Breitburn Energy Partners LP - FORM 10-Q

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EX-32.1 - Breitburn Energy Partners LP	bbep-10qx33111ex321.htm
EX-31.1 - Breitburn Energy Partners LP	bbep-10qx33111xex311.htm
EX-10.1 - Breitburn Energy Partners LP	bbep-10qx33111xex101.htm
EX-31.2 - Breitburn Energy Partners LP	bbep-10qx33111xex312.htm
EX-32.2 - Breitburn Energy Partners LP	bbep-10qx33111xex322.htm

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 March 31, 2011



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 o No o (not yet applicable to registrant)

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 May 10, 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 March 31, 2011 and December 31, 2010	2
	– Unaudited Consolidated Statements of Operations for the Three Months Ended March 31, 2011 and 2010	3
	– Unaudited Consolidated Statements of Cash Flows for Three Months Ended March 31, 2011 and 2010	4
	– Notes to Consolidated Financial Statements	5

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 4.	Controls and Procedures	30

	PART II
	OTHER INFORMATION

Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults Upon Senior Securities	31
Item 4.	(Removed and Reserved)	31
Item 5.	Other Information	31
Item 6.	Exhibits	32

Signatures		33

INDEX

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 changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; 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 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.

INDEX

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Balance Sheets



Thousands	March 31, 2011			December 31, 2010
ASSETS
Current assets
Cash	$	6,177		$	3,630
Accounts and other receivables, net	51,587			53,520
Derivative instruments (note 3)	42,006			54,752
Related party receivables (note 4)	2,556			4,345
Inventory (note 5)	4,875			7,321
Prepaid expenses	5,899			6,449
Total current assets	113,100			130,017
Equity investments	7,803			7,700
Property, plant and equipment
Oil and gas properties	2,142,636			2,133,099
Other assets	11,163			10,832
	2,153,799			2,143,931
Accumulated depletion and depreciation	(445,446		)	(421,636		)
Net property, plant and equipment	1,708,353			1,722,295
Other long-term assets
Derivative instruments (note 3)	25,016			50,652
Other long-term assets	16,380			19,503

Total assets	$	1,870,652		$	1,930,167

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	28,029		$	26,808
Derivative instruments (note 3)	58,219			37,071
Revenue and royalties payable	17,059			16,427
Salaries and wages payable	3,938			12,594
Accrued liabilities	13,712			8,417
Total current liabilities	120,957			101,317

Credit facility (note 6)	113,000			228,000
Senior notes, net (note 6)	300,240			300,116
Deferred income taxes (note 8)	1,057			2,089
Asset retirement obligation (note 9)	46,734			47,429
Derivative instruments (note 3)	91,447			39,722
Other long-term liabilities	2,066			2,237
Total liabilities	675,501			720,910
Equity
Partners' equity (note 10)	1,194,702			1,208,803
Noncontrolling interest (note 11)	449			454
Total equity	1,195,151			1,209,257

Total liabilities and equity	$	1,870,652		$	1,930,167

Common units outstanding	59,040			53,957

See accompanying notes to consolidated financial statements.

INDEX

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Operations



	Three Months Ended
	March 31,
Thousands of dollars, except per unit amounts	2011			2010
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	92,575		$	80,469
Gain (loss) on commodity derivative instruments, net (note 3)	(106,177		)	52,065
Other revenue, net	898			632
Total revenues and other income items	(12,704		)	133,166
Operating costs and expenses
Operating costs	36,811			35,851
Depletion, depreciation and amortization	24,641			22,054
General and administrative expenses	12,471			11,257
Loss on sale of assets	14			115
Total operating costs and expenses	73,937			69,277

Operating income (loss)	(86,641		)	63,889

Interest expense, net of capitalized interest	9,420			3,617
(Gain) loss on interest rate swaps (note 3)	(343		)	2,243
Other income, net	(3		)	(25		)

Income (loss) before taxes	(95,715		)	58,054

Income tax expense (benefit) (note 8)	(1,002		)	144

Net income (loss)	(94,713		)	57,910

Less: Net income attributable to noncontrolling interest	(34		)	(71		)

Net income (loss) attributable to the partnership	$	(94,747	)	$	57,839

Basic net income (loss) per unit (note 10)	$	(1.67	)	$	1.02
Diluted net income (loss) per unit (note 10)	$	(1.67	)	$	1.02

See accompanying notes to consolidated financial statements.

INDEX

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows



	Three Months Ended
	March 31,
Thousands of dollars	2011			2010
Cash flows from operating activities
Net income (loss)	$	(94,713	)	$	57,910
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization	24,641			22,054
Unit-based compensation expense	5,437			4,883
Unrealized (gain) loss on derivative instruments	111,254			(40,610		)
Income from equity affiliates, net	(103		)	158
Deferred income taxes	(1,032		)	27
Amortization of intangibles	–			124
Loss on sale of assets	14			115
Other	257			824
Changes in net assets and liabilities
Accounts receivable and other assets	4,462			7,884
Inventory	2,446			(1,261		)
Net change in related party receivables and payables	1,789			(513		)
Accounts payable and other liabilities	(53		)	(6,960		)
Net cash provided by operating activities	54,399			44,635
Cash flows from investing activities
Capital expenditures	(12,735		)	(9,954		)
Net cash used in investing activities	(12,735		)	(9,954		)
Cash flows from financing activities
Issuance of common units	100,482			—
Distributions	(23,559		)	—
Proceeds from issuance of long-term debt	60,500			22,000
Repayments of long-term debt	(175,500		)	(58,000		)
Change in book overdraft	(1,003		)	878
Long-term debt issuance costs	(37		)	—
Net cash used in financing activities	(39,117		)	(35,122		)
Increase (decrease) in cash	2,547			(441		)
Cash beginning of period	3,630			5,766
Cash end of period	$	6,177		$	5,325

See accompanying notes to consolidated financial statements.

