UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended September 30, 2011

or

o	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from ___ to ___

Commission File Number 001-33055

BreitBurn Energy Partners L.P.

(Exact name of registrant as specified in its charter)

Delaware	74-3169953
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)
515 South Flower Street, Suite 4800
Los Angeles, California	90071
(Address of principal executive offices)	(Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o     No x

As of November 8, 2011, the registrant had 59,039,933 Common Units outstanding.

INDEX

		Page No.
	Cautionary Statement Regarding Forward-Looking Information	1
	PART I
	FINANCIAL INFORMATION
Item 1.	Financial Statements
	– Unaudited Consolidated Balance Sheets at September 30, 2011 and December 31, 2010	2
	– Unaudited Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2011 and 2010	3
	– Unaudited Consolidated Statements of Cash Flows for Nine Months Ended September 30, 2011 and 2010	4
	– Notes to Consolidated Financial Statements	5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	36
	PART II
	OTHER INFORMATION
Item 1.	Legal Proceedings	37
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 4.	(Removed and Reserved)	37
Item 5.	Other Information	37
Item 6.	Exhibits	37
Signatures		39

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

Forward-looking statements are included in this report and may be included in other public filings, press releases, our website and oral and written presentations by management.  Statements other than historical facts are forward-looking and may be identified by words such as “believe,” “estimate,” “impact,” “future,” “affect,” “result,” “engage,” “will,” variations of such words and words of similar meaning.  These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict.  Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements.  The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are changes in crude oil and natural gas prices; delays in planned or expected drilling; changes in costs and availability of drilling, completion, and production equipment, and related services and labor; the discovery of previously unknown environmental issues; the competitiveness of alternate energy sources or product substitutes; technological developments; potential disruption or interruption of our net production due to accidents or severe weather; changes in governmental regulations, including the regulation of derivatives and the oil and natural gas industry; the effects of changes in accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; integration and other risks associated with our acquisitions; and the factors set forth under “Cautionary Statement Regarding Forward-Looking Information” and Part I—Item 1A “—Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2010, Part II—Item 1A of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011 and in Part II—Item 1A of this report.  Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

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

We undertake no obligation to update the forward-looking statements in this report to reflect future events or circumstances.

1

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Balance Sheets

Thousands	September 30, 2011			December 31, 2010
ASSETS
Current assets
Cash	$	4,777		$	3,630
Accounts and other receivables, net	64,542			53,520
Derivative instruments (note 3)	87,824			54,752
Related party receivables (note 4)	3,413			4,345
Inventory (note 5)	4,683			7,321
Prepaid expenses	6,611			6,449
Total current assets	171,850			130,017
Equity investments	7,531			7,700
Property, plant and equipment
Oil and gas properties	2,248,035			2,133,099
Other assets	11,916			10,832
	2,259,951			2,143,931
Accumulated depletion and depreciation	(494,704		)	(421,636		)
Net property, plant and equipment	1,765,247			1,722,295
Other long-term assets
Derivative instruments (note 3)	64,418			50,652
Other long-term assets	32,315			19,503
Total assets	$	2,041,361		$	1,930,167
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	31,748		$	26,808
Derivative instruments (note 3)	14,630			37,071
Revenue and royalties payable	17,876			16,427
Salaries and wages payable	9,090			12,594
Accrued liabilities	12,264			8,417
Total current liabilities	85,608			101,317
Credit facility (note 6)	211,000			228,000
Senior notes, net (note 6)	300,489			300,116
Deferred income taxes (note 8)	3,402			2,089
Asset retirement obligation (note 9)	47,083			47,429
Derivative instruments (note 3)	2,514			39,722
Other long-term liabilities	2,043			2,237
Total liabilities	652,139			720,910
Equity
Partners' equity (note 10)	1,388,771			1,208,803
Noncontrolling interest (note 11)	451			454
Total equity	1,389,222			1,209,257
Total liabilities and equity	$	2,041,361		$	1,930,167
Common units outstanding	59,040			53,957

See accompanying notes to consolidated financial statements.

2

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	2011			2010			2011			2010
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	97,356		$	77,055		$	284,673		$	239,603
Gain (loss) on commodity derivative instruments, net (note 3)	178,826			(7,973		)	119,132			95,742
Other revenue, net	1,375			719			3,416			1,838
Total revenues and other income items	277,557			69,801			407,221			337,183
Operating costs and expenses
Operating costs	46,446			33,207			119,465			108,429
Depletion, depreciation and amortization	26,688			23,636			76,354			69,599
General and administrative expenses	13,999			12,740			38,126			33,957
(Gain) loss on sale of assets	(94		)	(359		)	(40		)	137
Total operating costs and expenses	87,039			69,224			233,905			212,122
Operating income	190,518			577			173,316			125,061
Interest expense, net of capitalized interest	9,270			5,147			27,770			13,762
Loss on interest rate swaps (note 3)	1,143			1,629			3,020			5,290
Other income, net	(17		)	(3		)	(20		)	(7		)
Income (loss) before taxes	180,122			(6,196		)	142,546			106,016
Income tax expense (benefit) (note 8)	1,895			(470		)	1,509			235
Net income (loss)	178,227			(5,726		)	141,037			105,781
Less: Net income attributable to noncontrolling interest	(46		)	(28		)	(148		)	(127		)
Net income (loss) attributable to the partnership	$	178,181		$	(5,754	)	$	140,889		$	105,654
Basic net income (loss) per unit (note 10)	$	2.87		$	(0.11	)	$	2.30		$	1.86
Diluted net income (loss) per unit (note 10)	$	2.87		$	(0.11	)	$	2.29		$	1.86

See accompanying notes to consolidated financial statements.

3

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

	Nine Months Ended
	September 30,
Thousands of dollars	2011			2010
Cash flows from operating activities
Net income	$	141,037		$	105,781
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization	76,354			69,599
Unit-based compensation expense	16,334			15,386
Unrealized gain on derivative instruments	(106,488		)	(46,065		)
Income from equity affiliates, net	169			293
Deferred income taxes	1,313			188
Amortization of intangibles	—			371
(Gain) loss on sale of assets	(40		)	137
Other	417			2,850
Changes in net assets and liabilities
Accounts receivable and other assets	(9,858		)	13,315
Inventory	2,638			1,202
Net change in related party receivables and payables	932			(12,935		)
Accounts payable and other liabilities	5,976			(6,822		)
Net cash provided by operating activities	128,784			143,300
Cash flows from investing activities
Capital expenditures	(61,264		)	(46,418		)
Proceeds from sale of assets	1,118			225
Deposit for oil and gas properties	(14,250		)	—
Property acquisitions	(57,380		)	(1,550		)
Net cash used in investing activities	(131,776		)	(47,743		)
Cash flows from financing activities
Issuance of common units	99,826			—
Distributions	(75,690		)	(43,043		)
Proceeds from issuance of long-term debt	283,500			683,500
Repayments of long-term debt	(300,500		)	(726,500		)
Change in book overdraft	141			—
Long-term debt issuance costs	(3,138		)	(11,871		)
Net cash provided by (used in) financing activities	4,139			(97,914		)
Increase (decrease) in cash	1,147			(2,357		)
Cash beginning of period	3,630			5,766
Cash end of period	$	4,777		$	3,409

See accompanying notes to consolidated financial statements.

4

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, 2010 (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.  In the opinion of management, all adjustments considered necessary for a fair statement of our financial position at September 30, 2011, our operating results for the three months and nine months ended September 30, 2011 and 2010, and our cash flows for the nine months ended September 30, 2011 and 2010, have been included.  Operating results for the three months and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ended December 31, 2011.  The consolidated balance sheet at December 31, 2010 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.

On June 15, 2011, Quicksilver Resources Inc. ("Quicksilver") sold 7.0 million of our limited partnership units ("Common Units") at a price to the public of $19.78 per Common Unit. In connection with this sale, Quicksilver granted the underwriters an option to purchase up to an additional 1.1 million Common Units to cover over-allotments. On July 8, 2011, Quicksilver sold an additional 0.6 million Common Units at a price to the public of $19.78 per Common Unit. These sales resulted in Quicksilver's ownership percentage being reduced from 26.4% to 13.6%.

On July 26, 2011, we entered into an agreement (the "Purchase Agreement") with Cabot Oil & Gas Corporation ("Cabot") to acquire oil and gas properties located primarily in the Evanston and Green River Basins of Southwest Wyoming (the "Cabot Assets") for approximately $283 million in cash, subject to customary purchase price adjustments and the execution and delivery of a transition services agreement (the "Cabot Acquisition"). The Cabot Assets also include limited acreage and non-operated oil and gas interests in Colorado and Utah. These properties are 95% natural gas. Concurrent with the execution of the acquisition agreement, we paid a $14.3 million deposit to the seller, which was applied toward the cash consideration due at closing on October 6, 2011. See Note 14 for a further discussion of the Cabot Acquisition.

On July 28, 2011, we completed the acquisition of crude oil properties in Niobrara County, Wyoming with an effective date of July 1, 2011 (the "Greasewood Acquisition"). The purchase price for the acquisition was approximately $57 million in cash. The properties produced approximately 550 Boe/d net in September 2011 and are 100% oil.

2.  Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board ("FASB") issued an Accounting Standards Update ("ASU") that required additional fair value measurement disclosures and clarified existing fair value measurement disclosures. The new disclosures require a gross presentation of activity within the Level 3 roll forward that presents separately information about purchases, sales, issuances and settlements. We adopted the ASU effective for financial statements issued for interim or annual periods beginning after December 15, 2010. The adoption of the ASU has not had an impact on our financial position, results of operations or cash flows.

