Exhibit 99.1

BreitBurn Energy Partners L.P. Reports Fourth Quarter and Full Year Results and Year

End Reserves; Provides Full Year 2011 Guidance

Reports Full-Year 2010 Results Which Exceed or Meet Guidance

LOS ANGELES, March 9, 2011 — BreitBurn Energy Partners L.P. (the "Partnership") (NASDAQ:BBEP) today announced financial and operating results for its fourth quarter and full year 2010 and public guidance for its expected performance in 2011.

Key Highlights

- The Partnership had an excellent year both operationally and financially, with full-year 2010 results in-line with or exceeding guidance.

o Full-year production was at the high-end of the guidance range and totaled 6.7MMBoe.

o Full-year adjusted EBITDA, a non-GAAP measure, was well above the guidance range at $227 million.

o Lease operating costs for 2010 were below the guidance range.

o General and administrative costs for the year were also below the 2010 guidance range.

- In October 2010, the Partnership completed a private offering of $305 million in aggregate principal amount of 8.625% Senior Notes due 2020.  The Partnership received net proceeds of approximately $291 million, which were primarily used to reduce borrowings under its bank credit facility.

- In February 2011, the Partnership completed a public offering of 4,945,000 common units at $21.25 per unit representing additional limited partner interests.  The Partnership received net proceeds of approximately $100 million, which were used to further reduce borrowings under its bank credit facility.  As of February 28, 2010, the Partnership had $122 million outstanding under the facility.

- On February 11, 2011, the Partnership paid cash distributions for the fourth quarter of 2010 at an annualized rate of $1.65 per unit, up from an annualized rate $1.56 per unit for the third quarter of 2010.

- The Partnership continues to opportunistically layer in new hedges and has extended its price protection portfolio in 2015 at attractive prices.

Management Commentary

Hal Washburn, CEO, said: “2010 was a very productive year for the Partnership – we ended the year with a strong fourth quarter as well as full-year 2010 results that exceeded expectations.  Our operations teams performed exceptionally, delivering production results at the high-end of our guidance range while aggressively controlling operating costs.  With our inaugural Senior Notes offering launched in September and the equity offering we closed earlier this year, we’ve increased our financial flexibility considerably.  Since announcing first quarter 2010 distributions of $1.50 per unit on an annualized basis in April 2010, we have steadily grown distributions over three consecutive quarters by 10% to the most recent annualized rate of $1.65 per unit which was paid in February.  With our increased liquidity and our strong hedge portfolio, we are well-positioned in 2011 and will continue to focus on efficiently managing our existing assets, executing our capital program, generating cash flows, and pursuing acquisition opportunities.”

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Fourth Quarter 2010 Operating and Financial Results Compared to Third Quarter 2010

- Total production decreased slightly from 1,741 MBoe in the third quarter of 2010 to 1,700 MBoe in the fourth quarter of 2010.  Average daily production decreased from 18,927 Boe/day in the third quarter of 2010 to 18,480 Boe/day in the fourth quarter of 2010.

o Oil and NGL production was 791 MBoe compared to 827 MBoe.

o Natural gas production was 5,452 MMcf compared to 5,486 MMcf.

- Lease operating expenses per Boe, which include district expenses and processing fees and exclude production/property taxes and transportation costs, increased to $17.37 per Boe in the fourth quarter of 2010 from $16.54 per Boe in the third quarter of 2010.

- General and administrative expenses, excluding non-cash unit-based compensation, were $5.9 million, or $3.47 per Boe, in the fourth quarter of 2010 compared to $7.2 million, or $4.13 per Boe, in the third quarter of 2010.

- Adjusted EBITDA, a non-GAAP measure, was $59.1 million in the fourth quarter, down from $60.0 million in the third quarter of 2010.

- Oil and natural gas sales revenues, including realized gains and losses on commodity derivative instruments, were $99.8 million in the fourth quarter of 2010, up slightly from $99.6 million in the third quarter of 2010.

- Realized gains from commodity derivative instruments were $21.7 million in the fourth quarter of 2010 compared to $22.6 million in the third quarter of 2010.

