BreitBurn Energy Partners L.P. Reports Second Quarter Results, Announces Substantial Increase in 2012 Capital Program and Updates Second Half 2012 Guidance

LOS ANGELES--(BUSINESS WIRE)-- BreitBurn Energy Partners L.P. (the "Partnership") (NASDAQ:BBEP) today announced financial and operating results for its second quarter of 2012, a substantial increase in its 2012 capital program, and updated second half 2012 guidance.

Key Highlights

• The Partnership had strong operating and financial results with net production increasing 18%, and Adjusted EBITDA increasing 28%, from the second quarter of 2011.
• On July 31, 2012, the Partnership announced an increased cash distribution for the second quarter of 2012 of $0.4600 per common unit, equal to an annualized rate of $1.84 per common unit, to be paid on August 14, 2012 to the record holders of common units at the close of business on August 10, 2012. This represents the Partnership's ninth consecutive quarterly distribution increase and a 9% increase over the cash distribution for the second quarter of 2011.
• On July 2, 2012, the Partnership completed two separate acquisitions of principally oil properties located in the Permian Basin in Texas from Element Petroleum LP and CrownRock LP for approximately $150 million and $70 million, respectively, subject to customary post-closing adjustments.
• On June 28, 2012, the Partnership completed the acquisition of oil properties located in Park County in the Big Horn Basin of Wyoming from NiMin Energy Corp. for approximately $93 million, subject to customary post-closing adjustments.
• The Partnership is substantially increasing its 2012 capital program for the second time this year. In April, the Partnership announced a $19 million increase to its original 2012 capital program of approximately $68 million. Today the Partnership is announcing an additional increase of $50 million. This latest increase expands the Partnership's total 2012 capital program to approximately $137 million and will be allocated principally to attractive oil development opportunities on newly acquired assets as well as the Partnership's legacy assets.
• The Partnership updated its guidance for the second half of 2012, reflecting year-to-date acquisitions and the positive impacts of its increased capital program.

Management Commentary

Hal Washburn, CEO, said: "The Partnership delivered a strong second quarter as we continued to execute on our growth through acquisitions strategy. We completed three very attractive acquisitions of primarily oil properties which expanded our operations to seven states and established our presence in the Permian Basin. Additionally, we are increasing our capital program for the second time this year by $50 million to develop our newly acquired assets and to pursue a series of attractive oil projects identified in our legacy assets as well. To reflect our increased capital program and recent acquisitions, we are increasing our full year production target to between approximately 8.3 MMBoe and 8.6 MMBoe and we are increasing our full year Adjusted EBITDA target to between approximately $280 million and $290 million. These increases demonstrate our focus on continually improving our operating performance and the ongoing success of our growth through acquisitions strategy."

Second Quarter 2012 Operating and Financial Results Compared to First Quarter 2012

• Total production was 1,953 MBoe in the second quarter of 2012 compared to 1,987 MBoe in the first quarter of 2012. Average daily production was 21,457 Boe/day in the second quarter of 2012 compared to 21,835 Boe/day in first quarter of 2012.
  • Oil and NGL production was 815 MBoe compared to 859 MBoe. The decline principally reflects interest reversions in two California fields which occurred during the second quarter. NGLs represented less than 6% of oil and NGL production and less than 3% of total production.
  • Natural gas production was 6,824 MMcf compared to 6,769 MMcf.
• Adjusted EBITDA, a non-GAAP measure, increased approximately 8% to a record quarterly high of $66.3 million in the second quarter of 2012 from $61.4 million in the first quarter of 2012.
• Lease operating expenses per Boe, which include district expenses, transportation expenses and processing fees and exclude production and property taxes, increased to $20.03 per Boe in the second quarter of 2012 from $19.16 per Boe in the first quarter of 2012, primarily due to higher well service costs.
• General and administrative expenses on a per Boe basis, excluding non-cash unit-based compensation, decreased to $3.75 per Boe in the second quarter of 2012 from $4.07 per Boe in the first quarter of 2012.
• Oil and natural gas sales revenues were $95.0 million in the second quarter of 2012, up from $94.0 million in the first quarter of 2012. Realized gains on commodity derivative instruments were $25.1 million in the second quarter of 2012 compared to realized gains of $17.6 million in the first quarter of 2012.
• NYMEX WTI crude oil spot prices averaged $93.29 per barrel and Henry Hub natural gas spot prices averaged $2.29 per Mcf in the second quarter of 2012 compared to $102.98 per barrel and $2.44 per Mcf, respectively, in the first quarter of 2012. Brent crude oil spot prices averaged $108.04 per barrel in the second quarter of 2012 compared to $118.71 in the first quarter of 2012.
• Realized crude oil and NGL prices averaged $92.08 per Boe and realized natural gas prices averaged $5.74 per Mcf in the second quarter of 2012 compared to realized crude oil and NGL prices of $90.36 per Boe and realized natural gas prices of $6.18 per Mcf in the first quarter of 2012.
• Net income attributable to the Partnership, including the effect of unrealized losses on commodity derivative instruments, was $92.5 million, or $1.29 per diluted common unit, in the second quarter of 2012 compared to a net loss of $50.0 million, or $0.76 per diluted common unit, in the first quarter of 2012.
• Capital expenditures totaled $28.0 million in the second quarter of 2012 compared to $16.5 million in the first quarter of 2012.