In May 2011, the FASB issued an ASU to improve comparability between US GAAP and International Financial Reporting Standards ("IFRS") fair value measurement and disclosure requirements. This amendment changes the wording used to describe many of the requirements in US GAAP for measuring fair value and for disclosing information about fair value measurements, particularly for Level 3 fair value measurements. For many of the requirements, the FASB does not intend for the amendments to result in a change in the application of the fair value measurement and disclosure requirements. Some of the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011. This ASU requires prospective application. We do not expect the adoption of this ASU to have a material impact on our financial position, results of operations or cash flows.

5

In June 2011, the FASB issued an ASU to improve comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The amendment requires that components of other comprehensive income be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. Currently, entities can present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. This amendment eliminates that option. For public entities, this ASU is effective for fiscal years beginning after December 15, 2011 and for interim periods within those years. This ASU requires retrospective application. We do not present components of other comprehensive income, and, therefore, we do not expect the provisions of this amendment to have an impact on our financial position, results of operations or cash flows.

3.  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 increases, our margins would be adversely affected.

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 FASB Accounting Standards.  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.  

6

We had the following commodity derivative contracts in place at September 30, 2011:

	Year
	2011			2012		2013		2014		2015
Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbl/d)	5,316			5,039		6,480		5,000		2,500
Average Price ($/Bbl)	$	76.95		$	77.15	$	81.37	$	88.59	$	99.50
Participating Swaps: (a)
Hedged Volume (Bbl/d)	1,377			—		—		—		—
Average Price ($/Bbl)	$	60.00		—		—		—		—
Average Participation %	53.1		%	—		—		—		—
Collars:
Hedged Volume (Bbl/d)	2,166			2,477		500		1,000		1,000
Average Floor Price ($/Bbl)	$	103.61		$	110.00	$	77.00	$	90.00	$	90.00
Average Ceiling Price ($/Bbl)	$	153.50		$	145.39	$	103.10	$	112.00	$	113.50
Total:
Hedged Volume (Bbl/d)	8,859			7,516		6,980		6,000		3,500
Average Price ($/Bbl)	$	80.84		$	87.97	$	81.06	$	88.83	$	96.79
Gas Positions:
Fixed Price Swaps: (b)
Hedged Volume (MMBtu/d)	30,000			35,128		53,000		27,500		27,500
Average Price ($/MMBtu)	$	6.11		$	6.09	$	6.01	$	5.48	$	5.61
Collars:
Hedged Volume (MMBtu/d)	20,000			19,129		—		—		—
Average Floor Price ($/MMBtu)	$	9.00		$	9.00	—		—		—
Average Ceiling Price ($/MMBtu)	$	12.05		$	11.89	—		—		—
Total:
Hedged Volume (MMBtu/d)	50,000			54,257		53,000		27,500		27,500
Average Price ($/MMBtu)	$	7.27		$	7.12	$	6.01	$	5.48	$	5.61

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

(b) A weighted average volume of 17,529 MMBtu/d for 2011 through 2015 is hedged at a weighted average NYMEX Henry Hub price of $5.12 per MMBtu and the remaining volume is hedged at Mich Con City-Gate prices.

7

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, 2011, our total debt outstanding under our credit facility was $211.0 million.  In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at September 30, 2011, 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, 2011 to October 20, 2011	100,000	1.6200	%
October 1, 2011 to October 20, 2011	100,000	2.9900	%
November 21, 2011 to December 20, 2012	100,000	1.1550	%
January 20, 2012 to January 20, 2014	100,000	2.4800	%

Fair Value of Financial Instruments

FASB Accounting Standards require disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, 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:

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, 2011
Assets
Current assets - derivative instruments	$	32,172		$	55,782		$	—		$	(130	)	$	87,824
Other long-term assets - derivative instruments	36,394			37,911			—			(9,887		)	64,418
Total assets	68,566			93,693			—			(10,017		)	152,242
Liabilities
Current liabilities - derivative instruments	(12,566		)	—			(2,194		)	130			(14,630		)
Long-term liabilities - derivative instruments	(9,887		)	—			(2,514		)	9,887			(2,514		)
Total liabilities	(22,453		)	—			(4,708		)	10,017			(17,144		)
Net assets (liabilities)	$	46,113		$	93,693		$	(4,708	)	$	—		$	135,098
As of December 31, 2010
Assets
Current assets - derivative instruments	$	9,438		$	48,972		$	—		$	(3,658	)	$	54,752
Other long-term assets - derivative instruments	15,785			55,806			—			(20,939		)	50,652
Total assets	25,223			104,778			—			(24,597		)	105,404
Liabilities
Current liabilities - derivative instruments	(37,610		)	—			(3,119		)	3,658			(37,071		)
Long-term liabilities - derivative instruments	(58,766		)	(166		)	(1,729		)	20,939			(39,722		)
Total liabilities	(96,376		)	(166		)	(4,848		)	24,597			(76,793		)
Net assets (liabilities)	$	(71,153	)	$	104,612		$	(4,848	)	$	—		$	28,611

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

8

Gains and losses on derivative instruments not designated as hedging instruments:

Thousands of dollars	Oil Commodity Derivatives (a)			Natural Gas Commodity Derivatives (a)			Interest Rate Derivatives (b)			Total Financial Instruments
Three Months Ended September 30, 2011
Realized gain (loss)	$	(4,901	)	$	12,993		$	(1,072	)	$	7,020
Unrealized gain (loss)	161,208			9,526			(71		)	170,663
Net gain (loss)	$	156,307		$	22,519		$	(1,143	)	$	177,683
Three Months Ended September 30, 2010
Realized gain (loss)	$	6,298		$	16,269		$	(2,943	)	$	19,624
Unrealized gain (loss)	(46,721		)	16,181			1,314			(29,226		)
Net gain (loss)	$	(40,423	)	$	32,450		$	(1,629	)	$	(9,602	)
Nine Months Ended September 30, 2011
Realized gain (loss)	$	(25,446	)	$	38,230		$	(3,160	)	$	9,624
Unrealized gain (loss)	117,267			(10,919		)	140			106,488
Net gain (loss)	$	91,821		$	27,311		$	(3,020	)	$	116,112
Nine Months Ended September 30, 2010
Realized gain (loss)	$	8,030		$	45,118		$	(8,761	)	$	44,387
Unrealized gain (loss)	(141		)	42,735			3,471			46,065
Net gain (loss)	$	7,889		$	87,853		$	(5,290	)	$	90,452
(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.
(b) Included in loss on interest rate swaps on the consolidated statements of operations.

FASB Accounting Standards define fair value, establish a framework for measuring fair value and establish required disclosures about fair value measurements.  They also establish 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 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 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, 2011 and December 31, 2010, 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 if we are able to obtain sufficient binding market data or if the interpretation of Level 2 criteria is modified in practice to include non-binding market corroborated data.  We had no transfers in or out of Levels 1, 2 or 3 during the three months and nine months ended September 30, 2011.

9

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 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.

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. Financial assets and liabilities carried at fair value on a recurring basis are presented in the following table.  

Recurring fair value measurements at September 30, 2011 and December 31, 2010:

Thousands of dollars	Level 1		Level 2			Level 3		Total
As of September 30, 2011
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	—	$	56,909		$	82,897	$	139,806
Other derivatives (interest rate swaps)	—		(4,708		)	—		(4,708		)
Total	$	—	$	52,201		$	82,897	$	135,098
As of December 31, 2010
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	—	$	(52,794	)	$	86,253	$	33,459
Other derivatives (interest rate swaps)	—		(4,848		)	—		(4,848		)
Total	$	—	$	(57,642	)	$	86,253	$	28,611

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	2011		2010			2011			2010
Assets:
Beginning balance	$	63,681	$	115,009		$	86,253		$	102,475
Realized gain (a)	13,778		8,041			30,268			18,795
Unrealized gain (loss) (a)	5,438		(25,908		)	(33,624		)	(24,128		)
Ending balance	$	82,897	$	97,142		$	82,897		$	97,142
(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.

During the periods presented, we had no changes in the fair value of our derivative instruments classified as Level 3 related to purchases, sales, issuances or settlements.

10

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist primarily of derivatives and accounts receivable.  Our derivatives expose us to credit risk from counterparties.  As of September 30, 2011, 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, 2011, 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, 2011, our largest derivative asset balances were with JP Morgan Chase Bank N.A. and Credit Suisse Energy LLC, who accounted for approximately 47% and 8%, respectively, and Bank of Montreal, Citibank, N.A, Barclays Bank PLC and BNP Paribas, who each accounted for approximately 7%, of our derivative asset balance.  As of September 30, 2011, our largest derivative liability balances were with Wells Fargo Bank National Association and The Royal Bank of Scotland plc, who accounted for approximately 73% and 22% of our derivative liability balance, respectively.

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 2011, the monthly fee paid by BEC for indirect expenses is approximately $481,000.

At September 30, 2011 and December 31, 2010, we had current receivables of $2.1 million and $3.2 million, respectively, due from BEC related to the administrative services agreement, outstanding liabilities for employee related costs, including incentive compensation plan costs, and oil and gas sales made by BEC on our behalf from certain properties.  For the three months and nine months ended September 30, 2011, the monthly charges to BEC for indirect expenses totaled $1.4 million and $4.3 million, respectively, and charges for direct expenses including incentive compensation plan costs, direct payroll and administrative costs totaled $2.3 million and $5.9 million, respectively.  For the three months and nine months ended September 30, 2011, total oil and gas sales made by BEC on our behalf were approximately $0.6 million and $1.6 million, respectively.

For 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 $1.5 million and $4.9 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.

At September 30, 2011 and December 31, 2010, we had receivables of $1.1 million and $0.4 million, respectively, 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, 2011, total net gas sales to Quicksilver were approximately $0.8 million and $3.0 million, respectively.  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. At September 30, 2011 and December 31, 2010, the related receivable was $0.2 million and $0.7 million, respectively.