INDEX

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. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation of our financial position at March 31, 2011, our operating results for the three months ended March 31, 2011 and 2010, and our cash flows for the three months ended March 31, 2011 and 2010, have been included. Operating results for the three months ended March 31, 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.

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 our 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.

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.

INDEX

We had the following commodity derivative contracts in place at March 31, 2011:



	Year
	2011			2012		2013		2014		2015
Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbl/d)	5,151			5,039		6,480		5,000		2,000
Average Price ($/Bbl)	$	76.56		$	77.15	$	81.37	$	88.59	$	99.00
Participating Swaps: (a)
Hedged Volume (Bbl/d)	1,377			—		—		—		—
Average Price ($/Bbl)	$	60.00		—		—		—		—
Average Participation %	53.1		%	—		—		—		—
Collars:
Hedged Volume (Bbl/d)	2,231			2,477		500		1,000		1,000
Average Floor Price ($/Bbl)	$	103.79		$	110.00	$	77.00	$	90.00	$	90.00
Average Ceiling Price ($/Bbl)	$	153.06		$	145.39	$	103.10	$	112.00	$	113.50
Floors:
Hedged Volume (Bbl/d)	—			—		—		—		—
Average Floor Price ($/Bbl)	—			—		—		—		—
Total:
Hedged Volume (Bbl/d)	8,759			7,516		6,980		6,000		3,000
Average Price ($/Bbl)	$	80.89		$	87.97	$	81.06	$	88.83	$	96.00

Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)	20,282			19,128		37,000		7,500		5,000
Average Price ($/MMBtu)	$	6.78		$	7.10	$	6.50	$	6.00	$	6.00
Collars:
Hedged Volume (MMBtu/d)	20,282			19,129		—		—		—
Average Floor Price ($/MMBtu)	$	9.00		$	9.00	—		—		—
Average Ceiling Price ($/MMBtu)	$	11.13		$	11.89	—		—		—
Total:
Hedged Volume (MMBtu/d)	40,564			38,257		37,000		7,500		5,000
Average Price ($/MMBtu)	$	7.89		$	8.05	$	6.50	$	6.00	$	6.00

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

Interest Rate Activities

We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of March 31, 2011, our total debt outstanding under our credit facility was $113.0 million. In order to mitigate our interest rate exposure, we had the following interest rate derivative contracts in place at March 31, 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
April 1, 2011 to October 20, 2011	100,000	1.6200	%
April 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	%

INDEX

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 March 31, 2011
Assets
Current assets - derivative instruments	$	3,289		$	45,882		$	—		$	(7,165	)	$	42,006
Other long-term assets - derivative instruments	4,078			43,039			83			(22,184		)	25,016
Total assets	7,367			88,921			83			(29,349		)	67,022

Liabilities
Current liabilities - derivative instruments	(62,700		)	—			(2,684		)	7,165			(58,219		)
Long-term liabilities - derivative instruments	(112,356		)	(394		)	(881		)	22,184			(91,447		)
Total liabilities	(175,056		)	(394		)	(3,565		)	29,349			(149,666		)

Net assets (liabilities)	$	(167,689	)	$	88,527		$	(3,482	)	$	—		$	(82,644	)

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.

INDEX

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 March 31, 2011
Realized gain (loss)	$	(8,623	)	$	15,066		$	(1,023	)	$	5,420
Unrealized gain (loss)	(96,536		)	(16,084		)	1,366			(111,254		)
Net gain (loss)	$	(105,159	)	$	(1,018	)	$	343		$	(105,834	)

Three Months Ended March 31, 2010
Realized gain (loss)	$	308		$	11,838		$	(2,934	)	$	9,212
Unrealized gain (loss)	(2,511		)	42,430			691			40,610
Net gain (loss)	$	(2,203	)	$	54,268		$	(2,243	)	$	49,822

(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.
(b) Included in (gain) 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 March 31, 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 ended March 31, 2011.

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

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

INDEX

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 March 31, 2011 and December 31, 2010:



Thousands of dollars	Level 1		Level 2			Level 3		Total

As of March 31, 2011
Assets (liabilities):
Commodity derivatives (swaps, put and call options)	$	—	$	(148,233	)	$	69,071	$	(79,162	)
Other derivatives (interest rate swaps)	—		(3,482		)	—		(3,482		)
Total	$	—	$	(151,715	)	$	69,071	$	(82,644	)

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
	March 31,
Thousands of dollars	2011			2010
Assets:
Beginning balance	$	86,253		$	102,475
Realized gain (a)	4,725			4,975
Unrealized gain (loss) (a)	(21,907		)	1,266
Ending balance	$	69,071		$	108,716

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

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

Credit and Counterparty Risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of March 31, 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 March 31, 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 March 31, 2011, our largest derivative asset balances were with JP Morgan Chase Bank N.A., who accounted for approximately 86% of our derivative asset balance. As of March 31, 2011, our largest derivative liability balances were with Wells Fargo Bank National Association, BNP Paribas, Citibank, N.A and The Royal Bank of Scotland plc, who accounted for approximately 47%, 18%, 14% and 11% of our derivative liability balance, respectively.

