8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
______________

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15 (d)OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report: March 17, 2008(Date of earliest event reported)
______________

BREITBURN ENERGY PARTNERS L.P.

(Exact name of registrant as specified in its charter)
______________

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

515 South Flower Street, Suite 4800

Los Angeles, CA 90071

(Address of principal executive offices)

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

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

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

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

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

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

Item 2.02     Results of Operations and Financial Condition.

On March 17, 2008, BreitBurn Energy Partners L.P. (the "Partnership") issued a press release announcing financial results for the fourth quarter 2007. A copy of the press release is attached to this Current Report on Form 8-K as Exhibit 99.1 and is incorporated herein solely for purposes of this Item 2.02 disclosure.

The information in this Current Report on Form 8-K provided under Item 2.02, including Exhibit 99.1 attached hereto, shall not be deemed to be "filed" for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to the liabilities of that Section, and shall not be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01     Financial Statements and Exhibits.

(d)  Exhibits.

Exhibit No.	Exhibit Description
99.1	BreitBurn Energy Partners L.P. fourth quarter 2007 earnings release dated March 17, 2008.

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 hereunto duly authorized.

		BREITBURN ENERGY PARTNERS L.P.
		By:	BREITBURN GP, LLC,
			its general partner
Date:	March 17, 2008	By:	/s/ Randall H. Breitenbach
			Randall H. Breitenbach
			Co-Chief Executive Officer

EX-99.1

Exhibit 99.1

BreitBurn Energy Partners Reports Fourth Quarter and Full Year 2007 Results; Provides 2008 Guidance

Estimated Proved Reserves Increase 363% to 142.2 MMBoe

Will Recommend a 10.5% Increase in Distributions to an Annualized Rate of $2.00 Per Unit

LOS ANGELES--(BUSINESS WIRE)--BreitBurn Energy Partners L.P. (the "Partnership") (NASDAQ:BBEP), today announced operating and financial results for its fourth quarter and full year 2007 and guidance for full year 2008.

Highlights of Fourth Quarter 2007 Results Compared to Third Quarter 2007:

• Increased Adjusted EBITDA, a non-GAAP measure, by 105% to $43.5 million from $21.2 million
• Grew production by 110% to 1,389,000 Boe from 661,000 Boe
• Increased net income by 12% to $16.5 million, excluding the effect of unrealized losses on commodity derivative instruments
• Closed the transformative acquisition of Quicksilver Resources Inc.’s oil and gas assets in Michigan, Indiana and Kentucky
• Appointed Mark Pease as Chief Operating Officer
• Paid a distribution for the fourth quarter of $0.4525 per unit, or $1.81 on an annualized basis, on February 14, 2008.

Hal Washburn, Co-CEO of BreitBurn, said, "We are pleased with our fourth quarter operating and financial performance, which capped off an extraordinary year of growth for the Partnership. We increased our production, Adjusted EBITDA and reserves through a combination of organic reserve replacement and seven acquisitions totaling approximately $1.7 billion. These acquisitions were transformative as they provide us the opportunity to grow our production and our proved reserves through ongoing development and exploitation activities without significant reliance on future acquisitions. In addition, our existing financial position and credit facility should enable us to execute the associated capital programs. As a result, we believe BreitBurn is well positioned in this period of high commodity prices and challenging general financial markets to provide our equity holders with an attractive and competitive investment opportunity.”

Washburn concluded, “For the first quarter of 2008, we intend to recommend to the Board a 10.5% increase in our distributions to an annualized rate of $2.00 per unit. In addition, we will look to make incremental distribution increases throughout the year, based on our operating performance, and are targeting a $2.30 distribution rate per unit for the fourth quarter of 2008. Without question, our current outlook with respect to achieving a distribution level of $2.30 is later than we originally targeted when we announced the acquisition of the Michigan, Indiana and Kentucky assets from Quicksilver in September 2007. This delay is primarily due to the seller’s suspension of expected development drilling activities on these properties during the sales process which continued into the early stages of the integration process, together with other factors affecting the industry generally. The integration of these assets is now well underway, development activities have increased, and we remain confident in our outlook for the potential of these assets and their complementary fit for BreitBurn.”