11

5.  Inventory

Our crude oil inventory from our Florida operations was $4.7 million at September 30, 2011 and $7.3 million at December 31, 2010.  In the nine months ended September 30, 2011, we sold 645 gross MBbls and produced 578 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

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 "Senior Notes"). The Senior Notes were offered at a discount price of 98.358%, or $300 million. The $5 million discount is being amortized over the life of the Senior Notes. As of September 30, 2011, the Senior Notes had a carrying value of $300.5 million, net of unamortized discount of $4.5 million. Interest on the Senior Notes is payable twice a year in April and October.

As of September 30, 2011, the fair value of the Senior Notes was estimated to be $300.7 million, based on prices quoted from third-party financial institutions.

In connection with the issuance of the Senior Notes, on January 19, 2011, the Issuers filed a registration statement on Form S-4 with the Securities and Exchange Commission (the "SEC") to offer to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act. On February 17, 2011, the exchange registration statement became effective, and we commenced the exchange offer, which was completed on March 30, 2011.

Credit Facility

On May 7, 2010, BreitBurn Operating L.P. ("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 (as amended, the "Second Amended and Restated Credit Agreement"). Borrowings under the Second 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% of the total value of our oil and gas properties.

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, we remain in compliance with all terms and conditions of our credit facility, including the leverage ratio (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. The Second Amended and Restated Credit Agreement also requires us to maintain a current ratio, as of the last day of each quarter, of not less than 1.00 to 1.00.

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, cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and BreitBurn Energy Partners I, L.P. ("BEPI") and excluding income from our unrestricted entities and BEPI. All calculations of EBITDAX, for any applicable period during which a permitted acquisition or disposition is consummated, are determined on a pro forma basis as if such acquisition or disposition was consummated on the first day of such applicable period.

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% of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination.

12

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.

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 credit facility. Utica is not a guarantor of indebtedness under our credit facility. On October 5, 2010, our borrowing base was reaffirmed at $735 million, and, as a result of the issuance of the Senior Notes on October 6, 2010, our borrowing base was automatically reduced to $658.8 million.

On May 9, 2011, we entered into the Second Amendment to the Second Amended and Restated Credit Agreement (the "Second Amendment"), which increased our borrowing base to $735 million and extended the maturity date to May 9, 2016. The Second Amendment also revised certain covenants in the credit facility, which included: eliminating the interest coverage ratio and the "borrowing base availability" test (applied prior to making distributions to unitholders or making other restricted payments); increasing the maximum leverage coverage ratio to 4.00 to 1.00 from 3.75 to 1.00; increasing our ability to incur or guaranty an additional $350 million of unsecured senior notes (subject to our borrowing base being reduced by 25% of the original stated principal amount of such new debt); and adjusting the pricing grid by decreasing the applicable margins (as defined in the Second Amended and Restated Credit Agreement) by 25 basis points.

On August 3, 2011, we entered into the Third Amendment (the "Third Amendment") to the Second Amended and Restated Credit Agreement, which permits us to hedge oil and gas volumes for properties for which we have entered into a purchase agreement prior to closing the transaction. The Third Amendment also provides that such hedges must be terminated in the event that the acquisition does not close within 90 days of the execution of such purchase agreement.

As of September 30, 2011 and December 31, 2010, we were in compliance with the credit facility's covenants. See Note 14 for a discussion of the Fourth Amendment to the Second Amended and Restated Credit Agreement and our October 2011 borrowing base redetermination.

As of September 30, 2011 and December 31, 2010, we had $211.0 million and $228.0 million, respectively, in indebtedness outstanding under the credit facility. At September 30, 2011, the 1-month LIBOR interest rate plus an applicable spread was 2.240% on the 1-month LIBOR portion of $211.0 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.

Our interest and other financing costs, as reflected in interest expense, net of capitalized interest 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	2011		2010		2011			2010
Credit agreement (including commitment fees)	$	1,602	$	4,084	$	4,619		$	10,912
Senior notes	6,576		—		19,583			—
Amortization of discount and deferred issuance costs	1,092		1,063		3,645			2,850
Capitalized interest	—		—		(77		)	—
Total	$	9,270	$	5,147	$	27,770		$	13,762

7. Condensed Consolidating Financial Statements

Given that certain, but not all, of our subsidiaries have issued full, unconditional and joint and several guarantees of our Senior Notes, in accordance with Rule 3-10(d) of Regulation S-X, the following presents condensed consolidating financial information as of September 30, 2011 and December 31, 2010, and for the three months and nine months ended September 30, 2011 and 2010 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, guarantor subsidiaries and non-guarantor subsidiaries. For purposes of the following tables, we and BreitBurn Finance Corporation are referred to as "Parent/Co-Issuer" and the "Guarantor Subsidiaries" are all of our subsidiaries other than BEPI and Utica (together the "Non-Guarantor Subsidiaries").

13

Condensed Consolidating Balance Sheets

	As of September 30, 2011
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash	$	60		$	2,054		$	2,663		$	—		$	4,777
Accounts and other receivables, net	10,250			52,257			2,035			—			64,542
Derivative instruments	—			87,824			—			—			87,824
Related party receivables	—			3,413			—			—			3,413
Inventory	—			4,683			—			—			4,683
Prepaid expenses	884			5,727			—			—			6,611
Total current assets	11,194			155,958			4,698			—			171,850
Investments in subsidiaries	1,406,223			31,411			—			(1,437,634		)	—
Intercompany receivables (payables)	269,986			(266,794		)	(3,192		)	—			—
Equity investments	—			7,531			—			—			7,531
Property, plant and equipment
Oil and gas properties	8,467			2,189,416			50,152			—			2,248,035
Other assets	—			11,916			—			—			11,916
	8,467			2,201,332			50,152			—			2,259,951
Accumulated depletion and depreciation	(1,281		)	(479,888		)	(13,535		)	—			(494,704		)
Net property, plant and equipment	7,186			1,721,444			36,617			—			1,765,247
Other long-term assets
Derivative instruments	—			64,418			—			—			64,418
Other long-term assets	7,075			25,164			76			—			32,315
Total assets	$	1,701,664		$	1,739,132		$	38,199		$	(1,437,634	)	$	2,041,361
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	12,249		$	18,726		$	773		$	—		$	31,748
Derivative instruments	—			14,630			—			—			14,630
Revenue and royalties payable	—			16,171			1,705			—			17,876
Salaries and wages payable	—			9,090			—			—			9,090
Accrued liabilities	—			11,487			777			—			12,264
Total current liabilities	12,249			70,104			3,255			—			85,608
Credit facility	—			211,000			—			—			211,000
Senior notes, net	300,489			—			—			—			300,489
Deferred income taxes	—			3,402			—			—			3,402
Asset retirement obligation	—			43,846			3,237			—			47,083
Derivative instruments	—			2,514			—			—			2,514
Other long-term liabilities	—			2,043			—			—			2,043
Total liabilities	312,738			332,909			6,492			—			652,139
Equity
Partners' equity	1,388,926			1,406,223			31,707			(1,438,085		)	1,388,771
Noncontrolling interest	—			—			—			451			451
Total equity	1,388,926			1,406,223			31,707			(1,437,634		)	1,389,222
Total liabilities and equity	$	1,701,664		$	1,739,132		$	38,199		$	(1,437,634	)	$	2,041,361

14

Condensed Consolidating Balance Sheets

	As of December 31, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets:
Cash	$	70		$	1,836		$	1,724		$	—		$	3,630
Accounts and other receivables, net	10,000			41,945			1,575			—			53,520
Derivative instruments	—			54,752			—			—			54,752
Related party receivables	—			4,345			—			—			4,345
Inventory	—			7,321			—			—			7,321
Prepaid expenses	877			5,572			—			—			6,449
Total current assets	10,947			115,771			3,299			—			130,017
Investments in subsidiaries	1,243,910			30,647			—			(1,274,557		)	—
Intercompany receivables (payables)	245,323			(242,011		)	(3,312		)	—			—
Equity investments	—			7,700			—			—			7,700
Property, plant and equipment
Oil and gas properties	8,467			2,076,074			48,558			—			2,133,099
Other assets	—			10,832			—			—			10,832
	8,467			2,086,906			48,558			—			2,143,931
Accumulated depletion and depreciation	(1,014		)	(408,850		)	(11,772		)	—			(421,636		)
Net property, plant and equipment	7,453			1,678,056			36,786			—			1,722,295
Other long-term assets
Derivative instruments	—			50,652			—			—			50,652
Other long-term assets	7,746			11,681			76			—			19,503
Total assets	$	1,515,379		$	1,652,496		$	36,849		$	(1,274,557	)	$	1,930,167
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	6,300		$	19,566		$	942		$	—		$	26,808
Derivative instruments	—			37,071			—			—			37,071
Revenue and royalties payable	—			15,016			1,411			—			16,427
Salaries and wages payable	—			12,594			—			—			12,594
Accrued liabilities	—			7,912			505			—			8,417
Total current liabilities	6,300			92,159			2,858			—			101,317
Credit facility	—			228,000			—			—			228,000
Senior notes, net	300,116			—			—			—			300,116
Deferred income taxes	—			2,089			—			—			2,089
Asset retirement obligation	—			44,379			3,050			—			47,429
Derivative instruments	—			39,722			—			—			39,722
Other long-term liabilities	—			2,237			—			—			2,237
Total liabilities	306,416			408,586			5,908			—			720,910
Equity:
Partners' equity	1,208,963			1,243,910			30,941			(1,275,011		)	1,208,803
Noncontrolling interest	—			—			—			454			454
Total equity	1,208,963			1,243,910			30,941			(1,274,557		)	1,209,257
Total liabilities and equity	$	1,515,379		$	1,652,496		$	36,849		$	(1,274,557	)	$	1,930,167

