (losses)		(141	)		42,735			3,471			46,065
Net gains (losses)	$	7,889		$	87,853		$	(5,290	)	$	90,452
Nine Months Ended September 30, 2009
Realized gains (losses)	$	64,829		$	85,083		$	(9,670	)	$	140,242
Unrealized gains (losses)		(135,104	)		(29,328	)		4,113			(160,319	)
Net gains (losses)	$	(70,275	)	$	55,755		$	(5,557	)	$	(20,077	)

(a) Included in gains (losses) on commodity derivative instruments, net on the consolidated statements of operations.

(b) Included in losses on interest rate swaps on the consolidated statements of operations.

ASC 820 “Fair Value Measurements and Disclosures” defines fair value, establishes a framework for measuring fair value and establishes required disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. 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. The fair value hierarchy established by ASC 820 gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 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 ASC 820 are described further as follows:

Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. 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. We consider the over the counter (“OTC”) commodity and interest rate swaps in our portfolio to be Level 2. 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. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of September 30, 2010 and December 31, 2009, our Level 3 derivative 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. Effective January 1, 2010, we adopted ASU 2010-06 “Fair Value Measurements and Disclosures.” ASU 2010-06 requires detailed disclosures of significant transfers in and out of Level 1 and Level 2 categories and the reasons for those transfers. We had no such transfers during the nine months ended September 30, 2010.

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Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options. We compare these fair value amounts to the fair value amounts that we receive from the counterparties on a monthly basis. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.

The model we utilize to calculate the fair value of our commodity derivative instruments is a standard option pricing model. Inputs to the option pricing models include 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 are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatility, forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting.

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 classified.

Recurring fair value measurements at September 30, 2010 and December 31, 2009:

Thousands of dollars	Level 1		Level 2			Level 3		Total
As of September 30, 2010
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	-	$	18,623		$	97,142	$	115,765
Other derivatives (interest rate swaps)		-		(7,974	)		-		(7,974	)
Total	$	-	$	10,649		$	97,142	$	107,791
As of December 31, 2009
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	-	$	(29,304	)	$	102,475	$	73,171
Other derivatives (interest rate swaps)		-		(11,445	)		-		(11,445	)
Total	$	-	$	(40,749	)	$	102,475	$	61,726

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands of dollars	2010			2009		2010			2009
Assets:
Beginning balance	$	115,009		$	113,355	$	102,475		$	153,218
Realized and unrealized gains (losses)		(17,867	)		5,954		(5,333	)		(27,879	)
Settlement (a)		-			-		-			(6,030	)
Ending balance	$	97,142		$	119,309	$	97,142		$	119,309

(a) Settlement reflects the monetization of oil contracts in June 2009.

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For the three months and nine months ended September 30, 2010, realized gains of $8.1 million and $18.8 million and unrealized losses of $26.0 million and $24.1 million, respectively, 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. For the three months and nine months ended September 30, 2009, realized gains of $0.6 million and $15.0 million and unrealized gains of $5.4 million and unrealized losses of $42.9 million, respectively, 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. Determination of fair values incorporates various factors as required by ASC 820 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. During the three months and nine months ended September 30, 2010 and the three months ended September 30, 2009, we had no changes to the fair value of our derivative instruments classified as Level 3 related to purchases, sales, issuances or settlements. During the nine months ended September 30, 2009, we had $6.0 million in settlements impacting the fair value of our derivative instruments classified as Level 3 related to the monetization of oil contracts, and no changes related to purchases, sales or issuances.

11. Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months and nine months ended September 30, 2010 was $5.5 million and $15.4 million, respectively, and for the three months and nine months ended September 30, 2009 was $3.5 million and $9.7 million, respectively.

During the three months and nine months ended September 30, 2010, the board of directors of BreitBurn GP, LLC (our “General Partner”) approved the grant of 1,062 and 1,475,684 RPUs, respectively, to employees of BreitBurn Management under our First Amended and Restated 2006 Long-Term Incentive Plan (“LTIP”). Our outside directors were issued 3,286 and 66,486 phantom units under our LTIP during the three months and nine months ended September 30, 2010, respectively. The fair market value of the RPUs granted during 2010 for computing compensation expense under ASC 718 “Compensation—Stock Compensation” averaged $13.74 per unit.