Fourth Quarter 2007 Results

Including unrealized losses on derivative instruments of $63.6 million, net loss for the fourth quarter totaled $47.1 million, or a loss of $0.86 per diluted limited partnership unit. The unrealized losses reflect the impact of higher crude oil and natural gas futures prices on our commodity derivative instruments covering future production. Excluding the impact of unrealized losses on commodity derivative instruments, adjusted net income for the fourth quarter of 2007 would have been $16.5 million. In the third quarter of 2007, the net loss was $7.5 million, or a loss of $0.25 per diluted limited partnership unit, including unrealized losses of $22.2 million. Excluding the impact of unrealized losses on commodity derivative instruments in the third quarter of 2007, net income for the third quarter of 2007 would have been $14.7 million.

Adjusted earnings before interest, taxes, depreciation and amortization ("Adjusted EBITDA") totaled $43.5 million, which was $22.3 million higher than the third quarter of 2007, due primarily to higher production volumes from the recent acquisition of assets and equity interests in certain entities from Quicksilver Resources Inc. (“Quicksilver”) and overall higher commodity prices. (See "Non-GAAP Financial Measures" and the associated tables for a discussion of management's use of Adjusted EBITDA in this release.)

Production

Aggregate production during the fourth quarter totaled 1,389,000 Boe, an increase of 728,000 Boe from the immediately preceding quarter. This production growth was principally driven by the Quicksilver acquisition completed on November 1, 2007, which contributed 719,000 Boe of this increase. Other than the Quicksilver acquisition, production during the quarter increased from the prior period by 9,000 Boe, primarily due to a 21,000 Boe increase from production in Florida, partially offset by natural declines from other properties.

Revenues and Realized Prices

Excluding the effect of derivatives, our oil, natural gas and natural gas liquid sales were $81.0 million, or $59.94 per Boe, in the fourth quarter of 2007. Including the effects of realized losses on commodity derivative instruments, realized prices were $54.10 per Boe. This compared to oil, natural gas and natural gas liquid sales of $49.5 million, or $61.37 per Boe, in the third quarter of 2007. Including the effects of realized losses on commodity derivative instruments, realized prices in the third quarter of 2007 were $58.10 per Boe. The lower average realized prices in the fourth quarter reflect our new sales mix of natural gas and crude oil, which was 52% crude oil and 48% natural gas, compared to the third quarter in which our sales mix was 98% crude oil and 2% natural gas.

Lease and other Operating Expenses

Lease operating expenses for the fourth quarter totaled $26.1 million, or $17.76 per Boe, compared with $13.8 million, or $20.82 per Boe in the third quarter of 2007. This was a decrease of $3.06 per Boe from the third quarter due to the lower operating costs per Boe associated with our production from properties in Michigan, Indiana and Kentucky acquired in the fourth quarter of 2007.

Other operating expenses in the fourth quarter included $1.3 million in processing fees related to our Michigan assets. In addition, fourth quarter transportation related expenses, primarily from our Florida operations, were $1.1 million compared with $1.5 million in the third quarter. There was also a $2.3 million benefit from an inventory change during the fourth quarter, reflecting an increase in crude oil inventory held for sale. By comparison, during the third quarter, there was a $5.4 million charge reflecting costs associated with the inventory that was sold.

On a sequential basis, we expect our total operating expenses will be higher than levels reported in 2007, primarily as a result of acquisitions completed in 2007. In addition, although we expect operating expense per unit of production to decrease due to the change in production mix as a result of these acquisitions, because our operating expenses are directly related to commodity prices, we expect to continue to experience pressure on operating expenses associated with fuel, electricity and oilfield services in general. In addition, we expect production and severance taxes, which also move directly with commodity prices, to increase as well.

Depletion, Depreciation and Amortization (DD&A)

DD&A expenses for the fourth quarter totaled $15.7 million, or $11.29 per Boe, compared with $6.1 million, or $9.30 per Boe, for the third quarter of 2007. The sequential increase in DD&A expenses reflects the Quicksilver acquisition completed in the fourth quarter of 2007.