15

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2011
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	$	—		$	89,338		$	8,018		$	—		$	97,356
Gain on commodity derivative instruments, net	—			178,826			—			—			178,826
Other revenue, net	—			1,375			—			—			1,375
Total revenues and other income items	—			269,539			8,018			—			277,557
Operating costs and expenses:
Operating costs	—			43,519			2,927			—			46,446
Depletion, depreciation and amortization	63			25,938			687			—			26,688
General and administrative expenses	476			13,521			2			—			13,999
Gain on sale of assets	—			(94		)	—			—			(94		)
Total operating costs and expenses	539			82,884			3,616			—			87,039
Operating income (loss)	(539		)	186,655			4,402			—			190,518
Interest expense, net of capitalized interest	6,921			2,349			—			—			9,270
Loss on interest rate swaps	—			1,143			—			—			1,143
Other income, net	—			(16		)	(1		)	—			(17		)
Income (loss) before taxes	(7,460		)	183,179			4,403			—			180,122
Income tax expense	34			1,861			—			—			1,895
Net income (loss) before equity earnings	(7,494		)	181,318			4,403			—			178,227
Equity in earnings of subsidiaries	185,675			4,357			—			(190,032		)	—
Net income	178,181			185,675			4,403			(190,032		)	178,227
Less: Net income attributable to noncontrolling interest	—			—			—			(46		)	(46		)
Net income attributable to the partnership	$	178,181		$	185,675		$	4,403		$	(190,078	)	$	178,181

16

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
Loss 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 expense, net	—			5,147			—			—			5,147
Loss on interest rate swaps	—			1,629			—			—			1,629
Other income, net	—			(2		)	(1		)	—			(3		)
Income (loss) before taxes	(142		)	(8,855		)	2,801			—			(6,196		)
Income tax benefit	—			(470		)	—			—			(470		)
Net income (loss) before equity earnings	(142		)	(8,385		)	2,801			—			(5,726		)
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	)

17

Condensed Consolidating Statements of Operations

	Nine Months Ended September 30, 2011
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	$	—		$	260,211		$	24,462		$	—		$	284,673
Gain on commodity derivative instruments, net	—			119,132			—			—			119,132
Other revenue, net	—			3,416			—			—			3,416
Total revenues and other income items	—			382,759			24,462			—			407,221
Operating costs and expenses:
Operating costs	—			112,200			7,265			—			119,465
Depletion, depreciation and amortization	268			74,137			1,949			—			76,354
General and administrative expenses	526			37,595			5			—			38,126
Gain on sale of assets	—			(40		)	—			—			(40		)
Total operating costs and expenses	794			223,892			9,219			—			233,905
Operating income (loss)	(794		)	158,867			15,243			—			173,316
Interest expense, net of capitalized interest	20,613			7,157			—			—			27,770
Loss on interest rate swaps	—			3,020			—			—			3,020
Other income, net	—			(18		)	(2		)	—			(20		)
Income (loss) before taxes	(21,407		)	148,708			15,245			—			142,546
Income tax expense	25			1,482			2			—			1,509
Net income (loss) before equity earnings	(21,432		)	147,226			15,243			—			141,037
Equity in earnings of subsidiaries	162,314			15,088			—			(177,402		)	—
Net income	140,882			162,314			15,243			(177,402		)	141,037
Less: Net income attributable to noncontrolling interest	—			—			—			(148		)	(148		)
Net income attributable to the partnership	$	140,882		$	162,314		$	15,243		$	(177,550	)	$	140,889

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
Gain 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 expense, net	—			13,762			—			—			13,762
Loss on interest rate swaps	—			5,290			—			—			5,290
Other income, net	—			(6		)	(1		)	—			(7		)
Income (loss) before taxes	(650		)	98,223			8,443			—			106,016
Income tax expense (benefit)	(25		)	259			1			—			235
Net income (loss) before equity earnings	(625		)	97,964			8,442			—			105,781
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

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Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2011
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income	140,882			162,314			15,243			(177,402		)	141,037
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization	268			74,137			1949			—			76,354
Unit-based compensation expense	—			16,334			—			—			16,334
Unrealized gain on derivative instruments	—			(106,488		)	—			—			(106,488		)
Income from equity affiliates, net	—			169			—			—			169
Equity in earnings of subsidiaries	(162,314		)	(15,088		)	—			177,402			—
Deferred income taxes	—			1,313			—			—			1,313
Gain on sale of assets	—			(40		)	—			—			(40		)
Other	1,030			(613		)	—			—			417
Changes in net assets and liabilities:
Accounts receivable and other assets	(175		)	(9,223		)	(460		)	—			(9,858		)
Inventory	—			2,638			—			—			2,638
Net change in related party receivables and payables	—			932			—			—			932
Accounts payable and other liabilities	5,948			(192		)	220			—			5,976
Net cash provided by (used in) operating activities	(14,361		)	126,193			16,952			—			128,784
Cash flows from investing activities
Capital expenditures	—			(59,846		)	(1,418		)	—			(61,264		)
Proceeds from sale of assets, net	—			1,118			—			—			1,118
Deposit for oil and gas properties	—			(14,250		)	—			—			(14,250		)
Property acquisitions	—			(57,380		)	—			—			(57,380		)
Net cash used in investing activities	—			(130,358		)	(1,418		)	—			(131,776		)
Cash flows from financing activities
Issuance of common units	99,826			—			—			—			99,826
Distributions	(75,690		)	—			—			—			(75,690		)
Proceeds from the issuance of long-term debt	—			283,500			—			—			283,500
Repayments of long-term debt	—			(300,500		)	—			—			(300,500		)
Change in book overdraft	—			141			—			—			141
Long-term debt issuance costs	(69		)	(3,069		)	—			—			(3,138		)
Intercompany activity	(9,716		)	24,311			(14,595		)	—			—
Net cash provided by (used in) financing activities	14,351			4,383			(14,595		)	—			4,139
Increase (decrease) in cash	(10		)	218			939			—			1,147
Cash beginning of period	70			1,836			1,724			—			3,630
Cash end of period	$	60		$	2,054		$	2,663		$	—		$	4,777
Cash end of period

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Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			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 gain on derivative instruments	—			(46,065		)	—			—			(46,065		)
Income from equity affiliates, net	—			293			—			—			293
Equity in earnings of subsidiaries	(106,323		)	(8,359		)	—			114,682			—
Deferred income taxes	—			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 by (used in) 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 in investing activities	—			(46,440		)	(1,303		)	—			(47,743		)
Cash flows from financing activities
Distributions	(43,043		)	—			—			—			(43,043		)
Proceeds from issuance of 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 by (used in) financing 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

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8.  Income Taxes

Our deferred income tax liability was $3.4 million and $2.1 million at September 30, 2011 and December 31, 2010, respectively.  The following table presents our income tax expense (benefit) for the three months and nine months ended September 30, 2011 and 2010: 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands of dollars	2011			2010			2011		2010
Federal current tax expense (benefit)	$	(10	)	$	77		$	116	$	224
Deferred federal tax expense (benefit) (a)	1,831			(434		)	1,313		188
State income tax expense (benefit) (b)	74			(113		)	80		(177		)
Total income tax expense (benefit)	$	1,895		$	(470	)	$	1,509	$	235
(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.

9.  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 7% and adjusted for inflation using a rate of 2%.  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.

FASB Accounting Standards establish 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 period ended September 30, 2011 and the year ended December 31, 2010 are presented in the following table:

	Nine Months Ended			Year Ended
Thousands of dollars	September 30, 2011			December 31, 2010
Carrying amount, beginning of period	$	47,429		$	36,635
Additions (a)	135			509
Liabilities settled in the current period	(3,015		)	(1,952		)
Revisions (b)	—			9,611
Accretion expense	2,534			2,626
Carrying amount, end of period	$	47,083		$	47,429
(a) 2011 additions reflect asset retirement obligations incurred in the Greasewood Acquisition.
(b) Changes to cost estimates and revisions to reserve life.

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10.  Partners’ Equity

On February 11, 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25 per Common Unit, resulting in proceeds net of underwriting discount and expenses of $100.2 million, which we used to repay outstanding debt under our credit facility.

During the first nine months of 2011, approximately 0.1 million Common Units were issued to employees and outside directors pursuant to vested grants under our First Amended and Restated 2006 Long Term Incentive Plan ("LTIP").

At September 30, 2011 and December 31, 2010, we had approximately 59.0 million and 54.0 million Common Units outstanding, respectively.  At September 30, 2011 and December 31, 2010, there were approximately 3.1 million and 2.6 million, respectively, of units outstanding under our LTIP that were eligible to be paid in Common Units upon vesting.

Cash Distributions

On February 11, 2011, we paid a cash distribution of approximately $22.4 million to our common unitholders of record as of the close of business on February 8, 2011. The distribution that was paid to unitholders was $0.4125 per Common Unit.

On May 13, 2011, we paid a cash distribution of approximately $24.6 million to our common unitholders of record as of the close of business on May 10, 2011. The distribution that was paid to unitholders was $0.4175 per Common Unit.

On August 12, 2011, we paid a cash distribution of approximately $24.9 million to our common unitholders of record as of the close of business on August 9, 2011. The distribution that was paid to unitholders was $0.4225 per Common Unit.

During the three months and nine months ended September 30, 2011, we also paid $1.3 million and $3.8 million, respectively, 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 LTIP.

Earnings per Unit

FASB Accounting Standards require 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 net income (loss) per common unit.

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The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Thousands, except per unit amounts	2011		2010			2011		2010
Net income (loss) attributable to the partnership	$	178,181	$	(5,754	)	$	140,889	$	105,654
Distributions on participating units not expected to vest	25		15			26		15
Net income (loss) attributable to common unitholders and participating securities	$	178,206	$	(5,739	)	$	140,915	$	105,669
Weighted average number of units used to calculate basic and diluted income per unit:
Common Units	59,040		53,303			58,297		53,297
Participating securities	3,015		—			2,976		3,442
Denominator for basic income per common unit (a)	62,055		53,303			61,273		56,739
Dilutive units (b)	136		—			133		133
Denominator for diluted income per common unit	62,191		53,303			61,406		56,872
Net income (loss) per common unit
Basic	$	2.87	$	(0.11	)	$	2.30	$	1.86
Diluted	$	2.87	$	(0.11	)	$	2.29	$	1.86
(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 excludes 3,504 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
(b) The three months ended September 30, 2010 excludes 144 weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit.