During the nine months of 2010, 510,437 Common Units were issued to employees pursuant to grants that vested under our LTIP and 13,617 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2007 and vested in January 2010. Common Units issued under our LTIP are issued net of units withheld for payment of taxes.

For the three months and nine months ended September 30, 2010, we paid less than $0.1 million and $0.1 million, respectively, for various liability-classified compensation plans. For the three months and nine months ended September 30, 2009, we paid $0 and approximately $0.1 million, respectively, in cash for various liability-classified compensation plans. For the three months and nine months ended September 30, 2010, we paid $1.4 million and $2.7 million in cash, respectively, at a rate equal to the distribution paid to our unitholders, to holders of unvested RPUs and CPUs. For the three months and nine months ended September 30, 2009, we paid $0 and approximately $0.7 million, respectively, at a rate equal to the distribution paid to our unitholders, to holders of unvested RPUs and CPUs.

As of September 30, 2010, we had $32.4 million of total unrecognized compensation costs for all outstanding plans. This amount is expected to be recognized over the period from October 1, 2010 to December 31, 2012.

For detailed information on our various compensation plans, see Note 17 to the consolidated financial statements included in our Annual Report.

12. Commitments and Contingencies

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 September 30, 2010 and December 31, 2009, we had various surety bonds for $10.9 million and $10.6 million, respectively. At September 30, 2010 and December 31, 2009, we had approximately $0.3 million in letters of credit outstanding.

-15-

13. Subsequent Events

Senior Notes Due 2020

On October 6, 2010, we and BreitBurn Finance Corporation (the “Issuers”), and certain of our subsidiaries, as guarantors (the “Guarantors”), issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the “Notes”). The Notes were not registered under the Securities Act of 1933, as amended (the “Securities Act”), or any state securities laws, and unless so registered, the Notes may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. The Notes were sold pursuant to a private placement exemption from the Securities Act to a group of initial purchasers (“Initial Purchasers”) and then resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation 5 under the Securities Act. We received net proceeds of approximately $291.4 million (after deducting estimated fees and offering expenses). We used $290 million of the net proceeds to repay amounts outstanding under our bank credit facility. In connection with the Notes, we incurred financing fees and expenses of approximately $8.6 million, which will be amortized over the life of the Notes. The $5 million discount will also be amortized over the life of the Notes.

In connection with the issuance of the Notes, we entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the Guarantors and Initial Purchasers. Under the Registration Rights Agreement, the Issuers and the Guarantors shall cause to be filed with the Securities and Exchange Commission a registration statement with respect to an offer to exchange the Notes for substantially identical notes that are registered under the Securities Act. The Issuers and the Guarantors will use their commercially reasonable efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, the Issuers and the Guarantors will use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 400 days after October 6, 2010. Under some circumstances, in lieu of, or in addition to, a registered exchange offer, the Issuers and the Guarantors have agreed to file a shelf registration statement with respect to the Notes. The Issuers and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods.

Credit Facility

On October 5, 2010, the borrowing base under our Second Amended and Restated Credit Agreement was reaffirmed at $735 million. As a result of the completion of the Notes offering, our borrowing base was automatically reduced from $735 million to $658.8 million.

Additional Subsequent Events

On October 4, 2010, we entered into crude oil fixed price swap contracts for 500 Bbl/d for the period January 2011 to March 2011 at $83.90 per Bbl, 500 Bbl/d for April 2011 to December 2014 at $88.00 per Bbl and 500 Bbl/d for the period April 2011 to December 2014 at $87.75 per Bbl. On November 2, 2010, we entered into a natural gas swap contract for 5,000 MMBtu/d for 2013 at $5.25 per MMBtu.

On October 29, 2010, we announced a cash distribution to unitholders for the third quarter of 2010 at the rate of $0.3900 per Common Unit, to be paid on November 12, 2010.

In October 2010, Quicksilver sold 0.65 million Common Units, resulting in Quicksilver’s ownership being reduced to approximately 15.7 million Common Units, and with that sale, Quicksilver now owns approximately 29 percent of our Common Units.