INDEX

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 March 31, 2011 and December 31, 2010, we had current receivables of $1.5 million and $3.2 million, respectively, due from BEC related to the administrative services agreement, outstanding liabilities for employee related costs and oil and gas sales made by BEC on our behalf from certain properties. During the three months ended March 31, 2011, we received $1.4 million from BEC for direct charges related to our employee short-term incentive plan. During the three months ended March 31, 2011 and 2010, the monthly charges to BEC for indirect expenses totaled $1.4 million and $1.3 million, respectively, and charges for direct expenses including incentive compensation plan costs, direct payroll and administrative costs totaled $1.8 million and $2.4 million, respectively. For the three months ended March 31, 2011 and 2010, total oil and gas sales made by BEC on our behalf were approximately $0.5 million and $0.4 million, respectively.

At March 31, 2011 and December 31, 2010, we had receivables of $0.3 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.

Quicksilver Resources Inc. (“Quicksilver”) buys natural gas from us in Michigan. For the three months ended March 31, 2011 and 2010, total net gas sales to Quicksilver were approximately $1.3 million and $1.2 million, respectively. At March 31, 2011 and December 31, 2010, the related receivable was $0.8 million and $0.7 million, respectively.

5. Inventory

Our crude oil inventory from our Florida operations at March 31, 2011 and December 31, 2010 was $4.9 million and $7.3 million, respectively. In the three months ended March 31, 2011, we sold 253 gross MBbls and produced 186 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 March 31, 2011, the Senior Notes had a carrying value of $300.2 million, net of unamortized discount of $4.8 million. Interest on the Senior Notes is payable twice a year in April and October.

As of March 31, 2011, the fair value of the Senior Notes was estimated to be $319.1 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”) with respect to an 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.

INDEX

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”). The Second Amended and Restated Credit Agreement set our borrowing base at $735 million and will mature on May 7, 2014. On September 17, 2010, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which included a consent to the formation of a new wholly owned subsidiary, BreitBurn Collingwood Utica LLC (“Utica”), and its designation as an unrestricted subsidiary under our 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.

See Note 14 for a discussion of the Second Amendment to the Second Amended and Restated Credit Agreement, entered into on May 9, 2011, which extended the maturity date to May 9, 2016 and increased our borrowing base to $735 million. Our next borrowing base redetermination is scheduled for October 2011.

As of March 31, 2011 and December 31, 2010, we had $113.0 million and $228.0 million, respectively, in indebtedness outstanding under the credit facility. At March 31, 2011, the 1-month LIBOR interest rate plus an applicable spread was 2.260% on the 1-month LIBOR portion of $113.0 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.

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. As of March 31, 2011 and December 31, 2010, we were in compliance with the credit facility's covenants.

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.

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.

INDEX

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
	March 31,
Thousands of dollars	2011			2010
Credit agreement (including commitment fees)	$	1,690		$	2,793
Senior notes	6,503			—
Amortization of discount and deferred issuance costs	1,304			824
Capitalized interest	(77		)	—
Total	$	9,420		$	3,617

7. Condensed Consolidating Financials

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 March 31, 2011 and December 31, 2010, and for the three months ended March 31, 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”).

INDEX

Condensed Consolidating Balance Sheets



	As of March 31, 2011
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash	$	61		$	3,851		$	2,265		$	—		$	6,177
Accounts and other receivables, net	10,000			39,416			2,171			—			51,587
Derivative instruments	—			42,006			—			—			42,006
Related party receivables	—			2,556			—			—			2,556
Inventory	—			4,875			—			—			4,875
Prepaid expenses	879			5,020			—			—			5,899
Total current assets	10,940			97,724			4,436			—			113,100
Investments in subsidiaries	1,156,132			31,662			—			(1,187,794		)	—
Intercompany receivables (payables)	326,233			(323,470		)	(2,763		)	—			—
Equity investments	—			7,803			—			—			7,803

Property, plant and equipment
Oil and gas properties	8,467			2,084,839			49,330			—			2,142,636
Other assets	—			11,163			—			—			11,163
	8,467			2,096,002			49,330			—			2,153,799
Accumulated depletion and depreciation	(1,119		)	(431,972		)	(12,355		)	—			(445,446		)
Net property, plant and equipment	7,348			1,664,030			36,975			—			1,708,353
Other long-term assets
Derivative instruments	—			25,016			—			—			25,016
Other long-term assets	7,542			8,762			76			—			16,380

Total assets	$	1,508,195		$	1,511,527		$	38,724		$	(1,187,794	)	$	1,870,652

LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	13,103		$	13,594		$	1,332		$	—		$	28,029
Derivative instruments	—			58,219			—			—			58,219
Revenue and royalties payable	—			15,457			1,602			—			17,059
Salaries and wages payable	—			3,938			—			—			3,938
Accrued liabilities	—			12,994			718			—			13,712
Total current liabilities	13,103			104,202			3,652			—			120,957