- NYMEX WTI crude oil spot prices averaged $85.16 per barrel and NYMEX natural gas prices averaged $3.98 per Mcf in the fourth quarter of 2010 compared to $76.06 per barrel and $4.24 per Mcf, respectively, in the third quarter of 2010.

- Realized crude oil and natural gas prices averaged $78.95 per Boe and $7.38 per Mcf, respectively, in the fourth quarter of 2010 compared to $76.14 per Boe and $7.55 per Mcf, respectively, in the third quarter of 2010.

- Net loss, including the effect of unrealized gains on commodity derivative instruments, was $70.9 million, or $1.25 per diluted limited partner unit, in the fourth quarter of 2010 compared to a net loss of $5.7 million, or $0.11 per diluted limited partner unit, in the third quarter of 2010.

- Capital expenditures totaled $16.8 million in the fourth quarter of 2010 compared to $25.6 million in the third quarter of 2010.

Full Year 2010 Results

- Total production was at the high end of our guidance range at 6,699 MBoe in 2010, an increase of 3% from 2009.

- Oil and gas capital expenditures were $69.5 million, an increase of 142% from 2009.

- Full year lease operating expenses per Boe were $17.68, which was below the low end of our guidance range of $18.32 - $20.82 per Boe and 1% below 2009 operating expenses per Boe.

- Full year general and administrative expenses, excluding unit-based compensation, were $24.5 million, which was below the low end of the guidance range of $25.0 - $27.0 million.

- Adjusted EBITDA, a non-GAAP measure, was above the high end of our guidance range at $226.9 million.

- Average realized crude oil and natural gas prices for 2010 were $74.31 per Boe and $7.57 per Mcf, compared to NYMEX WTI crude oil and NYMEX natural gas average prices of $79.48 per barrel and $4.38 per Mcf.

2010 Estimated Proved Reserves Increase to 118.9 MMBoe

BreitBurn's total estimated proved oil and gas reserves as of December 31, 2010, were 118.9 MMBoe. The Standardized Measure of discounted (at 10%) future net cash flows from the production of these reserves is approximately $1,065 million using prices and costs in effect as of the dates such estimates were made that are held constant throughout the life of the properties. Estimated proved reserves were determined using $4.38 per MMBtu for gas and $79.40 per Bbl of oil for Michigan and California and $65.36 per Bbl of oil for Wyoming. Of the total estimated proved reserves, 65% were natural gas and 35% were crude oil, 91% were classified as proved developed and 68% were located in Michigan, 12% in California, 10% in Wyoming, and 8% in Florida, with the remaining 2% in Indiana and Kentucky.

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Estimates of our proved reserves were prepared by Netherland, Sewell & Associates, Inc. and Schlumberger Data & Consulting Services, independent petroleum engineering firms. Netherland, Sewell & Associates, Inc. prepared reserve data for our California, Wyoming and Florida properties, and Schlumberger Data & Consulting Services prepared reserve data for our Michigan, Kentucky and Indiana properties.

2011 Guidance

The following guidance is subject to all cautionary statements and limitations described below and under the caption "Cautionary Statement Regarding Forward-Looking Information." In addition, estimates for the Partnership's future production volumes are based on, among other things, assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of oil and gas are extremely complex and are subject to disruption due to transportation and processing availability, mechanical failure, human error, weather, and numerous other factors. The Partnership's estimates are based on certain other assumptions, such as well performance, which may actually prove to vary significantly from those assumed. Operating costs, which include major maintenance costs, vary in response to changes in prices of services and materials used in the operation of our properties and the amount of maintenance activity required. Operating costs, including taxes, utilities and service company costs, move directionally with increases and decreases in commodity prices, and we cannot fully predict such future commodity or operating costs. Similarly, interest rates and price differentials are set by the market and are not within our control. They can vary dramatically from time to time. Capital expenditures are based on our current expectation as to the level of capital expenditures that will be justified based upon the other assumptions set forth below as well as expectations about other operating and economic factors not set forth below. The guidance below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. Rather, the table simply sets forth our best estimate today for these matters based upon our current expectations about the future based upon both stated and unstated assumptions. Actual conditions and those assumptions may, and probably will, change over the course of the year.