General and Administrative Expenses (G&A)

G&A expenses for the fourth quarter totaled $11.1 million, including $3.9 million of unit-based compensation expenses relating to incentive plans. This amount included a charge of $2.4 million for the conversion of the cash-based executive phantom options plan to a unit-based plan. During the third quarter of 2007, G&A expenses totaled $5.1 million, including $1.5 million of unit-based compensation expense related to incentive plans. Fourth quarter G&A expenses, excluding unit-based compensation, were $3.6 million higher than the third quarter reflecting $2.2 million in higher staffing levels, principally associated with the Quicksilver acquisition and $1.4 million in higher professional services expenses. The increase in professional services expenses included $0.6 million for transition related services provided by Quicksilver for accounting, land administration and gas marketing.

2007 Results

For the full year 2007, Adjusted EBITDA totaled $85.3 million. Production volumes grew 1.4 million barrels of oil equivalent (MMBoe), or 84% year-over-year, with acquisitions accounting for 99% of the increase from 2006. Total revenues, including unrealized gains and losses on commodity derivative instruments, were approximately $75.0 million in 2007, a $20.3 million decline from 2006 as a result of $103.9 million in unrealized losses from derivative instruments compared to a gain of $3.3 million in 2006. The unrealized losses in 2007 reflected higher crude oil and natural gas prices. Offsetting the unrealized losses from derivative instruments were higher sales volumes of 3.1 MMBoe in 2007 compared with 1.6 MMBoe in 2006. Our net loss in 2007 was $60.4 million, or $1.83 per diluted limited partnership unit.

2007 Reserves

As of December 31, 2007, our estimated proved reserves were 142.2 MMBoe, an increase of 363% when compared to our 30.7 MMBoe as of December 31, 2006. The 111.5 MMBoe increase is primarily a result of acquiring 111.3 MMBoe of proved reserves in 2007. In addition to being successful on the acquisition front, we had a good year with organic reserve replacement. The 2007 reserve replacement ratio excluding the acquisitions and their associated production was 198%. This percentage excludes 1,354 MBoe of production associated with the acquisitions and includes the estimated reserve changes associated with additions, extensions, and revisions due to infill drilling, performance and price changes. Using the same methodology, and excluding the revisions due to performance and price changes, the 2007 reserve replacement ratio was 93%.

The Standardized Measure of discounted (at 10%) net future cash flows from the production of these reserves is approximately $1.9 billion at December 31, 2007, using prices and costs in effect as of the dates such estimates were made and which are held constant throughout the life of the properties. Of the total estimated proved reserves, 41% were oil, 90% were classified as proved developed and 61% were located in Michigan, 17% in California, 10% in Wyoming, 8% in Florida, 2% in Indiana, 1% in Texas and less than 1% in Kentucky.

2008 Guidance

The following guidance is subject to all cautionary statements and limitations described below and under the caption “Cautionary Statement Relevant to 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. Lease operating expenses, 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. Lease 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 lease 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 Thousands, unless otherwise noted)	Full Year 2008
Total Production (Mboe)	6,700	-	7,300
Average Daily Production (boe)	18,300	-	20,000
Production Mix:
Oil Production %		44%
Gas Production %		56%
Average Price Differential %:
Oil Price Differential %	84%	-	86%
Gas Price Differential %	100%	-	102%
LOE / BOE(1)	$14.00	-	$15.40
Taxes / BOE(1)	$3.15	-	$3.50
G&A (Excl. Unit Based Compensation)(2)(3)	$37,000	-	$39,000
Cash Interest Expense(4)	$21,000	-	$23,000
Total Capital Expenditures	$115,000	-	$125,000
Maintenance & Obligatory Capital Expenditures(5)	$54,000	-	$56,000

	2008 Quarterly Production Guidance
	1Q			2Q			3Q			4Q
Total Production (Mboe)	1,650	-	1,750	1,600	-	1,700	1,700	-	1,900	1,750	-	1,950
Average Daily Production (boe)	18,000	-	19,250	17,500	-	18,750	18,750	-	20,500	19,250	-	21,250