-16-

Condensed Consolidating Financial Information

BreitBurn Energy Partners L.P. (the “Partnership,” “we,” “us” or “our”), BreitBurn Finance Corporation, a Delaware corporation (together with the Partnership, the “Issuers”), and certain of our 100% owned subsidiaries, as guarantors (the “Guarantors”), entered into a Purchase Agreement (the “Purchase Agreement”) with the Initial Purchasers as defined therein, pursuant to which the Issuers agreed to sell $305 million in aggregate principal amount of the Issuers’ 8.625% Senior Notes due 2020 (the “Notes”). The Notes were offered and sold in private placements to qualified institutional buyers in the United States in reliance on Rule 144A under the Securities Act of 1933, as amended.

In connection with the issuance of the Notes, we entered into a registration rights agreement requiring us to file an exchange offer registration statement with the Securities and Exchange Commission (the “SEC”) with respect to an offer to exchange the Notes for substantially identical notes that are registered under the Securities Act of 1933. Certain, but not all, of our subsidiaries have issued full, unconditional and joint and several guarantees of the Notes, will guarantee the exchange offer notes and may guarantee future issuances of debt securities, in accordance with Rule 3-10(d) of Regulation S-X.

We are, therefore, presenting condensed consolidating financial information as of September 30, 2010 and December 31, 2009 and for the three months and nine months ended September 30, 2010 and 2009 on a parent/co-issuer, guarantor subsidiaries, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Eliminating entries presented are necessary to combine the parent/co-issuer, the guarantor subsidiaries and the non-guarantor subsidiaries. For purposes of the following tables, we are referred to as “Parent” and the “Guarantor Subsidiaries” are all of our subsidiaries other than BreitBurn Energy Partners I, L.P (“BEPI”, the “Non-Guarantor Subsidiary”) and our wholly owned subsidiary, BreitBurn Collingwood Utica LLC, formed in September 2010 (together the “Non-Guarantor Subsidiaries”). We hold a 99 percent limited partner interest in BEPI.

BreitBurn Finance Corporation, our wholly-owned subsidiary, was organized for the sole purpose of being a co-issuer of certain of our indebtedness, including the Notes. BreitBurn Finance Corporation has no operations and no revenue other than as may be incidental to its activities as co-issuer of our indebtedness.

-17-

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	-		$	71,354		$	5,701		$	-		$	77,055
Losses on commodity derivative instruments, net		-			(7,973	)		-			-			(7,973	)
Other revenue, net		-			719			-			-			719
Total revenues and other income items		-			64,100			5,701			-			69,801
Operating costs and expenses
Operating costs		-			30,874			2,333			-			33,207
Depletion, depreciation and amortization		92			22,978			566			-			23,636
General and administrative expenses		50			12,688			2			-			12,740
Gain on sale of assets		-			(359	)		-			-			(359	)
Total operating costs and expenses		142			66,181			2,901			-			69,224
Operating income (loss)		(142	)		(2,081	)		2,800			-			577
Interest and other financing costs, net		-			5,147			-			-			5,147
Losses on interest rate swaps		-			1,629			-			-			1,629
Other income, net		-			(2	)		(1	)		-			(3	)
Total other expense (income)		-			6,774			(1	)		-			6,773
Income (loss) before taxes		(142	)		(8,855	)		2,801			-			(6,196	)
Income tax benefit		-			(470	)		-			-			(470	)
Equity in earnings (losses) of subsidiaries		(5,612	)		2,773			-			2,839			-
Net income (loss)		(5,754	)		(5,612	)		2,801			2,839			(5,726	)
Less: Net income attributable to noncontrolling interest		-			-			-			(28	)		(28	)
Net income (loss) attributable to the partnership	$	(5,754	)	$	(5,612	)	$	2,801		$	2,811		$	(5,754	)

-18-

Condensed Consolidating Statements of Operations

	Nine Months Ended September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	-		$	222,010		$	17,593		$	-		$	239,603
Gains on commodity derivative instruments, net		-			95,742			-			-			95,742
Other revenue, net		-			1,838			-			-			1,838
Total revenues and other income items		-			319,590			17,593			-			337,183
Operating costs and expenses
Operating costs		-			101,116			7,313			-			108,429
Depletion, depreciation and amortization		307			67,469			1,823			-			69,599
General and administrative expenses		343			33,599			15			-			33,957
Loss on sale of assets		-			137			-			-			137
Total operating costs and expenses		650			202,321			9,151			-			212,122
Operating income (loss)		(650	)		117,269			8,442			-			125,061
Interest and other financing costs, net		-			13,762			-			-			13,762
Losses on interest rate swaps		-			5,290			-			-			5,290
Other income, net		-			(6	)		(1	)		-			(7	)
Total other expense (income)		-			19,046			(1	)		-			19,045
Income (loss) before taxes		(650	)		98,223			8,443			-			106,016
Income tax expense (benefit)		(25	)		259			1			-			235
Equity in earnings of subsidiaries		106,323			8,359			-			(114,682	)		-
Net income		105,698			106,323			8,442			(114,682	)		105,781
Less: Net income attributable to noncontrolling interest		-			-			-			(127	)		(127	)
Net income attributable to the partnership	$	105,698		$	106,323		$	8,442		$	(114,809	)	$	105,654