Second Half of 2012 Guidance Update

The following guidance is subject to all of the 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 expectations 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)						Second Half 2012 Guidance
					Total Production (MBoe)							4,400		-			4,700
					Oil Production (Mbbls)							2,050		-			2,250
					Gas Production (MMcfe)							14,100		-			14,700
					Average Price Differential %:
					Oil Price Differential %(1)							88	%	-			90	%
					Gas Price Differential %							108	%	-			110	%
					Operating Costs / BOE(2)(3)						$	18.00		-		$	20.00
					Production / Property Taxes (% of oil & gas revenue)							8.0	%	-			9.0	%
					G&A (Excl. Unit Based Compensation)						$	15,000		-		$	17,000
					Cash Interest Expense(4)						$	32,000		-		$	34,000
					Capital Expenditures(5)						$	90,000		-		$	94,000
					Adjusted EBITDA(6)						$	155,000		-		$	165,000

(1)			Represents the expected average price differential to both WTI crude oil and Brent crude oil pricing. Approximately 30% of oil production is expected to be sold based on Brent pricing.
(2)			Operating Costs include lease operating costs, processing fees, district expense, and transportation expense. Expected transportation expense totals approximately $3.4 million in the second half of 2012, largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs per Boe are expected to range between approximately $17.25 - $19.25.
(3)			Operating Costs are based on flat $85 per barrel WTI crude oil, $100 per barrel Brent crude oil, and $3.00 per Mcfe natural gas price levels for the second half of 2012. Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices.
(4)			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 $194 million of borrowings at a weighted average swap rate of 1.84% for the second half of 2012.
(5)			Total Capital Expenditures for 2012 include maintenance and obligatory capital expenditures as well as growth capital expenditures and exclude capital expense for acquisitions as well as information technology spending. 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 the Partnership would need to spend approximately $35 million in the second half of 2012 to hold production flat.
(6)			Assuming the high and low range of our guidance, Adjusted EBITDA for the second half of 2012 is expected to range between $155 million and $165 million, and is comprised of estimated net income (before non-cash compensation) between $58 million and $70 million, less estimated unrealized gain on commodity derivative instruments of approximately $5 million, plus estimated DD&A of approximately $63 million, plus estimated interest expense between $32 million (high end of Adjusted EBITDA) and $34 million (low end of Adjusted EBITDA), and plus other adjustments of approximately $5 million. Estimated 2012 net income is based on oil prices of $85 per barrel for WTI crude oil, $100 per barrel Brent crude oil, and $3.00 per Mcfe for natural gas. Consequently, differences between actual and forecast 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 $25.1 million during the second quarter of 2012. Realized losses from interest rate derivative instruments were $0.8 million during the second quarter of 2012. Non-cash unrealized gains from commodity derivative instruments were $82.2 million and non-cash unrealized gains from interest rate derivative instruments were $0.6 million during the second quarter of 2012.