Notes

1.	Estimated Lease Operating Expenses and Taxes are based on current WTI price levels, declining to $85.00 for the second half of 2008 and approximately $8.00 per mcfe gas price. Management expects these expenses to increase or decrease with corresponding changes in commodity prices. More specifically, in the event commodity prices continue at their current levels, management would expect these expenses to increase accordingly.
2.	Due to the timing of certain audit, tax, legal, advisory and other professional services being performed for the Partnership, as well as certain costs related to the ongoing integration of the recently completed acquisition of certain assets from Quicksilver, the Partnership estimates that approximately 30% of the projected annual general and administrative expense should be incurred in the first three months of 2008 and approximately 55% of the projected annual expense should be incurred in the first half of 2008.
3.	Includes expense of $1.3 million for unit-price based long-term incentive compensation plans which pay out in cash and are tied to BBEP or Provident Energy Trust (NYSE:PVX) unit prices and assumes BBEP and PVX unit prices remain at their March 14, 2008 levels of $20.23 and $10.85, respectively for the remainder of 2008. Each $1 change in the BBEP or PVX unit price during the remainder of the year would result in a corresponding change of $.30 million or $.25 million, respectively.
4.	The Partnership typically borrows on a 1-month LIBOR basis, plus an applicable spread. Estimated cash interest expense assumes a weighted average 1-month LIBOR rate of approximately 4.00% for 2008 and includes the impact of three interest rate swaps entered into in January 2008 covering $200 million of borrowings at a weighted average swap rate of 3.46%.
5.	Maintenance & Obligatory Capital Expenditures are defined as the average estimated amount of investment in capital projects, and obligatory spending on existing facilities and operations, needed to hold production approximately constant for the period.

2008 Hedge Portfolio Summary

The table below summarizes the Partnership’s 2008 hedge portfolio and includes the effects of the restructuring of a portion of our 2008 fixed price swaps completed on March 14, 2008.

	2008 Hedge Portfolio Summary
	Q1	Q2	Q3	Q4	FY 2008
Oil Hedges (Mbbls):
Swap Volume (including FL)	468	464	273	317	1,525
W.A. Swap Price	$70.52	$78.97	$78.64	$77.20	$75.94
Participatory Swap Volume	39	39	292	246	613
W.A. Swap Price	$60.00	$60.00	$60.70	$60.93	$60.74
% Participation	76.1%	76.1%	57.0%	61.7%	61.3%
Collar Volume	46	46	--	--	92
W.A. Floor Price	$66.00	$66.00	--	--	$66.00
W.A. Ceiling Price	70.38	70.38	--	--	70.38
Gas Hedges(mmbtu):
Volume Hedged	4,598	4,482	4,419	4,301	17,803
W.A. Price	$8.01	$8.01	$8.01	$8.01	$8.01

Cash Distribution

On February 14, the Partnership paid a cash distribution of approximately $30.5 million, or $0.4525 per common unit, to its general partner and common unitholders of record as of the close of business on February 11, 2008.

Management intends to recommend to the Board a 10.5% increase in distributions for the first quarter of 2008 to a $2.00 per unit annualized rate. Management’s previously announced intention to recommend to the Board an increase to a $2.30 annualized rate for the first quarter of 2008 has been delayed, primarily due to the suspension of expected development drilling activities in Michigan, Indiana and Kentucky by the seller during the sales process which continued into the early stages of the integration process, together with other factors affecting the industry generally. Management is targeting to recommend to the Board a $2.30 per unit annualized distribution rate for the fourth quarter of 2008 through incremental increases during the year based on the Partnership’s operating and financial performance.

The Board's approval of recommended increases is subject to a review of future operating results including production, commodity prices, operating costs, capital requirements, and other factors affecting BreitBurn's business.

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 are "Adjusted EBITDA." This non-GAAP financial measure should not be considered as an alternative to GAAP measures, such as net income, operating income or any other GAAP measure of liquidity or financial performance.

Adjusted EBITDA is presented as management believes it provides additional information and metrics relative to the performance of the Partnership's business, such as the cash distributions we expect to pay to our unitholders, as well as our ability to meet our debt covenant compliance tests. Management believes that these financial measures indicate to investors whether or not cash flow is being generated at a level that can sustain or support an increase in our quarterly distribution rates. Adjusted EBITDA may not be comparable to a similarly titled measure of other publicly traded partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner.