-19-

 Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor      Subsidiary		Eliminations			Consolidated
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	-		$	57,293		$	5,381	$	-		$	62,674
Gains on commodity derivative instruments, net		-			12,719			-		-			12,719
Other revenue, net		-			261			-		-			261
Total revenues and other income items		-			70,273			5,381		-			75,654
Operating costs and expenses
Operating costs		1			31,413			2,474		-			33,888
Depletion, depreciation and amortization		-			23,765			365		-			24,130
General and administrative expenses		(1	)		9,318			1		-			9,318
Loss on sale of assets		-			5,470			-		-			5,470
Total operating costs and expenses		-			69,966			2,840		-			72,806
Operating income (loss)		-			307			2,541		-			2,848
Interest and other financing costs, net		-			4,549			-		-			4,549
Losses on interest rate swaps		-			3,792			-		-			3,792
Other income, net		-			(84	)		-		-			(84	)
Total other expense		-			8,257			-		-			8,257
Income (loss) before taxes		-			(7,950	)		2,541		-			(5,409	)
Income tax benefit		-			(13	)		-		-			(13	)
Equity in earnings (losses) of subsidiaries		(5,421	)		2,516			-		2,905			-
Net income (loss)		(5,421	)		(5,421	)		2,541		2,905			(5,396	)
Less: Net income attributable to noncontrolling interest		-			-			-		(12	)		(12	)
Net income (loss) attributable to the partnership	$	(5,421	)	$	(5,421	)	$	2,541	$	2,893		$	(5,408	)

-20-

Condensed Consolidating Statements of Operations

	Nine Months Ended September 30, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor      Subsidiary			Eliminations			Consolidated
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	-		$	167,131		$	13,058		$	-		$	180,189
Losses on commodity derivative instruments, net		-			(14,520	)		-			-			(14,520	)
Other revenue, net		-			930			-			-			930
Total revenues and other income items		-			153,541			13,058			-			166,599
Operating costs and expenses
Operating costs		3			94,014			6,256			-			100,273
Depletion, depreciation and amortization		387			79,587			1,419			-			81,393
General and administrative expenses		419			26,853			(7	)		-			27,265
Loss on sale of assets		-			5,470			-			-			5,470
Total operating costs and expenses		809			205,924			7,668			-			214,401
Operating income (loss)		(809	)		(52,383	)		5,390			-			(47,802	)
Interest and other financing costs, net		-			14,682			-			-			14,682
Losses on interest rate swaps		-			5,557			-			-			5,557
Other income, net		-			(123	)		(1	)		-			(124	)
Total other expense (income)		-			20,116			(1	)		-			20,115
Income (loss) before taxes		(809	)		(72,499	)		5,391			-			(67,917	)
Income tax expense (benefit)		61			(416	)		1			-			(354	)
Equity in earnings (losses) of subsidiaries		(66,747	)		5,336			-			61,411			-
Net income (loss)		(67,617	)		(66,747	)		5,390			61,411			(67,563	)
Less: Net income attributable to noncontrolling interest		-			-			-			(14	)		(14	)
Net income (loss) attributable to the partnership	$	(67,617	)	$	(66,747	)	$	5,390		$	61,397		$	(67,577	)

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Condensed Consolidating Balance Sheets