($ in 000s)	2011 Guidance
Total Production (Mboe)		6,500		-		6,900
Production Mix:
Oil Production %		48%
Gas Production %		52%
Average Price Differential %:
Oil Price Differential %		89	%	-		91	%
Gas Price Differential %		100	%	-		102	%
Operating Costs / BOE(1)(2)	$	18.50		-	$	21.00
Production/Property Taxes (% of oil & gas revenue)		7.5	%	-		8.0	%
G&A (Excl. Unit Based Compensation)	$	26,000		-	$	28,000
Cash Interest Expense(3)	$	36,000		-	$	38,000
Total Capital Expenditures(4)	$	70,000		-	$	74,000
Adjusted EBITDA(5)	$	195,000		-	$	205,000

1. Operating Costs include lease operating costs, processing fees and transportation expense.  Expected transportation expense totals approximately $6.7 million in 2011, largely attributable to our Florida production.  Excluding transportation expense, our estimated operating costs range per Boe is approximately $17.50 - $20.00.

2. Operating Costs are based on flat $80 per barrel WTI crude oil and $4.25 per Mcfe natural gas price levels for 2011.  Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices.

3. The Partnership typically borrows on a 1-month LIBOR basis, plus an applicable spread.  Estimated cash interest expense assumes a 1-month LIBOR rate of 1% and includes the impact of interest rate swaps covering approximately $175 million of borrowings at a weighted average swap rate of 2.23%.

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4. Total Capital Expenditures for 2011 include Maintenance and Obligatory Capital Expenditures as well as Growth Capital Expenditures.  Maintenance and Obligatory Capital Expenditures are defined as the estimated amount of investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately constant for the period.  Management estimates that we would need to spend between $40 and $50 million in 2011 to hold production flat.

5. Assuming the high and low range of our guidance, Adjusted EBITDA is expected to range between $195 million and $205 million, and is comprised of estimated net income between $120 million and $132 million, less unrealized gain on commodity derivative instruments of $63 million, plus DD&A of $100 million, plus interest expense between $36 million (high end of Adjusted EBITDA) and $38 million (low end of Adjusted EBITDA).  Estimated 2011 net income is based on oil prices of $80 per barrel for WTI crude oil and $4.25 per Mcfe for natural gas.  Consequently, differences between actual and forecasted prices could result in changes to unrealized gains or losses on commodity derivative instruments, DD&A, including potential impairments of long-lived assets, and ultimately, net income.

Impact of Derivative Instruments

The Partnership uses commodity and interest rate derivative instruments to mitigate the risks associated with commodity price volatility and changing interest rates and to help maintain cash flows for operating activities, acquisitions, capital expenditures, and distributions. The Partnership does not enter into derivative instruments for speculative trading purposes. Non-cash gains or losses do not affect Adjusted EBITDA, cash flow from operations or the Partnership’s ability to pay cash distributions.

Realized gains from commodity derivative instruments were $21.7 million during the fourth quarter of 2010.  Realized losses from interest rate derivative instruments were $2.3 million during the fourth quarter of 2010.  Non-cash unrealized losses from commodity derivative instruments were $82.3 million and non-cash unrealized gains from interest rate derivative instruments were $3.1 million during the fourth quarter of 2010.

Realized gains from commodity derivative instruments were $74.8 million for the year ended December 31, 2010.  Realized losses from interest rate derivative instruments were $11.1 million for the year ended December 31, 2010.  Non-cash unrealized losses from commodity derivative instruments were $39.7 million and non-cash unrealized gains from interest rate derivative instruments were $6.6 million for year ended December 31, 2010.