Credit facility	—			113,000			—			—			113,000
Senior notes, net	300,240			—			—			—			300,240
Deferred income taxes	—			1,057			—			—			1,057
Asset retirement obligation	—			43,623			3,111			—			46,734
Derivative instruments	—			91,447			—			—			91,447
Other long-term liabilities	—			2,066			—			—			2,066
Total liabilities	313,343			355,395			6,763			—			675,501
Equity
Partners' equity	1,194,852			1,156,132			31,961			(1,188,243		)	1,194,702
Noncontrolling interest	—			—			—			449			449
Total equity	1,194,852			1,156,132			31,961			(1,187,794		)	1,195,151

Total liabilities and equity	$	1,508,195		$	1,511,527		$	38,724		$	(1,187,794	)	$	1,870,652

INDEX

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

INDEX

Condensed Consolidating Statements of Operations



	Three Months Ended March 31, 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	$	—		$	85,056		$	7,519		$	—		$	92,575
Loss on commodity derivative instruments, net	—			(106,177		)	—			—			(106,177		)
Other revenue, net	—			898			—			—			898
Total revenues and other income items	—			(20,223		)	7,519			—			(12,704		)
Operating costs and expenses:
Operating costs	—			34,385			2,426			—			36,811
Depletion, depreciation and amortization	105			23,892			644			—			24,641
General and administrative expenses	36			12,433			2			—			12,471
Loss on sale of assets	—			14			—			—			14
Total operating costs and expenses	141			70,724			3,072			—			73,937

Operating income (loss)	(141		)	(90,947		)	4,447			—			(86,641		)

Interest expense, net of capitalized interest	6,848			2,572			—			—			9,420
Gain on interest rate swaps	—			(343		)	—			—			(343		)
Other income, net	—			(2		)	(1		)	—			(3		)
Income (loss) before taxes	(6,989		)	(93,174		)	4,448			—			(95,715		)

Income tax expense (benefit)	(9		)	(995		)	2			—			(1,002		)

Net income (loss) before equity earnings	(6,980		)	(92,179		)	4,446			—			(94,713		)

Equity in earnings (losses) of subsidiaries	(87,779		)	4,400			—			83,379			—

Net income (loss)	(94,759		)	(87,779		)	4,446			83,379			(94,713		)

Less: Net income attributable to noncontrolling interest	—			—			—			(34		)	(34		)

Net income (loss) attributable to the partnership	$	(94,759	)	$	(87,779	)	$	4,446		$	83,345		$	(94,747	)

INDEX

Condensed Consolidating Statements of Operations



	Three Months Ended March 31, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated

Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$	—		$	74,499		$	5,970		$	—		$	80,469
Gain on commodity derivative instruments, net	—			52,065			—			—			52,065
Other revenue, net	—			632			—			—			632
Total revenues and other income items	—			127,196			5,970			—			133,166
Operating costs and expenses:
Operating costs	47			33,052			2,752			—			35,851
Depletion, depreciation and amortization	52			21,453			549			—			22,054
General and administrative expenses	142			11,103			12			—			11,257
Loss on sale of assets	—			115			—			—			115
Total operating costs and expenses	241			65,723			3,313			—			69,277

Operating income (loss)	(241		)	61,473			2,657			—			63,889

Interest expense, net	—			3,617			—			—			3,617
Loss on interest rate swaps	—			2,243			—			—			2,243
Other income, net	—			(24		)	(1		)	—			(25		)
Income (loss) before taxes	(241		)	55,637			2,658			—			58,054

Income tax expense (benefit)	(40		)	183			1			—			144

Net income (loss) before equity earnings	(201		)	55,454			2,657			—			57,910

Equity in earnings of subsidiaries	58,084			2,630			—			(60,714		)	—

Net income	57,883			58,084			2,657			(60,714		)	57,910

Less: Net income attributable to noncontrolling interest	—			—			—			(71		)	(71		)

Net income attributable to the partnership	$	57,883		$	58,084		$	2,657		$	(60,785	)	$	57,839

INDEX

Condensed Consolidating Statements of Cash Flows



	Three Months Ended March 31, 2011
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Combined Non-Guarantor Subsidiaries			Eliminations			Consolidated

Cash flows from operating activities
Net income (loss)	$	(94,759	)	$	(87,779	)	$	4,446		$	83,379		$	(94,713	)
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation and amortization	105			23,892			644			—			24,641
Unit-based compensation expense	—			5,437			—			—			5,437
Unrealized loss on derivative instruments	—			111,254			—			—			111,254
Income from equity affiliates, net	—			(103		)	—			—			(103		)
Equity in earnings of subsidiaries	87,779			(4,400		)	—			(83,379		)	—
Deferred income taxes	—			(1,032		)	—			—			(1,032		)
Loss on sale of assets	—			14			—			—			14
Other	344			(87		)	—			—			257
Changes in net assets and liabilities:
Accounts receivable and other assets	—			5,058			(596		)	—			4,462
Inventory	—			2,446			—			—			2,446
Net change in related party receivables and payables	—			1,789			—			—			1,789
Accounts payable and other liabilities	6,490			(6,918		)	375			—			(53		)
Net cash provided by (used in) operating activities	(41		)	49,571			4,869			—			54,399
Cash flows from investing activities
Capital expenditures	—			(12,379		)	(356		)	—			(12,735		)
Net cash used in investing activities	—			(12,379		)	(356		)	—			(12,735		)
Cash flows from financing activities
Issuance of common units	100,482			—			—			—			100,482
Distributions	(23,559		)	—			—			—			(23,559		)
Proceeds from the issuance of long-term debt	—			60,500			—			—			60,500
Repayments of long-term debt	—			(175,500		)	—			—			(175,500		)
Change in book overdraft	—			(1,003		)	—			—			(1,003		)
Long-term debt issuance costs	(18		)	(19		)	—			—			(37		)
Intercompany activity	(76,873		)	80,845			(3,972		)	—			—
Net cash provided by (used in) financing activities	32			(35,177		)	(3,972		)	—			(39,117		)