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

Thousands of dollars	Quarter Ended December 31, 2007			Quarter Ended September 30, 2007			Quarter Ended June 30, 2007			Quarter Ended March 31, 2007			Year Ended December 31, 2007
Reconciliation of consolidated net loss to Adjusted EBITDA:
Net loss	$	(47,066	)	$	(7,467	)	$	(1,068	)	$	(4,756	)	$	(60,357	)
Unrealized loss on derivative instruments		63,581			22,212			8,373			9,696			103,862
Depletion, depreciation and amortization expense		15,678			6,146			4,511			3,087			29,422
Interest expense and other financing costs		4,635			522			603			498			6,258
Income tax provision		(667	)		(250	)		(215	)		(97	)		(1,229	)
Non-cash unit based compensantion		5,133			-			-			-			5,133
Amortization of intangibles		2,174			-			-			-			2,174
Adjusted EBITDA	$	43,468		$	21,163		$	12,204		$	8,428		$	85,263
Thousands of dollars	Quarter Ended December 31, 2007			Quarter Ended September 30, 2007			Quarter Ended June 30, 2007			Quarter Ended March 31, 2007			Year Ended December 31, 2007
Reconciliation of net cash from operating activities to Adjusted EBITDA:
Net cash from operating activities	$	11,002		$	22,110		$	13,568		$	13,422		$	60,102
Add:
Increase (decrease) in assets net of liabilities
relating to operating activities		33,978			189			1,641			(5,437	)		30,371
Cash interest expense		2,348			238			844			115			3,545
Equity earnings from affiliates, net		9			(75	)		12			82			28
Stock based compensantion expense		(3,887	)		(1,546	)		(4,020	)		(3,546	)		(12,999	)
Stock based compensation paid		23			76			(52	)		3,729			3,776
Minority interest		(44	)		(37	)		(10	)		-			(91	)
Other		39			208			221			63			531
Adjusted EBITDA	$	43,468		$	21,163		$	12,204		$	8,428		$	85,263

Conference Call

As announced on March 11, 2008, the Partnership will host an investor conference call to discuss its results today at 9:00 a.m. (Eastern). 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 888-221-3848 (international callers dial +1-913-312-0838) 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 24, 2008 by dialing 888-203-1112 (international callers dial +1-719-457-0820) and entering replay PIN 9806424, 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.

Annual Report on Form 10-K

The Partnership expects to file its Annual Report on Form 10-K for the year ended December 31, 2007 with the Securities and Exchange Commission today, March 17, 2008.

About BreitBurn Energy Partners L.P.

BreitBurn Energy Partners L.P. is a publicly traded independent oil and gas limited partnership focused on the acquisition, exploitation and development of oil and gas properties. The Partnership’s producing and non-producing crude oil and natural gas reserves are located in the Antrim Shale in Michigan, the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Sunniland Trend in Florida, the New Albany Shale in Indiana and Kentucky, and the Permian Basin in West Texas. See www.BreitBurn.com for more information.