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Production, Income Statement and Realized Price Information

The following table presents production, selected income statement and realized price information for the three months ended December 31, 2010 and 2009, the three months ended September 30, 2010 and the years ended December 31, 2010 and 2009:

	Three Months Ended									Year Ended December 31,
	December 31,			September 30,			December 31,
Thousands of dollars, except as indicated	2010			2010			2009			2010			2009
Oil, natural gas and NGL sales (a)	$	78,135		$	77,055		$	74,728		$	317,738		$	254,917
Realized gain on commodity derivative instruments (b)		21,677			22,567			17,771			74,825			167,683
Unrealized loss on commodity derivative instruments (b)		(82,307	)		(30,540	)		(54,688	)		(39,713	)		(219,120	)
Other revenues, net		660			719			452			2,498			1,382
Total revenues	$	18,165		$	69,801		$	38,263		$	355,348		$	204,862
Lease operating expenses and processing fees	$	29,536		$	28,800		$	31,685		$	118,454		$	118,405
Production and property taxes		5,626			5,081			6,118			20,510			19,433
Total lease operating expenses	$	35,162		$	33,881		$	37,803		$	138,964		$	137,838
Transportation expenses		943			1,037			926			4,058			3,825
Purchases		112			90			14			328			72
Change in inventory		(2,121	)		(1,801	)		(518	)		(825	)		(3,337	)
Uninsured loss		-			-			-			-			100
Total operating costs	$	34,096		$	33,207		$	38,225		$	142,525		$	138,498
Lease operating expenses pre taxes per Boe (c)	$	17.37		$	16.54		$	19.31		$	17.68		$	17.90
Production and property taxes per Boe		3.31			2.92			3.75			3.06			2.98
Total lease operating expenses per Boe		20.68			19.46			23.06			20.74			20.88
General and administrative expenses excluding unit-based compensation	$	5,907		$	7,193		$	6,184		$	24,478		$	23,704
Net income (loss)	$	(70,868	)	$	(5,726	)	$	(39,693	)	$	34,913		$	(107,257	)
Net income (loss) per diluted limited partnership unit	$	(1.25	)	$	(0.11	)	$	(0.75	)	$	0.61		$	(2.03	)
Total production (MBoe)		1,700			1,741			1,632			6,699			6,517
Oil and NGL (MBoe)		791			827			744			3,157			2,990
Natural gas (MMcf)		5,452			5,486			5,335			21,251			21,161
Average daily production (Boe/d)		18,480			18,927			17,740			18,354			17,856
Sales volumes (MBoe)		1,664			1,680			1,642			6,663			6,465
Average realized sales price (per Boe) (d) (e) (f)	$	59.99		$	59.32		$	56.48		$	58.94		$	54.60
Oil and NGL (per Boe) (d) (e) (f)		78.95			76.14			69.72			74.31			66.27
Natural gas (per Mcf) (d) (e)		7.38			7.55			7.55			7.57			7.48

(a) Q4 2010, Q3 2010, Q4 2009, Full Year 2010 and Full Year 2009 include $124, $124, $268, $495 and $1,040, respectively, of amortization of an intangible asset related to crude oil sales contracts

(b) Full Year 2009 includes the effects of the early terminations of hedge contracts monetized in January 2009 for $45,632 and June 2009 for $24,955.

(c) Includes lease operating expenses, district expenses and processing fees. Q4 2009 and Full Year 2009 exclude amortization of intangible asset related to the Quicksilver Acquisition.

(d) Includes realized gains on commodity derivative instruments.

(e) Full Year 2009 excludes the effect of the early termination of oil and natural gas hedge contracts monetized in January 2009 for $45,632 and June 2009 for $24,955.

(f) Excludes amortization of intangible asset related to crude oil sales contracts. Includes crude oil purchases.

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Non-GAAP Financial Measures

This press release, the financial tables and other supplemental information, including the reconciliations of certain non-generally accepted accounting principles ("non-GAAP") measures to their nearest comparable generally accepted accounting principles ("GAAP") measures, may be used periodically by management when discussing the Partnership's financial results with investors and analysts and they are also available on the Partnership's website under the Investor Relations tab.

Among the non-GAAP financial measures used is “Adjusted EBITDA.” This non-GAAP financial measure should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA is presented as management believes it provides additional information relative to the performance of the Partnership's business, such as our ability to meet our debt covenant compliance tests. This non-GAAP financial measure may not be comparable to similarly titled measures of other publicly traded partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.

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Adjusted EBITDA

The following table presents a reconciliation of net income or loss and net cash flows from operating activities, our most directly comparable GAAP financial performance and liquidity measures, to Adjusted EBITDA for each of the periods indicated.