Increase (decrease) in cash	(9		)	2,015			541			—			2,547
Cash beginning of period	70			1,836			1,724			—			3,630
Cash end of period	$	61		$	3,851		$	2,265		$	—		$	6,177

INDEX

Condensed Consolidating Statements of Cash Flows



	Three Months Ended March 31, 2010
Thousands of dollars	Parent/ Co-Issuer			Combined Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Consolidated

Cash flows from operating activities
Net income	$	57,883		$	58,084		$	2,657		$	(60,714	)	$	57,910
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation and amortization	52			21,453			549			—			22,054
Unit-based compensation expense	—			4,883			—			—			4,883
Unrealized gain on derivative instruments	—			(40,610		)	—			—			(40,610		)
Income from equity affiliates, net	—			158			—			—			158
Equity in earnings of subsidiaries	(58,084		)	(2,630		)	—			60,714			—
Deferred income taxes	—			27			—			—			27
Amortization of intangibles	—			124			—			—			124
Loss on sale of assets	—			115			—			—			115
Other	—			824			—			—			824
Changes in net assets and liabilities:
Accounts receivable and other assets	—			7,734			150			—			7,884
Inventory	—			(1,261		)	—			—			(1,261		)
Net change in related party receivables and payables	—			(513		)	—			—			(513		)
Accounts payable and other liabilities	—			(7,179		)	219			—			(6,960		)
Net cash provided by (used in) operating activities	(149		)	41,209			3,575			—			44,635
Cash flows from investing activities
Capital expenditures	—			(9,953		)	(1		)	—			(9,954		)
Net cash used in investing activities	—			(9,953		)	(1		)	—			(9,954		)
Cash flows from financing activities
Proceeds from the issuance of long-term debt	—			22,000			—			—			22,000
Repayments of long-term debt	—			(58,000		)	—			—			(58,000		)
Change in book overdraft	—			878			—			—			878
Intercompany activity	43			3,416			(3,459		)	—			—
Net cash provided by (used in) financing activities	43			(31,706		)	(3,459		)	—			(35,122		)

Increase (decrease) in cash	(106		)	(450		)	115			—			(441		)
Cash beginning of period	149			4,917			700			—			5,766
Cash end of period	$	43		$	4,467		$	815		$	—		$	5,325

INDEX

8. Income Taxes

Our deferred income tax liability was $1.1 million and $2.1 million at March 31, 2011 and December 31, 2010, respectively. The following table presents our income tax expense/benefit for the three months ended March 31, 2011 and 2010, respectively:



	Three Months Ended
	March 31,
Thousands of dollars	2011			2010
Federal current tax expense	$	28		$	129
Deferred federal tax expense (benefit) (a)	(1,032		)	27
State income tax expense (benefit) (b)	2			(12		)
Total income tax expense (benefit)	$	(1,002	)	$	144

(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 periods ended March 31, 2011 and December 31, 2010 are presented in the following table:



	Three Months Ended			Year Ended
Thousands of dollars	March 31, 2011			December 31, 2010
Carrying amount, beginning of period	$	47,429		$	36,635
Additions	—			509
Liabilities settled in the current period	(1,525		)	(1,952		)
Revisions (a)	—			9,611
Accretion expense	830			2,626
Carrying amount, end of period	$	46,734		$	47,429

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

INDEX

10. Partners’ Equity

During the first three months of 2011, 137,582 Common Units were issued to employees and outside directors pursuant to vested grants under our long-term incentive compensation plan (“LTIP”).

At March 31, 2011 and December 31, 2010, we had 59,039,933 and 53,957,351 Common Units outstanding, respectively. At March 31, 2011 and December 31, 2010, there were 3,148,868 and 2,576,504, 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.

During the three months ended March 31, 2011, we also paid $1.2 million in cash at a rate equal to the distributions paid to our unitholders, to holders of outstanding unvested Restricted Phantom Units (“RPUs”), Convertible Phantom Units (“CPUs”) and Directors' units issued in 2011 (“2011 Directors' Units”) issued under our long-term incentive plan.

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, CPUs and 2011 Directors' Units participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as earnings per common unit.