11.  Noncontrolling Interest

FASB Accounting Standardsrequire that noncontrolling interests be classified as a component of equity and establish 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%) of BEPI from TIFD X-III LLC.  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 each of September 30, 2011 and December 31, 2010, the amount of this noncontrolling interest was $0.5 million.  For the three months and nine months ended September 30, 2011, 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, 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. 

12.  Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months and nine months ended September 30, 2011 was $5.4 million and $16.3 million, respectively, and for the three months and nine months ended September 30, 2010 was $5.5 million and $15.4 million, respectively.

During the nine months ended September 30, 2011, the board of directors of BreitBurn GP, LLC (our "General Partner") approved the grant of approximately 745,000 RPUs to employees of BreitBurn Management under our LTIP.  Our outside directors were issued approximately 50,000 RPUs under our LTIP during the nine months ended September 30, 2011.  The fair market value of the RPUs granted during 2011 for computing compensation expense under FASB Accounting Standards averaged $21.66 per unit.

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For the nine months ended September 30, 2011, we paid $1.4 million for taxes withheld on RPUs vested during the period.  For the nine months ended September 30, 2010, we paid $0.9 million for taxes withheld on RPUs vested during the period.

For the three months and nine months ended September 30, 2011, we paid $1.3 million and $3.8 million, respectively, at a rate equal to the distributions paid to our unitholders, to holders of unvested RPUs and CPUs. For the three months and nine months ended September 30, 2010, we paid $1.4 million and $2.7 million, respectively, at a rate equal to the distributions paid to our unitholders, to holders of unvested RPUs and CPUs.

As of September 30, 2011, we had $27.8 million of total unrecognized compensation costs for all outstanding plans.  This amount is expected to be recognized over the period from October 1, 2011 to December 31, 2013. For detailed information on our various compensation plans, see Note 18 to the consolidated financial statements included in our Annual Report.

13.  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, 2011 and December 31, 2010, we had surety bonds for $21.5 million and $15.1 million, respectively.  At each of September 30, 2011 and December 31, 2010, we had approximately $0.3 million in letters of credit outstanding.

14.  Subsequent Events

On October 5, 2011, in connection with the completion of the Cabot Acquisition, we entered into the Fourth Amendment (the "Fourth Amendment") to the Second Amended and Restated Credit Agreement. The Fourth Amendment provides for an increase in the volume of permitted gas imbalances under the Credit Agreement from 300 MMcf to 1,000 MMcf. On October 6, 2011, we completed the Cabot Acquisition, pursuant to the terms and conditions of the Purchase Agreement, in exchange for $283 million in cash, subject to ordinary adjustments.

On October 11, 2011, our borrowing base was redetermined at $850 million, primarily as a result of an increase in oil and natural gas reserves due to the re-evaluation of existing reserves and the additional reserves associated with the Greasewood Acquisition.

On October 28, 2011, we announced a cash distribution to unitholders for the third quarter of 2011 at the rate of $0.4350 per Common Unit, to be paid on November 14, 2011 to our common unitholders of record as of the close of business on November 9, 2011.

In October 2011, in order to improve the effectiveness of our hedge portfolio, we terminated the following crude oil fixed price swaps at NYMEX WTI prices for a total termination cost of $33.8 million and entered into new crude oil fixed price swaps for the same volumes and periods at IPE Brent prices:

Period	NYMEX WTI $/Bbl		IPE Brent $/Bbl		Volume Bbl/d
January 1, 2012 to December 31, 2012	$	63.30	$	105.75	1,939
January 1, 2012 to June 30, 2012	79.55		106.20		600
January 1, 2012 to December 31, 2013	84.30		103.50		400
January 1, 2013 to December 31, 2013	83.60		92.65		500
January 1, 2013 to December 31, 2013	80.10		92.10		500
January 1, 2013 to December 31, 2013	80.15		94.25		500
January 1, 2013 to December 31, 2013	75.85		94.00		500
January 1, 2013 to December 31, 2013	77.85		100.60		500
January 1, 2013 to December 31, 2013	70.00		101.00		1,000
January 1, 2014 to December 31, 2014	81.05		89.25		500

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In October 2011, we entered into the following natural gas derivative contracts:

Fixed price swaps	NYMEX Henry Hub $/MMBtu		Volume MMBtu/d
Period
January 1, 2013 to December 31, 2015	$	5.01	3,000

Calls	NYMEX Henry Hub $/MMBtu		Volume MMBtu/d	Deferred Premium $/MMBtu
Period
January 1, 2013 to December 31, 2013	$	8.00	30,000	$	0.0815
January 1, 2014 to December 31, 2014	9.00		15,000	0.1200

On November 7, 2011, The Baupost Group, L.L.C. (“Baupost”) informed us that it had sold all of its remaining Common Units.  On May 10, 2011, Baupost had filed an Amended Statement of Beneficial Ownership on Form SC 13G/A reporting that it owned 2.5 million Common Units.

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Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis in conjunction with Management’s Discussion and Analysis in Part II—Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010 (the "Annual Report") and the consolidated financial statements and related notes therein.  Our Annual Report contains a discussion of other matters not included herein, such as disclosures regarding critical accounting policies and estimates and contractual obligations.  You should also read the following discussion and analysis together with Part II—Item 1A "—Risk Factors" of this report, Part II—Item 1A "—Risk Factors" of our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011, the "Cautionary Statement Regarding Forward Looking Information" in this report and in our Annual Report and Part I—Item 1A "—Risk Factors" of our Annual Report.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States.  Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in the Antrim Shale and other formations in Northern Michigan, the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Greasewood Field in eastern Wyoming, the Evanston and Green River Basins in southwestern Wyoming, the Sunniland Trend in Florida and the New Albany Shale in Indiana and Kentucky.

Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders.  On August 12, 2011, we paid a cash distribution to unitholders for the second quarter of 2011 at the rate of $0.4225 per Common Unit. On October 28, 2011, we announced a cash distribution to unitholders for the third quarter of 2011 at the rate of $0.4350 per Common Unit. We expect to pay the cash distribution on November 14, 2011.

Our core investment strategies include:

• Acquire long-lived assets with low-risk exploitation and development opportunities;

• Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;

• Reduce cash flow volatility through commodity price and interest rate derivatives; and

• Maximize asset value and cash flow stability through our operating and technical expertise.

Consistent with our long-term business strategy, we have completed two acquisitions this year and will continue to actively pursue oil and natural gas acquisition opportunities in 2011.

2011 Acquisitions

On July 28, 2011, we completed the Greasewood Acquisition to acquire crude oil properties in Niabrara County, Wyoming with an effective date of July 1, 2011. The purchase price for the acquisition was approximately $57 million in cash. We used borrowings under our credit facility to fund the Greasewood Acquisition. The properties produced approximately 550 Boe/d net in September 2011 and are 100% oil.

On October 6, 2011, we completed the Cabot Acquisition to acquire oil and gas properties located primarily in the Evanston and Green River Basins in southwestern Wyoming for approximately $283 million in cash, subject to ordinary adjustments. We used borrowings under our credit facility to fund the Cabot Acquisition. The Cabot Assets also include limited acreage and non-operated oil and gas interests in Colorado and Utah. These properties are 95% natural gas.

Operational Focus and Capital Expenditures

 In the first nine months of 2011, our oil and natural gas capital expenditures totaled $59 million, compared to approximately $53 million in the first nine months of 2010.  We spent approximately $26 million in Florida, $18 million in Michigan, Indiana and Kentucky, $8 million in California and $7 million in Wyoming.  In the first nine months of 2011, we drilled and completed 23 wells in Michigan, seven wells in Wyoming, three wells in Florida and three wells in California.  We also completed 31 well optimization projects in Michigan, five in California and three in Wyoming as well as three facility optimization projects in Michigan and one in Indiana.

In 2011, our crude oil and natural gas capital spending program, including expenditures related to the Greasewood and Cabot assets, is expected to be approximately $80 million, compared with approximately $70 million in 2010. We anticipate spending approximately 70% in California, Florida and Wyoming and approximately 30% in Michigan, Indiana and Kentucky.

27

We expect to drill or re-drill approximately 40 wells, with 75% of our total capital spending focused on drilling and rate generating projects that are designed to increase or add to production or revenues. We expect production to be approximately 7.0 MMBoe in 2011.

Commodity Prices

In the third quarter of 2011, the WTI spot price averaged $89 per barrel, compared with approximately $76 per barrel in the third quarter of 2010.  In the first nine months of 2011, the WTI spot price averaged $95 per barrel, compared with approximately $78 per barrel a year earlier.  The average WTI spot price in October 2011 was approximately $86 per barrel.  In 2010, the WTI spot price averaged approximately $79 per barrel.

In the third quarter of 2011, the NYMEX wholesale natural gas price averaged $4.06 per MMBtu compared with approximately $4.24 per MMBtu in the third quarter of 2010.  In the first nine months of 2011, the NYMEX wholesale natural gas price averaged $4.21 per MMBtu, compared with approximately $4.52 per MMBtu a year earlier. The average NYMEX wholesale natural gas price in October 2011 was approximately $3.62 per MMBtu.  In 2010, the NYMEX wholesale natural gas price averaged $4.38 per MMBtu and ranged from a low of $3.29 per MMBtu to a high of $6.01 per MMBtu.

Hedge Terminations

In October, we terminated certain crude oil fixed price swaps at NYMEX WTI prices for $33.8 million and entered into new crude oil fixed price swaps at IPE Brent prices.  The new crude oil swaps were entered into to mitigate future price volatility associated with our California production for the next three years.  Historically, WTI oil prices and Brent oil prices have fluctuated together, but recently WTI and Brent oil prices have diverged.  Management believes that Brent pricing will better correlate with local California prices received by us.