	As of September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non- Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash	$	12		$	1,726		$	1,671		$	-		$	3,409
Accounts and other receivables, net		10,000			40,847			1,401			-			52,248
Derivative instruments		-			75,534			-			-			75,534
Related party receivables		-			2,062			-			-			2,062
Inventory		-			4,621			-			-			4,621
Prepaid expenses		-			7,235			-			-			7,235
Intangibles		-			124			-			-			124
Total current assets		10,012			132,149			3,072			-			145,233
Investments in subsidiaries		1,307,806			46,547			-			(1,354,353	)		-
Intercompany receivables (payables)		(20,272	)		6,884			13,388			-			-
Equity investments		-			7,857			-			-			7,857
Property, plant and equipment
Property, plant and equipment		8,467			2,066,530			46,176			-			2,121,173
Accumulated depletion and depreciation		(905	)		(380,853	)		(11,159	)		-			(392,917	)
Net property, plant and equipment		7,562			1,685,677			35,017			-			1,728,256
Other long-term assets
Derivative instruments		-			78,347			-			-			78,347
Other long-term assets		277			11,558			74			-			11,909
Total assets	$	1,305,385		$	1,969,019		$	51,551		$	(1,354,353	)	$	1,971,602
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	3		$	24,502		$	840		$	-		$	25,345
Derivative instruments		-			23,418			-			-			23,418
Revenue and royalties payable		-			15,563			1,267			-			16,830
Salaries and wages payable		-			9,272			-			-			9,272
Accrued liabilities		-			9,193			977			-			10,170
Total current liabilities		3			81,948			3,084			-			85,035
Long-term debt		-			516,000			-			-			516,000
Deferred income taxes		-			2,680			-			-			2,680
Asset retirement obligation		-			35,811			1,450			-			37,261
Derivative instruments		-			22,672			-			-			22,672
Other long-term liabilities		-			2,102			-			-			2,102
Total liabilities		3			661,213			4,534			-			665,750
Equity
Partners' equity		1,305,382			1,307,806			47,017			(1,354,811	)		1,305,394
Noncontrolling interest		-			-			-			458			458
Total equity		1,305,382			1,307,806			47,017			(1,354,353	)		1,305,852
Total liabilities and equity	$	1,305,385		$	1,969,019		$	51,551		$	(1,354,353	)	$	1,971,602

-22-

Condensed Consolidating Balance Sheets

	As of December 31, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
ASSETS
Current assets:
Cash	$	149		$	4,917		$	700		$	-		$	5,766
Accounts and other receivables, net		13,000			50,196			2,013			-			65,209
Derivative instruments		-			57,133			-			-			57,133
Related party receivables		-			2,127			-			-			2,127
Inventory		-			5,823			-			-			5,823
Prepaid expenses		-			5,888			-			-			5,888
Intangibles		-			495			-			-			495
Total current assets		13,149			126,579			2,713			-			142,441
Investments in subsidiaries		1,201,492			47,074			-			(1,248,566	)		-
Intercompany receivables (payables)		18,743			(32,209	)		13,466			-			-
Equity investments		-			8,150			-			-			8,150
Property, plant and equipment
Oil and gas properties		8,467			2,005,619			44,882			-			2,058,968
Non-oil and gas assets		-			7,717			-			-			7,717
		8,467			2,013,336			44,882			-			2,066,685
Accumulated depletion and depreciation		(597	)		(315,567	)		(9,432	)		-			(325,596	)
Net property, plant and equipment		7,870			1,697,769			35,450			-			1,741,089
Other long-term assets
Derivative instruments		-			74,759			-			-			74,759
Other long-term assets		74			4,459			57			-			4,590
Total assets	$	1,241,328		$	1,926,581		$	51,686		$	(1,248,566	)	$	1,971,029
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable	$	2		$	20,386		$	926		$	-		$	21,314
Derivative instruments		-			20,057			-			-			20,057
Related party payables		13,000			-			-			-			13,000
Revenue and royalties payable		-			16,888			1,336			-			18,224
Salaries and wages payable		-			10,244			-			-			10,244
Accrued liabilities		-			8,531			520			-			9,051
Total current liabilities		13,002			76,106			2,782			-			91,890
Long-term debt		-			559,000			-			-			559,000
Deferred income taxes		-			2,492			-			-			2,492
Asset retirement obligation		-			35,280			1,355			-			36,635
Derivative instruments		-			50,109			-			-			50,109
Other long-term liabilities		-			2,102			-			-			2,102
Total liabilities		13,002			725,089			4,137			-			742,228
Equity:
Partners' equity		1,228,326			1,201,492			47,549			(1,248,994	)		1,228,373
Noncontrolling interest		-			-			-			428			428
Total equity		1,228,326			1,201,492			47,549			(1,248,566	)		1,228,801
Total liabilities and equity	$	1,241,328		$	1,926,581		$	51,686		$	(1,248,566	)	$	1,971,029