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



	Three Months Ended
	March 31,
Thousands, except per unit amounts	2011			2010

Net income (loss) attributable to the partnership	$	(94,747	)	$	57,839
Distributions on participating units not expected to vest	—			—
Net income (loss) attributable to common unitholders and participating securities	$	(94,747	)	$	57,839

Weighted average number of units used to calculate basic and diluted earnings per unit:
Common Units	56,787			53,294
Participating securities	—			3,291
Denominator for basic earnings per common unit (a)	56,787			56,585
Dilutive units (b)	—			118
Denominator for diluted earnings per common unit	56,787			56,703
Net income (loss) per common unit
Basic	$	(1.67	)	$	1.02
Diluted	$	(1.67	)	$	1.02
(a) Basic earnings per unit is based on the weighted average number of Common Units outstanding plus the weighted average number of unvested RPUs, CPUs and 2011 Directors' Units. The three months ended March 31, 2011 excludes 2,888 unvested weighted average RPUs, CPUs and 2011 Directors' Units from participating securities, as we were in a loss position.
(b) The three months ended March 31, 2010 includes unvested dilutive units issued to directors under compensation plans. The three months ended March 31, 2011 excludes 131 of weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit.

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11. Noncontrolling Interest

FASB Accounting Standards require 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 March 31, 2011 and December 31, 2010, the amount of this noncontrolling interest was $0.4 million and $0.5 million, respectively. For the three months ended March 31, 2011 and 2010, we recorded net income attributable to the noncontrolling interest of less than $0.1 million in each period and dividends of less than $0.1 million in each period.

12. Unit and Other Valuation-Based Compensation Plans

Unit-based compensation expense for the three months ended March 31, 2011 and 2010 was $5.4 million and $4.9 million, respectively.

During the three months ended March 31, 2011, the board of directors of BreitBurn GP, LLC (our “General Partner”) approved the grant of 734,324 RPUs to employees of BreitBurn Management under our First Amended and Restated 2006 Long Term Incentive Plan. Our outside directors were issued 43,828 phantom units under our LTIP during the three months ended March 31, 2011. The fair market value of the RPUs granted during 2011 for computing compensation expense under FASB Accounting Standards averaged $21.68 per unit.

During the first three months of 2011, 118,771 Common Units were issued to employees pursuant to grants that vested under our LTIP and 18,811 Common Units were issued to outside directors for phantom units and distribution equivalent rights which were granted in 2008 and vested in January 2011. Common Units issued to employees under our LTIP are issued net of units withheld for payment of taxes.

For the three months ended March 31, 2011 and 2010, we paid $1.4 million and $0.8 million in cash, respectively, for taxes withheld on RPUs vested during each period. For the three months ended March 31, 2011 and 2010, we paid $1.2 million and nothing in cash, respectively, at a rate equal to the distribution paid to our unitholders, to holders of unvested RPUs and CPUs.

As of March 31, 2011, we had $38.5 million of total unrecognized compensation costs for all outstanding plans. This amount is expected to be recognized over the period from April 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 March 31, 2011 and December 31, 2010, we had various surety bonds for $15.0 million and $15.1 million, respectively. At March 31, 2011 and December 31, 2010, we had approximately $0.3 million in letters of credit outstanding.

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14. Subsequent Events

On April 28, 2011, we announced a cash distribution to unitholders for the first quarter of 2011 at the rate of $0.4175 per Common Unit, to be paid on May 13, 2011.

On May 3, 2011, we entered into a natural gas fixed price swap contract for 2,500 MMBtu/d for the year 2015 at $6.00 per MMBtu.

On May 9, 2011, we entered into the Second Amendment to the Second Amended and Restated Credit Agreement (the “Amendment”), which increased our borrowing base to $735 million and extended the maturity date to May 9, 2016. The 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.

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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, 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 objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. 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 Sunniland Trend in Florida and the New Albany Shale in Indiana and Kentucky.

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 operating and technical expertise.

Consistent with our long-term business strategy, we are actively pursuing oil and natural gas acquisition opportunities in 2011. In connection with that strategy, we have continued to pay down amounts outstanding under our credit facility by issuing new equity and incurring longer term unsecured debt. From time to time, we may also sell assets or monetize hedge positions to further increase our liquidity.

Quarterly Highlights

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 April 28, 2011, we announced a cash distribution to unitholders for the first quarter of 2011 at the rate of $0.4175 per Common Unit, to be paid on May 13, 2011.

Our first horizontal well in the Raccoon Point Field in Florida came on production in May 2010, and our second well in the same field came on production in early January 2011. In March 2011, the combined production from both wells was approximately 600 Bbl/d. A third well in the field was spud in late December 2010 and we are now production testing it. We anticipate it coming on full production by the end of the second quarter of 2011.

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Operational Focus and Capital Expenditures

In the first three months of 2011, our oil and natural gas capital expenditures totaled $9.4 million, compared to approximately $7.2 million in the first three months of 2010. We spent approximately $6.4 million in Florida, $1.8 million in Michigan, Indiana and Kentucky, $1.1 million in California and $0.1 million in Wyoming. In the first three months of 2011, we drilled and completed one well in Florida and completed one optimization project in California and one optimization project in Indiana.

In 2011, our crude oil and natural gas capital spending program excluding acquisitions is expected to be in the range of $70 million to $74 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. 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. Excluding acquisitions, we expect production to be approximately 6.5 MMBoe to 6.9 MMBoe in 2011.