BreitBurn Management

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 manages the operations of BEC, our predecessor, and provides administrative services to BEC under an administrative services agreement. These services include operational functions such as exploitation and technical services, petroleum and reserves engineering and executive management, and administrative services such as accounting, information technology, audit, human resources, land, business development, finance and legal. These services are provided 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 2011, the monthly fee paid by BEC for indirect expenses is approximately $481,000.

We have been informed that the owners of BEC may seek to sell certain of the assets of BEC located in the Orcutt Field in Santa Barbara County and the West Pico Field in Los Angeles County in California. BEC's assets consist primarily of producing and non-producing crude oil reserves located in Santa Barbara, Los Angeles and Orange Counties in California.

In the event that BEC is sold to an unaffiliated third party that elects to have the BEC assets managed and operated by an entity other than BreitBurn Management, certain direct and indirect general and administrative expenses at BreitBurn Management that are currently reimbursed by BEC, will be borne by us. Our management has conducted a preliminary review of the likely impact of a third party sale of BEC and believes, absent workforce or other reductions, the Partnership would incur as much as $6.4 million annually in additional general and administrative expenses. These expenses consist primarily of costs related to employees who provide services to both us and BEC. Over time, we expect to be able to absorb a substantial portion of these costs through our ongoing acquisition activity.

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Results of Operations

The table below summarizes certain of the results of operations for the periods indicated.  The data for the periods reflect our results as they are presented in our unaudited consolidated financial statements included elsewhere in this report.

	Three Months Ended September 30,					Increase/					Nine Months Ended September 30,				Increase/
Thousands of dollars, except as indicated	2011		2010			Decrease			%		2011		2010		Decrease			%
Total production (MBoe)	1,681		1,741			(60		)	(3	)%	4,972		4,999		(27		)	(1	)%
Oil and NGLs (MBoe)	829		827			2			—	%	2,384		2,366		18			1	%
Natural gas (MMcf)	5,114		5,486			(372		)	(7	)%	15,529		15,799		(270		)	(2	)%
Average daily production (Boe/d)	18,273		18,927			(654		)	(3	)%	18,212		18,311		(99		)	(1	)%
Sales volumes (MBoe)	1,723		1,680			43			3	%	5,026		4,999		27			1	%
Average realized sales price (per Boe) (a) (b)	$	61.08	$	59.32		$	1.76		3	%	$	59.09	$	58.59	$	0.50		1	%
Oil and NGLs (per Boe) (a) (b)	81.50		76.14			5.36			7	%	78.28		72.84		5.44			7	%
Natural gas (per Mcf) (a)	6.72		7.55			(0.83		)	(11	)%	6.83		7.63		(0.80		)	(10	)%
Oil, natural gas and NGLs sales (c)	$	97,356	$	77,055		$	20,301		26	%	$	284,673	$	239,603	$	45,070		19	%
Realized gain on commodity derivative instruments	8,092		22,567			(14,475		)	(64	)%	12,784		53,148		(40,364		)	(76	)%
Unrealized gain (loss) on commodity derivative instruments	170,734		(30,540		)	201,274			n/a		106,348		42,594		63,754			150	%
Other revenues, net	1,375		719			656			91	%	3,416		1,838		1,578			86	%
Total revenues	277,557		69,801			207,756			n/a		407,221		337,183		70,038			21	%
Lease operating expenses and processing fees	36,409		28,800			7,609			26	%	94,489		88,918		5,571			6	%
Production and property taxes (d)	6,689		5,081			1,608			32	%	18,653		14,884		3,769			25	%
Total lease operating expenses	43,098		33,881			9,217			27	%	113,142		103,802		9,340			9	%
Transportation expenses	1,426		1,037			389			38	%	3,859		3,115		744			24	%
Purchases and other operating costs	329		90			239			n/a		751		216		535			n/a
Change in inventory	1,593		(1,801		)	3,394			n/a		1,713		1,296		417			32	%
Total operating costs	$	46,446	$	33,207		$	13,239		40	%	$	119,465	$	108,429	$	11,036		10	%
Lease operating expenses pre taxes per Boe (e)	$	21.66	$	16.54		$	5.12		31	%	$	19.00	$	17.79	$	1.21		7	%
Production and property taxes per Boe	3.98		2.92			1.06			36	%	3.75		2.98		0.77			26	%
Total lease operating expenses per Boe	25.64		19.46			6.18			32	%	22.75		20.77		1.98			10	%
Depletion, depreciation and amortization (DD&A)	$	26,688	$	23,636		$	3,052		13	%	$	76,354	$	69,599	$	6,755		10	%
DD&A per Boe	15.88		13.58			2.30			17	%	15.36		13.92		1.44			10	%
(a) Includes realized gain on commodity derivative instruments.
(b) Includes crude oil purchases. 2010 excludes amortization of an intangible asset related to crude oil sales contracts.
(c) The three months and nine months ended September 30, 2010 include approximately $124 and $371, respectively, of amortization of an intangible asset related to crude oil sales contracts.
(d) Includes ad valorem and severance taxes.
(e) Includes lease operating expenses, district expenses and processing fees.

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Comparison of Results for the Three Months and Nine Months Ended September 30, 2011 and 2010

The variances in our results were due to the following components:

Production

For the three months ended September 30, 2011, production was 1,681 MBoe compared to 1,741 MBoe for the same period a year ago, primarily due to a decrease in Michigan natural gas production, partially offset by higher Wyoming crude oil production.

For the nine months ended September 30, 2011, production was approximately 27 MBoe lower than the same period a year ago. The decrease in production was primarily due to lower Michigan natural gas production and lower California crude oil production, primarily due to natural field declines, partially offset by higher crude oil production from the new wells in Florida and higher Wyoming crude oil production.

Revenues

Total oil, natural gas liquids ("NGLs") and natural gas sales revenues increased $20.3 million in the three months ended September 30, 2011 compared to the three months ended September 30, 2010. Crude oil and NGLs revenues increased $24.1 million due to higher crude oil prices and higher sales volumes, primarily due to two Florida sales during the three months ended September 30, 2011 compared to one Florida sale during the three months ended September 30, 2010. Natural gas revenues were $3.8 million lower primarily due to lower natural gas prices and lower natural gas sales volumes.

Realized gains from commodity derivative instruments during the three months ended September 30, 2011 were $8.1 million compared to realized gains of $22.6 million during the three months ended September 30, 2010, primarily due to higher crude oil prices during the three months ended September 30, 2011 compared to the three months ended September 30, 2010.   

Unrealized gains on commodity derivative instruments during the three months ended September 30, 2011 were $170.7 million compared to unrealized losses of $30.5 million during the three months ended September 30, 2010.  Unrealized gains during the three months ended September 30, 2011 were primarily due to a decrease in crude oil futures prices and the effect those prices had on the valuation of our derivative contracts, compared to an increase in crude oil futures prices during the three months ended September 30, 2010. Natural gas unrealized gains were lower primarily due to a smaller decrease in natural gas futures prices during the three months ended September 30, 2011 compared to the decrease during the three months ended September 30, 2010.

Realized prices for crude oil and NGLs, including realized gains and losses on crude oil derivative instruments, increased $5.36 per Boe, or 7%, in the three months ended September 30, 2011 compared to the three months ended September 30, 2010. Realized prices for natural gas, including realized gains and losses on natural gas derivative instruments, decreased $0.83 per Mcf, or 11%, in the three months ended September 30, 2011 compared to the three months ended September 30, 2010.

Total oil, NGLs and natural gas sales revenues increased $45.1 million in the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. Crude oil and NGLs revenue increased $52.6 million due to higher crude oil prices and slightly higher sales volumes. Natural gas revenues decreased $7.5 million primarily due to lower natural gas prices and slightly lower natural gas sales volumes.

Realized gains from commodity derivative instruments during the nine months ended September 30, 2011 were $12.8 million compared to realized gains of $53.1 million during the nine months ended September 30, 2010.  Lower realized gains compared to the nine months ended September 30, 2010 were primarily due to higher crude oil prices during the nine months ended September 30, 2011.

Unrealized gains on commodity derivative instruments during the nine months ended September 30, 2011 were $106.3 million compared to unrealized gains of $42.6 million during the nine months ended September 30, 2010.  Unrealized gains on crude oil derivative instruments increased $117.4 million due to a decrease in crude oil futures prices during the nine months ended September 30, 2011. This increase was partially offset by a $53.6 million decrease in unrealized gains on natural gas derivative instruments due to a smaller decrease in natural gas futures prices during 2011 compared to the significant decrease in natural gas futures prices during the nine months ended September 30, 2010. 

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Realized prices for crude oil and NGLs, including realized gains and losses on crude oil derivative instruments, increased $5.44 per Boe, or 7%, in the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010. Realized prices for natural gas, including realized gains and losses on natural gas derivative instruments, decreased $0.80 per Mcf, or 10%, in the nine months ended September 30, 2011 compared to the nine months ended September 30, 2010.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses and processing fees, for the three months ended September 30, 2011 increased $7.6 million compared to the three months ended September 30, 2010.  On a per Boe basis, pre-tax lease operating expenses were $21.66 per Boe for the three months ended September 30, 2011 compared to $16.54 per Boe for the three months ended September 30, 2010.  The per Boe increase was primarily attributable to the scheduling of maintenance activities in the third quarter to avoid higher winter month costs, the upward pressure on the cost of services and materials from higher crude oil prices, and higher Florida expenses from the addition of new wells.

Production and property taxes for the three months ended September 30, 2011 totaled $6.7 million, which was $1.6 million higher than the three months ended September 30, 2010, primarily due to higher Wyoming and Florida production taxes attributable to higher crude oil prices during the three months ended September 30, 2011.  On a per Boe basis, production and property taxes for the three months ended September 30, 2011 were $3.98 per Boe, which was 36% higher than the three months ended September 30, 2010.