Production, Statement of Operations and Realized Price Information

The following table presents production, selected income statement and realized price information for the three months ended June 30, 2012, March 31, 2012 and June 30, 2011:

										Three Months Ended
										June 30,							March 31,								June 30,
					Thousands of dollars, except as indicated					2012							2012								2011
					Oil, natural gas and NGLs sales					$	94,981						$	94,007							$	94,742
					Realized gain (loss) on commodity derivative instruments						25,063							17,591								(1,751	)
					Unrealized gain (loss) on commodity derivative instruments						82,225							(53,596	)							48,234
					Other revenues, net						907							1,145								1,143
					Total revenues					$	203,176						$	59,147							$	142,368
					Lease operating expenses and processing fees					$	39,122						$	38,073							$	31,605
					Production and property taxes						6,525							7,573								6,195
					Total lease operating expenses					$	45,647						$	45,646							$	37,800
					Purchases and other operating costs						647							370								268
					Change in inventory						2,600							(2,755	)							(1,860	)
					Total operating costs					$	48,894						$	43,261							$	36,208
					Lease operating expenses pre taxes per Boe(a)					$	20.03						$	19.16							$	19.02
					Production and property taxes per Boe						3.34							3.81								3.73
					Total lease operating expenses per Boe						23.37							22.97								22.75
					General and administrative expenses (excluding unit-based compensation)					$	7,314						$	8,083							$	6,221
					Net income (loss) attributable to the partnership					$	92,506						$	(49,970	)						$	57,523
					Net income (loss) per diluted limited partner unit					$	1.29						$	(0.76	)						$	0.92
					Total production (MBoe)						1,953							1,987								1,662
					Oil and NGLs (MBoe)(b)						815							859								782
					Natural gas (MMcf)						6,824							6,769								5,277
					Average daily production (Boe/d)						21,457							21,835								18,265
					Sales volumes (MBoe)						2,013							1,899								1,621
					Average realized sales price (per Boe)(c)(d)					$	59.54						$	58.66							$	57.29
					Oil and NGLs (per Boe)(c)(d)						92.08							90.36								79.48
					Natural gas (per Mcf)(c)						5.74							6.18								6.42

					(a)			Includes lease operating expenses, district expenses, transportation expenses and processing fees.
					(b)			NGLs account for less than 6% of oil and NGLs production and less than 3% of total production.
					(c)			Includes realized gain (loss) on commodity derivative instruments.
					(d)			Includes crude oil purchases.

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. Management believes that these non-GAAP financial measures enhance comparability to prior periods.

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.

Adjusted EBITDA

The following table presents a reconciliation of net income (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
									June 30,								March 31,								June 30,
					Thousands of dollars				2012								2012								2011
					Reconciliation of net income (loss) to Adjusted EBITDA:
					Net income (loss) attributable to the Partnership				$	92,506								($49,970	)						$	57,455
					Unrealized (gain) loss on commodity derivative instruments					(82,225	)							53,596								(48,234	)
					Depletion, depreciation and amortization expense					33,517								38,281								25,025
					Interest expense and other financing costs(a)					14,872								14,458								10,145
					Unrealized (gain) loss on interest rate derivatives					(613	)							(164	)							1,155
					Loss on sale of assets					29								125								40
					Income taxes					1,005								(559	)							616
					Unit-based compensation expense(b)					5,612								5,591								5,435
					Net operating cash flow from acquisitions, effective date through closing date					1,595								-								-
					Adjusted EBITDA				$	66,298							$	61,358							$	51,637
									Three Months Ended
									June 30,								March 31,								June 30,
					Thousands of dollars				2012								2012								2011
					Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
					Net cash provided by operating activities				$	29,252							$	71,299							$	33,118
					Increase (decrease) in assets net of liabilities relating to operating activities					21,940								(23,168	)							9,837
					Interest expense(a)(c)					13,583								13,206								8,896
					Income from equity affiliates, net					(155	)							(154	)							(262	)
					Incentive compensation expense(d)					-								-								14
					Income taxes					100								220								102
					Non-controlling interest					(17	)							(45	)							(68	)
					Net operating cash flow from acquisitions, effective date through closing date					1,595								-								-
					Adjusted EBITDA				$	66,298							$	61,358							$	51,637

					(a)			Includes realized loss on interest rate derivatives.
					(b)			Represents non-cash long-term unit-based incentive compensation expense.
					(c)			Excludes amortization of debt issuance costs and amortization of senior note discount.
					(d)			Represents cash-based incentive compensation plan expense.

Hedge Portfolio Summary

The table below summarizes the Partnership's commodity derivative hedge portfolio for the second half of 2012 through 2017 and includes contracts entered into through August 6, 2012. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.