Commodity Prices

In the first three months of 2011, the WTI spot price averaged $94 per barrel, compared with approximately $79 per barrel in the first three months of 2010. The average WTI spot price in April 2011 was approximately $110 per barrel. In 2010, the WTI spot price averaged approximately $79 per barrel.

In the first three months of 2011, the NYMEX wholesale natural gas price averaged $4.20 per MMBtu compared with approximately $4.99 per MMBtu in the first three months of 2010. The average NYMEX wholesale natural gas price in April 2011 was approximately $4.27 per MMBtu. During 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.

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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 March 31,						Increase /
Thousands of dollars, except as indicated	2011			2010			Decrease			%
Total production (MBoe)	1,629			1,595			34			2	%
Oil and NGL (MBoe)	773			727			46			6	%
Natural gas (MMcf)	5,138			5,207			(69		)	(1	)%
Average daily production (Boe/d)	18,098			17,725			373			2	%
Sales volumes (MBoe)	1,682			1,594			88			6	%

Average realized sales price (per Boe) (a) (b)	$	58.78		$	58.15		$	0.63		1	%
Oil and NGL (per Boe) (a) (b)	73.81			72.79			1.02			1	%
Natural gas (per Mcf) (a)	7.38			7.65			(0.27		)	(4	)%

Oil, natural gas and NGL sales (c)	$	92,575		$	80,469		$	12,106		15	%
Realized gain on commodity derivative instruments	6,443			12,146			(5,703		)	(47	)%
Unrealized gain (loss) on commodity derivative instruments	(112,620		)	39,919			(152,539		)	n/a
Other revenues, net	898			632			266			42	%
Total revenues	(12,704		)	133,166			(145,870		)	(110	)%

Lease operating expenses and processing fees	27,485			30,491			(3,006		)	(10	)%
Production and property taxes (d)	5,769			5,579			190			3	%
Total lease operating expenses	33,254			36,070			(2,816		)	(8	)%

Transportation expenses	1,423			847			576			68	%
Purchases	154			52			102			196	%
Change in inventory	1,980			(1,118		)	3,098			n/a
Total operating costs	$	36,811		$	35,851		$	960		3	%

Lease operating expenses pre taxes per Boe (e)	$	16.87		$	19.12		$	(2.25	)	(12	)%
Production and property taxes per Boe	3.54			3.50			0.04			1	%
Total lease operating expenses per Boe	20.41			22.62			(2.21		)	(10	)%

Depletion, depreciation and amortization (DD&A)	$	24,641		$	22,054		$	2,587		12	%
DD&A per Boe	15.13			13.83			1.30			9	%

(a) Includes realized gains on commodity derivative instruments.
(b) Includes crude oil purchases. 2010 excludes amortization of an intangible asset related to crude oil sales contracts.
(c) 2010 includes $124 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 Ended March 31, 2011 and 2010

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

Production

For the three months ended March 31, 2011, production was approximately 34 MBoe higher than the same period a year ago. The increase in production primarily reflected higher crude oil production from the new Raccoon Point wells in Florida partially offset by slightly lower California crude oil production due to natural field declines.

Revenues

Total oil, natural gas liquids (“NGL”) and natural gas sales revenues increased $12.1 million in the first three months of 2011 compared to the first three months of 2010. Crude oil and NGL revenue increased $17.3 million due to higher crude oil prices and higher sales volumes, primarily related to production from the new Raccoon Point wells in Florida. Natural gas revenue decreased $5.2 million primarily due to lower natural gas prices and slightly lower natural gas sales volumes.

Realized gains from commodity derivative instruments during the first three months of 2011 were $6.4 million compared to realized gains of $12.1 million in the first three months of 2010. Lower realized gains compared to the first quarter of 2010 were primarily due to higher crude oil prices, partially offset by lower natural gas prices.

Unrealized losses on commodity derivative instruments during the first three months of 2011 were $112.6 million compared to unrealized gains of $39.9 million in the first three months of 2010. Higher unrealized losses were primarily due to a significant increase in oil futures prices and the effect those prices had on the valuation of our derivative contracts during the first three months of 2011 compared to a smaller increase in oil futures prices during the first three months of 2010 and an increase in natural gas futures prices during the first three months of 2011 compared to a decrease in natural gas futures prices during the first three months of 2010.

Lease operating expenses

Pre-tax lease operating expenses, including district expenses and processing fees, for the first three months of 2011 decreased $3.0 million compared to the first three months of 2010. On a per Boe basis, pre-tax lease operating expenses were $16.87 per Boe for the first three months of 2011 compared to $19.12 per Boe for the first three months of 2010. The per Boe decrease was primarily attributable to lower repairs and maintenance in California and higher production in the first three months of 2011 compared to the first three months of 2010.

Production and property taxes for the first three months of 2011 totaled $5.8 million, which was $0.2 million higher than the first three months of 2010, primarily due to higher crude oil prices and higher production in the first three months of 2011. On a per Boe basis, production and property taxes for the first three months of 2011 were $3.54 per Boe, which was 1% higher than the first three months of 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. In the first three months of 2011 and 2010, transportation costs totaled $1.4 million and $0.8 million, respectively. The increase in transportation costs was primarily due to higher Florida sales volumes in the first three months of 2011 compared to the first three months of 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 first three months of 2011 and 2010, the change in inventory account amounted to a charge of $2.0 million and a credit of $1.1 million, respectively. The charge to inventory during the first three months of 2011 reflected the higher amount of barrels sold than produced during the period.