Pre-tax lease operating expenses, including district expenses and processing fees, for the nine months ended September 30, 2011 increased $5.6 million compared to the nine months ended September 30, 2010.  On a per Boe basis, pre-tax lease operating expenses were $19.00 per Boe for the nine months ended September 30, 2011 compared to $17.79 per Boe for the nine months ended September 30, 2010.  The per Boe increase was primarily attributable to higher Florida and Michigan expenses related to well services, repairs and compressor maintenance, partially offset by lower California well services and maintenance.

Production and property taxes for the nine months ended September 30, 2011 totaled $18.7 million, which was $3.8 million higher than the nine months ended September 30, 2010, primarily due to higher production taxes attributable to higher crude oil prices during the nine months ended September 30, 2011.  On a per Boe basis, production and property taxes for the nine months ended September 30, 2011 were $3.75 per Boe, which was 26% higher than the nine months ended September 30, 2010.

Transportation expenses

In Florida, our crude oil sales are transported from the field by trucks and pipeline and then transported by barge to the sale point.  Transportation costs incurred in connection with such operations are reflected in operating costs on the consolidated statements of operations.  

During the three months ended September 30, 2011 and 2010, transportation costs totaled $1.4 million and $1.0 million, respectively.  The increase in transportation costs was primarily due to two Florida sales during the three months ended September 30, 2011 compared to one during the three months ended September 30, 2010.

During the nine months ended September 30, 2011 and 2010, transportation costs totaled $3.9 million and $3.1 million, respectively.  The increase in transportation costs was primarily due to five Florida sales during the nine months ended September 30, 2011 compared to four Florida sales during the nine months ended September 30, 2010.

Change in inventory

In Florida, our 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.  Sales occur on average every six to eight weeks.  We match production expenses with crude oil sales.  Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account.  Production expenses are charged to operating costs through the change in inventory account when they are sold.  

For the three months ended September 30, 2011 and 2010, the change in inventory account amounted to a charge of $1.6 million and a credit of $1.8 million, respectively.  The charge to inventory during the three months ended September 30, 2011 reflected the higher amount of barrels sold than produced during the period and the credit to inventory during the three months ended September 30, 2010 reflected the higher amount of barrels produced than sold, due to the timing of Florida sales.

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For the nine months ended September 30, 2011 and 2010, the change in inventory account amounted to a charge of $1.7 million and $1.3 million, respectively.  The charge to inventory during the nine months ended September 30, 2011 reflected the higher amount of barrels sold than produced during the period. The charge during the nine months ended September 30, 2010 reflected higher production costs for sold inventory during the period.

Depletion, depreciation and amortization

Depletion, depreciation and amortization expense ("DD&A") totaled $26.7 million, or $15.88 per Boe, during the three months ended September 30, 2011, an increase of approximately 17% per Boe from the same period a year ago.  DD&A totaled $76.4 million, or $15.36 per Boe, during the nine months ended September 30, 2011, an increase of approximately 10% per Boe from the same period a year ago. The increase in DD&A compared to last year was primarily due to DD&A rate adjustments in 2011 related to lower natural gas reserves reflecting lower natural gas prices and higher Florida DD&A rates reflecting investment additions related to the new wells.

General and administrative expenses

Our general and administrative ("G&A") expenses totaled $14.0 million and $12.7 million for the three months ended September 30, 2011 and 2010, respectively.  This included $5.4 million and $5.5 million, respectively, in non-cash unit-based compensation expense related to employee incentive plans.  G&A expenses, excluding non-cash unit-based compensation, were $8.6 million and $7.2 million for the three months ended September 30, 2011 and 2010, respectively.  The increase was primarily due to $1.0 million of acquisition related costs, including legal and other professional services.

G&A expenses totaled $38.1 million and $34.0 million for the nine months ended September 30, 2011 and 2010, respectively.  This included $16.3 million and $15.4 million respectively, in non-cash unit-based compensation expense related to employee incentive plans. The increase in non-cash unit-based compensation expense was primarily due to new awards granted in the first three months of 2011 and the overall increase in the value of the new awards due to the increase in unit price between year-end and the grant date.  G&A expenses, excluding non-cash unit-based compensation, were $21.8 million and $18.6 million for the nine months ended September 30, 2011 and 2010, respectively.  The increase was primarily due to $1.0 million of acquisition related costs and higher employee related costs including salaries and wages for additional employees.

Interest expense, net of amounts capitalized

Our interest expense totaled $9.3 million and $5.1 million for the three months ended September 30, 2011 and 2010, respectively.  The increase in interest expense was primarily due to $6.6 million of interest related to the Senior Notes issued in October 2010, partially offset by $2.5 million lower interest expense on our credit facility due to a lower credit facility debt balance.  

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates.  See Note 3 to the consolidated financial statements within this report for a discussion of our interest rate derivative contracts.  We had realized losses of $1.1 million and $2.9 million for the three months ended September 30, 2011 and 2010, respectively, relating to our interest rate derivative contracts.  We had unrealized losses of less than $0.1 million and unrealized gains of $1.3 million for the three months ended September 30, 2011 and 2010, respectively, relating to our interest rate derivative contracts.

Interest expense, including realized losses on interest rate derivative contracts and excluding debt amortization and unrealized gains or losses on interest rate derivative contracts, totaled $9.3 million and $7.1 million for the three months ended September 30, 2011 and 2010, respectively. 

Our interest expense totaled $27.8 million and $13.8 million for the nine months ended September 30, 2011 and 2010, respectively.  The increase in interest expense was primarily due to $19.6 million of interest related to the Senior Notes issued in October 2010 and higher amortization of debt issuance costs, partially offset by $6.3 million lower interest expense on our credit facility due to a lower credit facility debt balance.  We had realized losses of $3.2 million and $8.8 million for the nine months ended September 30, 2011 and 2010, respectively, relating to our interest rate derivative contracts.  We had unrealized gains of $0.1 million and $3.5 million for the nine months ended September 30, 2011 and 2010, respectively, relating to our interest rate derivative contracts.

Interest expense, including realized losses on interest rate derivative contracts and excluding debt amortization and unrealized gains on interest rate derivative contracts, totaled $27.3 million and $19.7 million for the nine months ended September 30, 2011 and 2010, respectively. 

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Credit and Counterparty Risk

Our derivative financial instruments are exposed to credit risk from counterparties.  See Note 3 to the consolidated financial statements within this report for a discussion of our derivative contracts and counterparties.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations and amounts available under our revolving credit facility.  Our primary uses of cash have been for our operating expenses, capital expenditures, cash distributions to unitholders and unit repurchase transactions.  To fund certain acquisition transactions, we have historically accessed the private placement markets and have issued equity as partial consideration for the acquisition of oil and gas properties.  As market conditions have permitted, we have also engaged in asset sale transactions and equity and debt offerings.  In the future, we intend to access the public and private capital markets to fund certain acquisitions and refinancing transactions.

On July 28, 2011, we completed the Greasewood Acquisition, with an effective date of July 1, 2011. The purchase price for the acquisition was approximately $57 million in cash. We funded this acquisition with borrowings under our credit facility.

On October 6, 2011, we completed the Cabot Acquisition to acquire oil and gas properties located primarily in the Evanston and Green River Basins of Southwest Wyoming for approximately $283 million in cash, subject to ordinary adjustments. The Cabot Assets also include limited acreage and non-operated oil and gas interests in Colorado and Utah. These properties are 95% natural gas. Concurrent with the execution of the acquisition agreement on July 26, 2011, we paid a $14.3 million deposit to the seller, which deposit was applied toward the cash consideration due at closing. We funded the deposit and amount due at closing with borrowings under our credit facility. We may subsequently issue equity or debt to increase borrowing availability under our credit facility.

On October 11, 2011, our borrowing base was redetermined at $850 million, primarily as a result of an increase in oil and natural gas reserves due to the re-evaluation of existing reserves and the additional reserves associated with the Greasewood Acquisition.

Equity Offering

On February 11, 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25 per Common Unit, resulting in proceeds net of underwriting discount and expenses of $100.2 million, which we used to repay outstanding debt under our credit facility. The proceeds from the sale of Common Units were used to repay amounts outstanding under our credit facility.

Distributions

On February 11, 2011, we paid a cash distribution to unitholders for the fourth quarter of 2010 at the rate of $0.4125 per Common Unit. On May 13, 2011, we paid a cash distribution to unitholders for the first quarter of 2011 at the rate of $0.4175 per Common Unit. On August 12, 2011, we paid a cash distribution to unitholders for the second quarter of 2011 at the rate of $0.4225 per Common Unit. On October 28, 2011, we announced a cash distribution to unitholders for the third quarter of 2011 at the rate of $0.4350 per Common Unit. We expect to pay the cash distribution on November 14, 2011.

Cash Flows

Operating activities.  Our cash flow from operating activities for the nine months ended September 30, 2011 was $128.8 million, compared to $143.3 million for the nine months ended September 30, 2010. The decrease in cash flow from operating activities was primarily due to higher operating costs and higher overall cash interest expense.

Investing activities.  Net cash used in investing activities during the nine months ended September 30, 2011 and September 30, 2010 was $131.8 million and $47.7 million, respectively. The current year results included $57.4 million for the Greasewood Acquisition and a deposit of $14.3 million for the Cabot Acquisition. During the nine months ended September 30, 2011 and 2010, we spent $61.3 million and $46.4 million, respectively, on capital expenditures, primarily for drilling and completions.  