							Year
							2012					2013					2014					2015					2016					2017
			Oil Positions:
			Fixed Price Swaps - NYMEX WTI
			Hedged Volume (Bbls/d)					3,586					3,371					3,145					3,546					1,484					222
			Average Price ($/Bbl)				$	89.76				$	90.02				$	93.14				$	97.78				$	91.84				$	88.12
			Fixed Price Swaps - IPE Brent
			Hedged Volume (Bbls/d)					2,339					3,900					3,500					2,000					500					-
			Average Price ($/Bbl)				$	105.37				$	97.23				$	96.86				$	96.46				$	95.55				$	-
			Collars - NYMEX WTI
			Hedged Volume (Bbls/d)					2,384					500					1,000					1,000					-					-
			Average Floor Price ($/Bbl)				$	110.00				$	77.00				$	90.00				$	90.00				$	-				$	-
			Average Ceiling Price ($/Bbl)				$	145.37				$	103.10				$	112.00				$	113.50				$	-				$	-
			Collars - IPE Brent
			Hedged Volume (Bbls/d)					-					-					-					500					500					-
			Average Floor Price ($/Bbl)				$	-				$	-				$	-				$	90.00				$	90.00				$	-
			Average Ceiling Price ($/Bbl)				$	-				$	-				$	-				$	109.50				$	101.25				$	-
			Total:
			Hedged Volume (Bbls/d)					8,309					7,771					7,645					7,046					2,484					222
			Average Price ($/Bbl)				$	99.96				$	92.80				$	94.43				$	95.75				$	92.21				$	88.12
			Gas Positions:
			Fixed Price Swaps - MichCon City-Gate
			Hedged Volume (MMBtu/d)					18,730					37,000					7,500					7,500					-					-
			Average Price ($/MMBtu)				$	7.10				$	6.50				$	6.00				$	6.00				$	-				$	-
			Fixed Price Swaps - Henry Hub
			Hedged Volume (MMBtu/d)					16,000					19,000					36,000					40,500					13,000					-
			Average Price ($/MMBtu)				$	4.88				$	4.90				$	4.86				$	4.88				$	4.18				$	-
			Collars - MichCon City-Gate
			Hedged Volume (MMBtu/d)					18,732					-					-					-					-					-
			Average Floor Price ($/MMBtu)				$	9.00				$	-				$	-				$	-				$	-				$	-
			Average Ceiling Price ($/MMBtu)				$	11.60				$	-				$	-				$	-				$	-				$	-
			Puts - Henry Hub
			Hedged Volume (MMBtu/d)					-					-					6,000					1,500					-					-
			Average Price ($/MMBtu)				$	-				$	-				$	5.00				$	5.00				$	-				$	-
			Total:
			Hedged Volume (MMBtu/d)					53,462					56,000					49,500					49,500					13,000					-
			Average Price ($/MMBtu)				$	7.10				$	5.96				$	5.05				$	5.05				$	4.18				$	-
			Calls - Henry Hub
			Hedged Volume (MMBtu/d)					-					30,000					15,000					-					-					-
			Average Price ($/MMBtu)				$	-				$	8.00				$	9.00				$	-				$	-				$	-
			Premium ($/MMBtu)				$	-				$	0.08				$	0.12				$	-				$	-				$	-

Other Information

The Partnership will host an investor conference call to discuss its results today at 10:00 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 888-300-2323 (international callers dial +1-719-325-2492) 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 August 21, 2012 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 1671747, 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 publicly traded independent oil and gas master 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 Michigan, Wyoming, California, Texas, Florida, 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 the Partnership's operations that are based on management's current expectations, estimates and projections about its operations. Words and phrases such as "believes," "expects," "future," "impact," "guidance," "will be" 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 and other sources of liquidity to execute our business plan, prices and demand for natural gas and oil, increases in operating costs, uncertainties inherent in estimating our reserves and production, 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, risks relating to our acquisitions, 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 February 29, 2012, and if applicable, 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, the Partnership 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.