	Three Months Ended									Year Ended December 31,
	December 31,			September 30,			December 31,
Thousands of dollars	2010			2010			2009			2010			2009
Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss) attributable to the partnership	$	(70,903	)	$	(5,754	)	$	(39,712	)	$	34,751		$	(107,290	)
Unrealized loss on commodity derivative instruments		82,307			30,540			54,688			39,713			219,120
Depletion, depreciation and amortization expense		33,159			23,636			25,450			102,758			106,843
Interest expense and other financing costs (a)		13,116			8,090			7,590			35,639			31,942
Unrealized gain on interest rate derivatives		(3,126	)		(1,314	)		(1,757	)		(6,597	)		(5,869	)
Gain on sale of commodity derivatives (b)		-			-			-			-			(70,587	)
(Gain) loss on sale of assets (c)		(123	)		(359	)		495			14			5,965
Income taxes		(439	)		(470	)		(1,174	)		(204	)		(1,528	)
Amortization of intangibles		124			124			437			495			2,771
Unit-based compensation expense (d)		5,009			5,502			2,933			20,331			13,619
Adjusted EBITDA	$	59,124		$	59,995		$	48,950		$	226,900		$	194,986

	Three Months Ended									Year Ended December 31,
	December 31,			September 30,			December 31,
Thousands of dollars	2010			2010			2009			2010			2009
Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
Net cash from operating activities	$	38,722		$	62,236		$	40,387		$	182,022		$	224,358
Increase (decrease) in assets net of liabilities relating to operating activities		9,983			(9,149	)		2,584			15,131			12,466
Interest expense (a) (e)		10,488			6,997			6,766			30,161			28,647
Gain on sale of commodity derivatives (b)		-			-			-			-			(70,587	)
Income from equity affiliates, net		(157	)		9			(536	)		(450	)		(1,302	)
Incentive compensation expense (f)		(29	)		(45	)		8			(93	)		958
Incentive compensation paid		-			11			41			91			217
Income taxes		152			(36	)		(281	)		199			262
Non-controlling interest		(35	)		(28	)		(19	)		(162	)		(33	)
Adjusted EBITDA	$	59,124		$	59,995		$	48,950		$	226,900		$	194,986

(a) Includes realized gain/loss on interest rate derivatives.

(b) Represents $45,632 and $24,955 related to the early terminations of selected 2011 and 2012 hedge contracts monetized in January 2009 and June 2009.

(c) The year ended December 31, 2009 includes loss on sale of Lazy JL assets of $5,541.

(d) Represents non-cash long term unit-based incentive compensation expense.

(e) Excludes amortization of debt issuance costs and amortization of Senior Note discount.

(f) Represents cash-based incentive compensation plan expense.

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Hedge Portfolio Summary

The table below summarizes the Partnership’s commodity derivative hedge portfolio as of March 9, 2011.

	Year
	2011			2012		2013		2014		2015
Oil Positions:
Fixed Price Swaps:
Hedged Volume (Bbls/d)		5,019			5,039		6,480		5,000		2,000
Average Price ($/Bbl)	$	76.14		$	77.15	$	81.37	$	88.60	$	99.00
Participating Swaps: (a)
Hedged Volume (Bbls/d)		1,439			-		-		-		-
Average Price ($/Bbl)	$	61.29		$	-	$	-	$	-	$	-
Average Participation %		53.2	%		-		-		-		-
Collars:
Hedged Volume (Bbls/d)		2,048			2,477		500		1,000		1,000
Average Floor Price ($/Bbl)	$	103.42		$	110.00	$	77.00	$	90.00	$	90.00
Average Ceiling Price ($/Bbl)	$	152.61		$	145.39	$	103.10	$	112.00	$	113.50
Floors:
Hedged Volume (Bbls/d)		-			-		-		-		-
Average Floor Price ($/Bbl)	$	-		$	-	$	-	$	-	$	-
Total:
Hedged Volume (Bbls/d)		8,506			7,516		6,980		6,000		3,000
Average Price ($/Bbl)	$	80.20		$	87.97	$	81.06	$	88.83	$	96.00
Gas Positions:
Fixed Price Swaps:
Hedged Volume (MMBtu/d)		25,955			19,128		37,000		7,500		-
Average Price ($/MMBtu)	$	7.26		$	7.10	$	6.50	$	6.00	$	-
Collars:
Hedged Volume (MMBtu/d)		16,016			19,129		-		-		-
Average Floor Price ($/MMBtu)	$	9.00		$	9.00	$	-	$	-	$	-
Average Ceiling Price ($/MMBtu)	$	11.28		$	11.89	$	-	$	-	$	-
Total:
Hedged Volume (MMBtu/d)		41,971			38,257		37,000		7,500		-
Average Price ($/MMBtu)	$	7.92		$	8.05	$	6.50	$	6.00	$	-