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Depletion, depreciation and amortization

Depletion, depreciation and amortization expense (“DD&A”) totaled $24.6 million, or $15.13 per Boe, in the first three months of 2011, an increase of approximately 9% 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.

General and administrative expenses

Our general and administrative (“G&A”) expenses totaled $12.5 million and $11.3 million for the three months ended March 31, 2011 and 2010, respectively. This included $5.4 million and $4.9 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. For the first three months of 2011 and 2010, G&A expenses, excluding non-cash unit-based compensation, were $7.1 million and $6.4 million, respectively. The increase was primarily due to salaries and wages for additional employees.

Interest expense, net of amounts capitalized

Our interest totaled $9.4 million and $3.6 million for the three months ended March 31, 2011 and 2010, respectively. The increase in interest expense was primarily due to $6.5 million of interest related to the Senior Notes issued in October 2010, and higher amortization of debt issuance costs, partially offset by a lower debt balance under our credit facility. 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 $1.0 million and $2.9 million for the three months ended March 31, 2011 and 2010, respectively, relating to our interest rate derivative contracts. We had unrealized gains of $1.4 million and $0.7 million for the three months ended March 31, 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 $9.1 million and $5.7 million for the three months ended March 31, 2011 and 2010, respectively.

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.

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Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations and amounts available under our revolving credit facility. Historically, 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 also 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 may look to the public and private capital markets to fund our acquisitions and refinancing transactions.

Equity Offering

On February 11, 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25, 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 use of proceeds from the sale of Common Units to repay amounts outstanding under our credit facility increased the borrowing availability under our credit facility, which gives us additional flexibility to finance future acquisitions.

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 April 28, 2011, we announced a cash distribution to unitholders for the first quarter of 2011 at the rate of $0.4175 per Common Unit, to be paid on May 13, 2011.

Cash Flows

Operating activities. Our cash flow from operating activities for the three months ended March 31, 2011 was $54.4 million, compared to $44.6 million for the three months ended March 31, 2010. The increase in cash flow from operating activities was primarily due to higher crude oil sales revenue related to higher sales volume and realized prices, as well as lower operating costs.

Investing activities. Net cash used in investing activities during the three months ended March 31, 2011 and March 31, 2010 was $12.7 million and $10.0 million, respectively, which was predominantly spent on drilling and completions. The three months ended March 31, 2011 included drilling related to the Raccoon Point wells in Florida.

Financing activities. Net cash used in financing activities for the three months ended March 31, 2011 and March 31, 2010 was $39.1 million and $35.1 million, respectively. We reduced our outstanding borrowings by approximately $114.9 million in the first three months of 2011. We had outstanding borrowings, net of unamortized discount on our Senior Notes, of $413.2 million at March 31, 2011 and $528.1 million at December 31, 2010. The reduction in our outstanding borrowings was primarily due to the use of the $100.2 million of net proceeds from the February 2011 issuance of Common Units to repay outstanding debt under our credit facility. For the three months ended March 31, 2011, we made cash distributions of $23.6 million, borrowed $60.5 million and repaid $175.5 million under our credit facility. For the three months ended March 31, 2010, we borrowed $22.0 million and repaid $58.0 million.

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

As of April 30, 2011, we had $121 million in indebtedness outstanding under our credit facility.

On May 9, 2011, we entered into the Second Amendment to the Second Amended and Restated Credit Agreement. Our next borrowing base redetermination is scheduled for October 2011.

As of May 9, 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

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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.

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 not exceeding 4.00 to 1.00 (which is total indebtedness to EBITDAX); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries. 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. As of March 31, 2011 and December 31, 2010, we were in compliance with the credit facility's covenants.

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.

Contractual Obligations

Other than the amendment to the credit agreement discussed above, we had no material changes to our financial contractual obligations during the three months ended March 31, 2011.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of March 31, 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 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 March 31, 2011.

Changes in Fair Value

The fair value of our outstanding oil and gas commodity derivative instruments was a net liability of approximately $79.2 million at March 31, 2011 and a net asset of approximately $33.5 million at December 31, 2010. At March 31, 2011, a $5.00 per barrel increase or decrease in the price of oil, and a corresponding $1.00 per Mcf change in natural gas would have increased or decreased the net liability of our outstanding oil and gas commodity derivative instruments by approximately $90 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 $3.5 million and $4.8 million at March 31, 2011 and December 31, 2010, respectively. With a 1% increase in the LIBOR rate, our net interest rate derivative instrument liability at March 31, 2011 would have decreased by approximately $4 million. With a 1% decrease in the LIBOR rate to a minimum rate of zero, our net liability at March 31, 2011 would have increased by approximately $3 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 March 31, 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 March 31, 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.

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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).
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*		Second Amendment to the Second Amended and Restated Credit Agreement dated May 9, 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.

* Filed herewith.

** Furnished herewith.

INDEX

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:	May 10, 2011	By:	/s/ Halbert S. Washburn
			Halbert S. Washburn
			Chief Executive Officer

Dated:	May 10, 2011	By:	/s/ James G. Jackson
			James G. Jackson
			Chief Financial Officer

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