-23-

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
Cash flows from operating activities
Net income	$	105,698		$	106,323		$	8,442		$	(114,682	)	$	105,781
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		307			67,469			1,823			-			69,599
Unit based compensation expense		-			15,386			-			-			15,386
Unrealized gains on derivative instruments		-			(46,065	)		-			-			(46,065	)
Income from equity affiliates, net		-			293			-			-			293
Equity (earnings) losses in subsidiaries		(106,323	)		(8,359	)		-			114,682			-
Deferred income tax		-			188			-			-			188
Amortization of intangibles		-			371			-			-			371
Loss on sale of assets		-			137			-			-			137
Other		-			2,850			-			-			2,850
Changes in net assets and liabilities
Accounts receivable and other assets		2,798			9,921			596			-			13,315
Inventory		-			1,202			-			-			1,202
Net change in related party receivables and payables		(13,000	)		65			-			-			(12,935	)
Accounts payable and other liabilities		1			(7,132	)		309			-			(6,822	)
Net cash provided (used) by operating activities		(10,519	)		142,649			11,170			-			143,300
Cash flows from investing activities
Capital expenditures		-			(45,115	)		(1,303	)		-			(46,418	)
Proceeds from sale of assets		-			225			-			-			225
Property acquisitions		-			(1,550	)		-			-			(1,550	)
Net cash used by investing activities		-			(46,440	)		(1,303	)		-			(47,743	)
Cash flows from financing activities
Distributions		(43,043	)		-			-			-			(43,043	)
Proceeds from long-term debt		-			683,500			-			-			683,500
Repayments of long-term debt		-			(726,500	)		-			-			(726,500	)
Long-term debt issuance costs		-			(11,871	)		-			-			(11,871	)
Intercompany activity		53,425			(44,529	)		(8,896	)		-			-
Net cash provided (used) by investing activities		10,382			(99,400	)		(8,896	)		-			(97,914	)
Increase (decrease) in cash		(137	)		(3,191	)		971			-			(2,357	)
Cash beginning of period		149			4,917			700			-			5,766
Cash end of period	$	12		$	1,726		$	1,671		$	-		$	3,409

-24-

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2009
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non- Guarantor Subsidiary			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	(67,617	)	$	(66,747	)	$	5,390		$	61,411		$	(67,563	)
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization		387			79,587			1,419			-			81,393
Unit based compensation expense		-			9,736			-			-			9,736
Unrealized losses on derivative instruments		-			160,319			-			-			160,319
Income from equity affiliates, net		-			766			-			-			766
Equity (earnings) losses in subsidiaries		66,747			(5,336	)		-			(61,411	)		-
Deferred income tax		-			(897	)		-			-			(897	)
Amortization of intangibles		-			2,334			-			-			2,334
Loss on sale of assets		-			5,470			-			-			5,470
Other		-			2,472			-			-			2,472
Changes in net assets and liabilities
Accounts receivable and other assets		-			4,851			(1,261	)		-			3,590
Inventory		-			(3,710	)		-			-			(3,710	)
Net change in related party receivables and payables		-			340			-			-			340
Accounts payable and other liabilities		(23	)		(12,356	)		2,100			-			(10,279	)
Net cash provided (used) by operating activities		(506	)		176,829			7,648			-			183,971
Cash flows from investing activities
Capital expenditures		-			(18,114	)		(489	)		-			(18,603	)
Proceeds from sale of assets		-			23,034			-			-			23,034
Net cash provided (used) by investing activities		-			4,920			(489	)		-			4,431
Cash flows from financing activities
Distributions		(28,038	)		-			-			-			(28,038	)
Proceeds from long-term debt		-			218,475			-			-			218,475
Repayments of long-term debt		-			(369,475	)		-			-			(369,475	)
Book overdraft		-			(9,711	)		-			-			(9,711	)
Intercompany activity		28,637			(20,267	)		(8,370	)		-			-
Net cash provided (used) by financing activities		599			(180,978	)		(8,370	)		-			(188,749	)
Increase (decrease) in cash		93			771			(1,211	)		-			(347	)
Cash beginning of period		2			731			1,813			-			2,546
Cash end of period	$	95		$	1,502		$	602		$	-		$	2,199

-25-