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

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Other Information

The Partnership will host an investor conference call to discuss its results today at 9:00 a.m. (Pacific Time). Investors may access the conference call over the Internet via the Investor Relations tab of the Partnership's website (www.breitburn.com), or via telephone by dialing 866-431-5320(international callers dial +1-719-325-2417) a few minutes prior to register. Those listening via the Internet should go to the site 15 minutes early to register, download and install any necessary audio software. In addition, a replay of the call will be available through March 23, 2011 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 7571007, or by going to the Investor Relations tab of the Partnership's website (www.breitburn.com). The Partnership will take live questions from securities analysts and institutional portfolio managers; the complete call is open to all other interested parties on a listen-only basis.

About BreitBurn Energy Partners L.P.

BreitBurn Energy Partners L.P. is a California-based publicly traded independent oil and gas limited partnership focused on the acquisition, exploitation, development and production of oil and gas properties. The Partnership’s producing and non-producing crude oil and natural gas reserves are located 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. See www.BreitBurn.com for more information.

Cautionary Statement Regarding Forward-Looking Information

This press release contains forward-looking statements relating to BreitBurn's operations that are based on management's current expectations, estimates and projections about its operations. Words and phrases such as "believes," “future,” “impact,” “guidance,” “expectations,” “continue,” “anticipate,” “will remain,” “generating,” “pursuing” and variations of such words and similar expressions are intended to identify such forward-looking statements. 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. These include risks relating to the Partnership’s financial performance and results, availability of sufficient cash flow to execute our business plan, our level of indebtedness, a significant reduction in the borrowing base under our bank credit facility, our ability to raise capital, prices and demand for natural gas and oil, increases in operating costs, our ability to replace reserves and efficiently develop our current reserves, political and regulatory developments relating to taxes, derivatives and our oil and gas operations, and the factors set forth under the heading "Risk Factors" incorporated by reference from our Annual Report on Form 10-K filed with the Securities and Exchange Commission on March 9, 2011, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K. 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 press release. Unless legally required, BreitBurn undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

Investor Relations Contacts:

James G. Jackson

Executive Vice President and Chief Financial Officer

(213) 225-5900 x273

or

Gloria Chu

Investor Relations

(213) 225-5900 x210

BBEP-IR

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BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Operations

	Three Months Ended						Year Ended
	December 31,						December 31,
Thousands of dollars, except per unit amounts	2010			2009			2010			2009
Revenues and other income items
Oil, natural gas and natural gas liquid sales	$	78,135		$	74,728		$	317,738		$	254,917
Gain (loss) on commodity derivative instruments, net		(60,630	)		(36,917	)		35,112			(51,437	)
Other revenue, net		660			452			2,498			1,382
Total revenues and other income items		18,165			38,263			355,348			204,862
Operating costs and expenses
Operating costs		34,096			38,225			142,525			138,498
Depletion, depreciation and amortization		33,159			25,450			102,758			106,843
General and administrative expenses		10,950			9,102			44,907			36,367
(Gain) loss on sale of assets		(123	)		495			14			5,965
Unreimbursed litigation settlement costs		1,401			-			1,401			-
Total operating costs and expenses		79,483			73,272			291,605			287,673
Operating income (loss)		(61,318	)		(35,009	)		63,743			(82,811	)
Interest and other financing costs, net		10,790			4,145			24,552			18,827
(Gain) loss on interest rate swaps		(800	)		1,688			4,490			7,246
Other expense (income), net		(1	)		25			(8	)		(99	)
Income (loss) before taxes		(71,307	)		(40,867	)		34,709			(108,785	)
Income tax benefit		(439	)		(1,174	)		(204	)		(1,528	)
Net income (loss)		(70,868	)		(39,693	)		34,913			(107,257	)
Less: Net income attributable to noncontrolling interest		(35	)		(19	)		(162	)		(33	)
Net income (loss) attributable to the partnership		(70,903	)		(39,712	)		34,751			(107,290	)
Basic net income (loss) per unit	$	(1.25	)	$	(0.75	)	$	0.61		$	(2.03	)
Diluted net income (loss) per unit	$	(1.25	)	$	(0.75	)	$	0.61		$	(2.03	)