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Financing activities.  Net cash provided by financing activities for the nine months ended September 30, 2011 was $4.1 million and net cash used in financing activities for the nine months ended September 30, 2010 was $97.9 million.  We reduced our outstanding borrowings under our credit facility by approximately $17.0 million in the first nine months of 2011. We had total outstanding borrowings, net of unamortized discount on our Senior Notes, of $511.5 million at September 30, 2011 and $528.1 million at December 31, 2010.  For the nine months ended September 30, 2011, we issued $99.8 million in Common Units, made cash distributions of $75.7 million, borrowed $283.5 million and repaid $300.5 million under our credit facility.  For the nine months ended September 30, 2010, we made cash distributions of $43.0 million, borrowed $683.5 million and repaid $726.5 million under our credit facility.  

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 at a price of 98.358%. We received net proceeds of approximately $291.2 million (after deducting estimated fees and offering expenses) and used $290 million of the net proceeds to repay amounts outstanding under our credit facility. Interest on the Senior Notes is payable twice a year in April and October.

Credit Agreement

On May 7, 2010, BreitBurn Operating L.P., as borrower, and we and our wholly owned subsidiaries, as guarantors, Wells Fargo Bank National Association, as administrative agent, and the lenders party thereto, entered into the Second Amended and Restated Credit Agreement, a four-year, $1.5 billion revolving credit facility.

On May 9, 2011, we entered into the Second Amendment to the Second Amended and Restated Credit Agreement, which increased our borrowing base to $735 million and extended the maturity date to May 9, 2016. The Second Amendment also revised certain covenants in the credit facility, which included: eliminating the interest coverage ratio and the “borrowing base availability” test (applied prior to making distributions to unitholders or making other restricted payments); increasing the maximum leverage coverage ratio to 4.00 to 1.00 from 3.75 to 1.00; increasing our ability to incur or guaranty an additional $350 million of unsecured senior notes (subject to our borrowing base being reduced by 25% of the original stated principal amount of such new debt); and adjusting the pricing grid by decreasing the applicable margins (as defined in the Second Amended and Restated Credit Agreement) by 25 basis points. As of September 30, 2011 and December 31, 2010, we were in compliance with the credit facility's covenants.

On August 3, 2011, we entered into the Third Amendment to the Second Amended and Restated Credit Agreement, which permits us to hedge oil and gas volumes for properties for which we have entered into a purchase agreement prior to closing the transaction. The Third Amendment also provides that such hedges must be terminated in the event that the acquisition does not close within 90 days of the execution of such purchase agreement.

On October 5, 2011, in connection with the completion of the Cabot Acquisition, we entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement, which provides for an increase in the volume of permitted gas imbalances under the Credit Agreement from 300 MMcf to 1,000 MMcf.

On October 11, 2011, our borrowing base was redetermined at $850 million, primarily as a result of an increase in oil and natural gas reserves due to the re-evaluation of existing reserves and the additional reserves associated with the Greasewood Acquisition.

As of September 30, 2011 and November 7, 2011, we had $211.0 million and $511.0 million, respectively, in indebtedness outstanding under the Second Amended and Restated Credit Agreement. Our next semi-annual borrowing base redetermination is scheduled for April 2012.

As of September 30, 2011, the lending group under the Second Amended and Restated Credit Agreement included 15 banks.  Of the $735 million in total commitments under the credit facility, Wells Fargo Bank National Association held approximately 12.4% of the commitments.  Eleven banks held between 5% and 7.5% of the commitments, including Union Bank, N.A., Bank of Montreal, The Bank of Nova Scotia, Houston Branch, BNP Paribas, Citibank, N.A., Royal Bank of Canada, U.S. Bank National Association, Bank of Scotland plc, Barclays Bank PLC, The Royal Bank of Scotland plc and Credit Suisse AG, Cayman Islands Branch, with each of the remaining lenders holding less than 5% of the commitments.  In addition to our relationships with these institutions under the credit facility, from time to time we engage in other transactions with a number of these institutions.  Such institutions or their affiliates may serve as underwriter or initial purchaser of our debt and equity securities and/or serve as counterparties to our commodity and interest rate derivative agreements.

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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, we remain in compliance with all terms and conditions of our credit facility, including the leverage ratio (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. The Second Amended and Restated Credit Agreement also requires us to maintain a current ratio, as of the last day of each quarter, of not less than 1.00 to 1.00.

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, cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and BEPI and excluding income from our unrestricted entities and BEPI. All calculations of EBITDAX, for any applicable period during which a permitted acquisition or disposition is consummated, are determined on a pro forma basis as if such acquisition or disposition was consummated on the first day of such applicable period.

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% 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.

Contractual Obligations

Other than the Second and Third Amendments to the Second Amended and Restated Credit Agreement discussed above, we had no material changes to our financial contractual obligations during the nine months ended September 30, 2011.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of September 30, 2011 and December 31, 2010.  

Recently Issued Accounting Pronouncements

See Note 2 to the consolidated financial statements within this report for a discussion of recently issued accounting pronouncements.

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with Quantitative and Qualitative Disclosures About Market Risk included under Part II—Item 7A in our Annual Report.  Also, see Note 3 and Note 14 to the consolidated financial statements within this report for additional discussion related to our financial instruments, including a summary of our derivative contracts as of September 30, 2011.

Changes in Fair Value

The fair value of our outstanding oil and gas commodity derivative instruments was a net asset of approximately $139.8 million at September 30, 2011 and a net asset of approximately $33.5 million at December 31, 2010.  With a $5.00 per barrel increase in the price of oil, and a corresponding $1.00 per Mcf increase in natural gas, our net commodity derivative instrument asset at September 30, 2011 would have decreased by approximately $96 million. With a $5.00 per barrel decrease in the price of oil, and a corresponding $1.00 per Mcf decrease in natural gas, our net commodity derivative instrument asset at September 30, 2011 would have increased by approximately $112 million.

Price risk sensitivities were calculated by assuming across-the-board increases in price of $5.00 per barrel for oil and $1.00 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price.  In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative portfolio would typically change by less than the amounts given due to lower volatility in out-month prices.

The fair value of our outstanding interest rate derivative instruments was a net liability of approximately $4.7 million and $4.8 million at September 30, 2011 and December 31, 2010, respectively.  With a 1% increase in the LIBOR rate, our net interest rate derivative instrument liability at September 30, 2011 would have decreased by approximately $3 million. With a 1% decrease in the LIBOR rate to a minimum rate of zero, our net liability at September 30, 2011 would have increased by approximately $2 million.

Item 4.  Controls and Procedures

Controls and Procedures

We maintain disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our General Partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Our management, with the participation of our General Partner’s Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2011.  Based on that evaluation, our General Partner’s Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1.  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.  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 statutes to which we are subject.

Item 1A.  Risk Factors

There have been no material changes to the Risk Factors disclosed in Part I—Item 1A "—Risk Factors" of our Annual Report.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

There were no sales of unregistered equity securities during the period covered by this report.

Item 3.  Defaults Upon Senior Securities

None.

Item 4.  (Removed and Reserved)

Item 5.  Other Information

None.

Item 6.  Exhibits

NUMBER	DOCUMENT
3.1	First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
3.2	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
3.3	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2009).
3.4	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 1, 2009).
3.5	Amendment No.4 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.6	Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.7	Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
4.1	Registration Rights Agreement dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
4.2	First Amendment to Registration Rights Agreement between BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).

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NUMBER	DOCUMENT
4.3	Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors and U.S. National Bank Association as trustee, in connection with the private placement of the Notes. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
10.1	Asset Purchase Agreement, dated as of July 26, 2011, between Cabot Oil & Gas Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 29, 2011.
10.2	Third Amendment to the Second Amended and Restated Credit Agreement dated August 3, 2011 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-33055) filed on August 8, 2011.
10.3	Fourth Amendment to the Second Amended and Restated Credit Agreement dated October 5, 2011 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2011.
31.1*	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
101††	Interactive Data Files.

*    Filed herewith.

**    Furnished herewith. 

††    The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.

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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:	November 8, 2011	By:	/s/ Halbert S. Washburn
			Halbert S. Washburn
			Chief Executive Officer
Dated:	November 8, 2011	By:	/s/ James G. Jackson
			James G. Jackson
			Chief Financial Officer

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INDEX TO EXHIBITS

NUMBER	DOCUMENT
3.1	First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 16, 2006).
3.2	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on June 23, 2008).
3.3	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2009).
3.4	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on September 1, 2009).
3.5	Amendment No.4 to the First Amended and Restated Agreement of Limited Partnership of BreitBurn Energy Partners L.P. (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.6	Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC (incorporated herein by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
3.7	Amendment No. 1 to the Fourth Amended and Restated Limited Liability Company Agreement of BreitBurn GP, LLC dated as of December 30, 2010 (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-33055) filed on January 6, 2011).
4.1	Registration Rights Agreement dated as of November 1, 2007, by and among BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-33055) filed on November 6, 2007).
4.2	First Amendment to Registration Rights Agreement between BreitBurn Energy Partners L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on April 9, 2010).
4.3	Indenture, dated as of October 6, 2010, by and among BreitBurn Energy Partners L.P., BreitBurn Finance Corporation, the Guarantors and U.S. National Bank Association as trustee, in connection with the private placement of the Notes. (incorporated herein by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2010).
10.1	Asset Purchase Agreement, dated as of July 26, 2011, between Cabot Oil & Gas Corporation and BreitBurn Operating L.P. (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on July 29, 2011.
10.2	Third Amendment to the Second Amended and Restated Credit Agreement dated August 3, 2011 (incorporated herein by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-33055) filed on August 8, 2011.
10.3	Fourth Amendment to the Second Amended and Restated Credit Agreement dated October 5, 2011 (incorporated herein by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-33055) filed on October 7, 2011.
31.1*	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934 and Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Registrant’s Chief Executive Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Registrant’s Chief Financial Officer pursuant to Rule 13a-14(b) of the Securities Exchange Act of 1934 and 18 U.S.C. Section 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002.
101††	Interactive Data Files.

*    Filed herewith.

**    Furnished herewith. 

††    The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.

40