BBEP-IR

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets
				June 30,											December 31,
Thousands				2012											2011
ASSETS
Current assets
Cash				$	4,066										$	5,328
Accounts and other receivables, net					55,575											73,018
Derivative instruments					79,616											83,452
Related party receivables					2,075											4,245
Inventory					5,267											4,724
Prepaid expenses					2,404											2,053
Total current assets					149,003											172,820
Equity investments					7,182											7,491
Property, plant and equipment
Oil and gas properties					2,719,580											2,583,993
Other assets					13,695											13,431
					2,733,275											2,597,424
Accumulated depletion and depreciation					(592,825	)										(524,665	)
Net property, plant and equipment					2,140,450											2,072,759
Other long-term assets
Derivative instruments					87,161											55,337
Other long-term assets					47,694											22,442
Total assets				$	2,431,490										$	2,330,849
LIABILITIES AND EQUITY
Current liabilities
Accounts payable				$	36,949										$	33,494
Derivative instruments					2,487											8,881
Revenue and royalties payable					16,059											19,641
Salaries and wages payable					7,998											13,655
Accrued liabilities					14,732											14,218
Total current liabilities					78,225											89,889
Credit facility					225,000											520,000
Senior notes, net					548,841											300,613
Deferred income taxes					2,929											2,803
Asset retirement obligation					84,802											82,397
Derivative instruments					1,104											3,084
Other long-term liabilities					4,823											4,849
Total liabilities					945,724											1,003,635
Equity
Partners' equity					1,485,766											1,326,764
Noncontrolling interest					-											450
Total equity					1,485,766											1,327,214
Total liabilities and equity				$	2,431,490										$	2,330,849
Common units outstanding					69,144											59,864

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Operations
				Three Months Ended														Six Months Ended
				June 30,														June 30,
Thousands of dollars, except per unit amounts				2012						2011								2012						2011
Revenues and other income items
Oil, natural gas and natural gas liquid sales				$	94,981					$	94,742							$	188,988					$	187,317
Gain (loss) on commodity derivative instruments, net					107,288						46,483								71,283						(59,694	)
Other revenue, net					907						1,143								2,052						2,041
Total revenues and other income items					203,176						142,368								262,323						129,664
Operating costs and expenses
Operating costs					48,894						36,208								92,155						73,019
Depletion, depreciation and amortization					33,517						25,025								71,798						49,666
General and administrative expenses					12,926						11,656								26,600						24,127
Loss on sale of assets					29						40								154						54
Total operating costs and expenses					95,366						72,929								190,707						146,866
Operating income (loss)					107,810						69,439								71,616						(17,202	)
Interest expense, net of capitalized interest					14,069						9,080								27,869						18,500
Loss on interest rate swaps					190						2,220								684						1,877
Other expense (income), net					23						-								19						(3	)
Income (loss) before taxes					93,528						58,139								43,044						(37,576	)
Income tax expense (benefit)					1,005						616								446						(386	)
Net income (loss)					92,523						57,523								42,598						(37,190	)
Less: Net income attributable to noncontrolling interest					(17	)					(68	)							(62	)					(102	)
Net income (loss) attributable to the partnership					92,506						57,455								42,536						(37,292	)
Basic net income (loss) per unit				$	1.29					$	0.93							$	0.61					$	(0.64	)
Diluted net income (loss) per unit				$	1.29					$	0.92							$	0.61					$	(0.64	)

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows
				Six Months Ended
				June 30,
Thousands of dollars				2012											2011
Cash flows from operating activities
Net income (loss)				$	42,598										$	(37,190	)
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation and amortization					71,798											49,666
Unit-based compensation expense					11,203											10,858
Unrealized loss (gain) on derivative instruments					(29,406	)										64,175
Income from equity affiliates, net					309											159
Deferred income taxes					126											(518	)
Loss on sale of assets					154											54
Other					2,367											(244	)
Changes in assets and liabilities:
Accounts receivable and other assets					9,970											4,171
Inventory					(543	)										(21	)
Net change in related party receivables and payables					2,170											1,713
Accounts payable and other liabilities					(10,195	)										(5,306	)
Net cash provided by operating activities					100,551											87,517
Cash flows from investing activities
Capital expenditures					(37,382	)										(35,136	)
Proceeds from sale of assets					674											110
Deposit for oil and gas properties					(21,954	)										-
Property acquisitions					(92,837	)										-
Net cash used in investing activities					(151,499	)										(35,026	)
Cash flows from financing activities
Issuance of common units					166,044											100,204
Distributions					(60,750	)										(49,470	)
Proceeds from issuance of long-term debt, net					538,885											133,500
Repayments of long-term debt					(586,000	)										(234,500	)
Change in book overdraft					(2,785	)										5
Debt issuance costs					(5,708	)										(3,113	)
Net cash provided by (used in) financing activities					49,686											(53,374	)
Decrease in cash					(1,262	)										(883	)
Cash beginning of period					5,328											3,630
Cash end of period				$	4,066										$	2,747

Investor Relations Contacts:
BreitBurn Energy Partners L.P.
James G. Jackson
Executive Vice President and Chief Financial Officer
213-225-5900 x273
or
Jessica Tang
Investor Relations
213-225-5900 x210

Source: BreitBurn Energy Partners L.P.

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