10

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Balance Sheets

	December 31,			December 31,
Thousands	2010			2009
ASSETS
Current assets
Cash	$	3,630		$	5,766
Accounts and other receivables, net		53,520			65,209
Derivative instruments		54,752			57,133
Related party receivables		4,345			2,127
Inventory		7,321			5,823
Prepaid expenses		6,449			5,888
Intangibles		-			495
Total current assets		130,017			142,441
Equity investments		7,700			8,150
Property, plant and equipment
Oil and gas properties		2,133,099			2,058,968
Other assets		10,832			7,717
		2,143,931			2,066,685
Accumulated depletion and depreciation		(421,636	)		(325,596	)
Net property, plant and equipment		1,722,295			1,741,089
Other long-term assets
Derivative instruments		50,652			74,759
Other long-term assets		19,503			4,590
Total assets	$	1,930,167		$	1,971,029
LIABILITIES AND EQUITY
Current liabilities
Accounts payable	$	26,808		$	21,314
Derivative instruments		37,071			20,057
Related party payables		-			13,000
Revenue and royalties payable		16,427			18,224
Salaries and wages payable		12,594			10,244
Accrued liabilities		8,417			9,051
Total current liabilities		101,317			91,890
Credit facility		228,000			559,000
Senior notes, net		300,116			-
Deferred income taxes		2,089			2,492
Asset retirement obligation		47,429			36,635
Derivative instruments		39,722			50,109
Other long-term liabilities		2,237			2,102
Total liabilities		720,910			742,228
Equity
Partners' equity		1,208,803			1,228,373
Noncontrolling interest		454			428
Total equity		1,209,257			1,228,801
Total liabilities and equity	$	1,930,167		$	1,971,029
Limited partner units issued and outstanding		53,957			52,784

11

BreitBurn Energy Partners L.P. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

	Year Ended
	December 31,
Thousands of dollars	2010			2009
Cash flows from operating activities
Net income (loss)	$	34,913		$	(107,257	)
Adjustments to reconcile to cash flows from operating activities:
Depletion, depreciation and amortization		102,758			106,843
Unit based compensation expense		20,422			12,661
Unrealized loss on derivative instruments		33,116			213,251
Income from equity affiliates, net		450			1,302
Deferred income taxes		(403	)		(1,790	)
Amortization of intangibles		495			2,771
Loss on sale of assets		14			5,965
Other		3,528			3,294
Changes in net assets and liabilities
Accounts receivable and other assets		11,552			(6,313	)
Inventory		(1,498	)		(4,573	)
Net change in related party receivables and payables		(15,218	)		2,957
Accounts payable and other liabilities		(8,107	)		(4,753	)
Net cash provided by operating activities		182,022			224,358
Cash flows from investing activities
Capital expenditures		(66,947	)		(29,513	)
Proceeds from sale of assets		337			23,284
Property acquisitions		(1,676	)		-
Net cash used in investing activities		(68,286	)		(6,229	)
Cash flows from financing activities
Distributions		(65,197	)		(28,038	)
Proceeds from long-term debt		1,047,992			249,975
Repayments of long-term debt		(1,079,000	)		(426,975	)
Book overdraft		1,025			(9,871	)
Long-term debt issuance costs		(20,692	)		-
Net cash used in financing activities		(115,872	)		(214,909	)
Increase (decrease) in cash		(2,136	)		3,220
Cash beginning of period		5,766			2,546
Cash end of period	$	3,630		$	5,766

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