BBEP-IR

Cautionary Statement Relevant to 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 such as "anticipates," "expects," "intends," "plans," "targets," "projects," "believes," "seeks," "schedules," "estimates," "recommends," "intention to recommend," “in the future,” “guidance” 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. 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.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: inaccuracies in the estimated timing and amount of future production of oil and natural gas due to numerous factors including permit delays or restrictions, weather, equipment failures, delays or lack of availability, unexpected subsurface or geologic conditions, lack of capital, increases in operating costs, volumes of oil or gas greater or lesser than anticipated, and changes in applicable regulations and laws; unexpected problems with wells or other equipment, particularly in our Florida properties where production is concentrated in relatively few wells; the lack of availability of drilling and production equipment or unexpected increases in the cost of such equipment; unexpected changes in operating costs and other expenses, including utilities, labor, transportation, well and oil field services, taxes, permit fees, regulatory compliance, and other costs of operation; the potential for oil and gas operating costs to increase while corresponding sales prices of oil and gas are wholly or partially fixed due to our use of derivative contracts, or "hedges" to limit price volatility; the potential impact of a change in our ownership (see “Business – Potential Sale by Provident of its Interest in the Partnership and BreitBurn Energy” in our Annual Report on Form 10-K for the year ended December 31, 2007 to be filed with the Securities and Exchange Commission and “Risk Factors – Risks Related to a Potential Sale by Provident of its Interest in the Partnership and BreitBurn Energy” in our current report on Form 8-K filed on February 12, 2008); changes in crude oil and natural gas prices, including price discounts and basis differentials; management changing its recommendation or the Board not accepting such a recommendation regarding distributions after reviewing all relevant factors the competitiveness of alternate energy sources or product substitutes; technological developments; the future performance of the properties acquired from Quicksilver Resources Inc.; the discovery of previously unknown environmental issues; inaccuracies in estimating the amount, nature and timing of capital expenditures, including future development costs; potential disruption or interruption of BreitBurn's net production due to accidents or severe weather; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule setting bodies; the inability to predict the availability and terms of capital; issues with marketing of oil and natural gas including lack of access to markets, changes in pipeline and transportation tariffs and costs, increases in minimum sales quality standards for oil or natural gas, changes in the supply-demand status of oil or gas in a given market area, and the introduction of increased quantities of oil or natural gas into a given area due to new discoveries or new delivery systems; and the factors set forth under the heading "Risk Factors" incorporated by reference from our Annual Report on Form 10-K for the year ended December 31, 2006, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007, June 30, 2007 and September 30, 2007, our Annual Report on Form 10-K for the year ended December 31, 2007 scheduled to be filed with the Securities and Exchange Commission today, and other filings with the Securities and Exchange Commission. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Operations
Thousands of dollars, except per unit amounts	Three Months Ended December 31, 2007	Three Months Ended September 30, 2007	Three Months Ended June 30, 2007	Three Months Ended March 31, 2007	Year Ended December 31, 2007
Revenues and other income items:
Oil, natural gas and natural gas liquid sales	$ 81,042	$ 49,528	$ 32,413	$ 21,389	$ 184,372
Realized gain (loss) on derivative instruments	(7,851)	(2,555)	822	3,028	(6,556)
Unrealized loss on derivative instruments	(63,581)	(22,212)	(8,373)	(9,696)	(103,862)
Other revenue, net	429	130	237	241	1,037
Total revenues and other income items	10,039	24,891	25,099	14,962	74,991
Operating costs and expenses:
Operating costs	26,258	20,775	14,604	8,692	70,329
Depletion, depreciation and amortization	15,678	6,146	4,511	3,087	29,422
General and administrative expenses	11,051	5,057	6,633	7,503	30,244
Total operating costs and expenses	52,987	31,978	25,748	19,282	129,995
Operating loss	(42,948)	(7,087)	(649)	(4,320)	(55,004)
Interest and other financing costs, net	4,635	522	603	498	6,258
Other expenses, net	106	71	21	35	233
Total other expense	4,741	593	624	533	6,491
Loss before taxes and minority interest	(47,689)	(7,680)	(1,273)	(4,853)	(61,495)
Income tax expense (benefit)	(667)	(250)	(215)	(97)	(1,229)
Minority interest	44	37	10	–	91
Net loss	$ (47,066)	$ (7,467)	$ (1,068)	$ (4,756)	$ (60,357)
General Partner's interest in net loss	(447)	(114)	(16)	(95)	(672)
Limited Partners' interest in net loss	$ (46,619)	$ (7,353)	$ (1,052)	$ (4,661)	$ (59,685)
Basic net loss per limited partner unit	$ (0.86)	$ (0.25)	$ (0.04)	$ (0.21)	$ (1.83)
Diluted net loss per limited partner unit	$ (0.86)	$ (0.25)	$ (0.04)	$ (0.21)	$ (1.83)
Weighted average number of units used to calculate
Basic net loss per limited partner unit	54,349,093	29,006,002	24,816,419	21,975,758	32,536,818
Diluted net loss per limited partner unit	54,349,093	29,006,002	24,816,419	21,975,758	32,536,818

BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Balance Sheets
	December 31,			December 31,
Thousands of dollars	2007			2006
ASSETS
Current assets:
Cash and cash equivalents	$	5,929		$	93
Accounts receivable		44,202			10,356
Non-hedging derivative instruments		948			3,998
Related party receivables		35,568			4,868
Inventory		5,704			–
Prepaid expenses		2,083			215
Intangibles		3,169			–
Other current assets		160			85
Total current assets		97,763			19,615
Equity investments		15,645			142
Property, plant and equipment
Oil and gas properties		1,910,941			203,911
Non-oil and gas assets		568			569
		1,911,509			204,480
Accumulated depletion and depreciation		(47,022	)		(18,610	)
Net property, plant and equipment		1,864,487			185,870
Other long-term assets
Intangibles		3,228			–
Other long-term assets		5,433			276
Total assets	$	1,986,556		$	205,903
LIABILITIES AND PARTNERS' EQUITY
Current liabilities:
Accounts payable	$	13,910		$	3,308
Book overdraft		1,920			2,036
Non-hedging derivative instruments		35,172			–
Related party payables		10,137			4,572
Accrued liabilities		29,545			2,201
Total current liabilities		90,684			12,117
Long-term debt		370,400			1,500
Long-term related party payables		1,532			467
Deferred income taxes		3,074			4,303
Asset retirement obligation		27,819			10,253
Non-hedging derivative instruments		65,695			55
Other long-term liability		2,000			–
Total liabilities		561,204			28,695
Minority interest		544			–
Partners' equity		1,424,808			177,208
Total liabilities and partners' equity	$	1,986,556		$	205,903

BreitBurn Energy Partners L.P. and Subsidiaries Consolidated Statement of Cash Flows
Thousands of dollars	Three Months Ended December 31, 2007	Three Months Ended September 30, 2007	Three Months Ended June 30, 2007	Three Months Ended March 31, 2007	Year Ended December 31 2007
Cash flows from operating activities
Net loss	$ (47,066)	$ (7,467)	$ (1,068)	$ (4,756)	$ (60,357)
Adjustments to reconcile to cash flow from operating activities:
Depletion, depreciation and amortization	15,678	6,145	4,511	3,088	29,422
Stock based compensation expense	3,887	1,546	4,020	3,546	12,999
Stock based compensation paid	(23)	(76)	52	(3,729)	(3,776)
Unrealized loss on derivative instruments	63,581	22,212	8,372	9,697	103,862
Equity in earnings of affiliates, net of dividends	(9)	75	(12)	(82)	(28)
Deferred income tax	(406)	(283)	(443)	(97)	(1,229)
Minority interest	44	37	10	–	91
Amortization of intangibles	2,174	-	-	–	2,174
Other	1,987	110	(233)	318	2,182
Changes in net assets and liablities:
Accounts receivable and other assets	(9,551)	(6,289)	(7,972)	(901)	(24,713)
Inventory	(3,410)	5,377	2,862	–	4,829
Due to (from) related parties	(37,738)	(30)	(1,717)	4,059	(35,426)
Accounts payable and other liabilities	21,854	753	5,186	2,279	30,072
Net cash provided by operating activities	11,002	22,110	13,568	13,422	60,102
Cash flows from investing activities (a)
Capital expenditures	(5,351)	(6,947)	(9,650)	(1,601)	(23,549)
Property acquisitions	(729,820)	(35,752)	(200,961)	(30,028)	(996,561)
Net cash used by investing activities	(735,171)	(42,699)	(210,611)	(31,629)	(1,020,110)
Cash flows from financing activities
Issuance of common units	441,338	–	222,000	–	663,338
Repayments of initial distributions by predecessor members	–	–	–	581	581
with initial public offering	–	–	–	–	–
Distributions	(29,855)	(12,445)	(9,250)	(8,947)	(60,497)
Proceeds from the issuance of long-term debt	431,200	67,000	25,200	51,300	574,700
Repayments of long-term debt	(108,800)	(32,500)	(41,800)	(22,700)	(205,800)
Book overdraft	(2,066)	2,135	1,450	(1,635)	(116)
Long-term debt issuance costs	(6,171)	(190)	–	(1)	(6,362)
Net cash provided by financing activities	725,646	24,000	197,600	18,598	965,844
Increase in cash	1,477	3,411	557	391	5,836
Cash beginning of period	4,452	1,041	484	93	93
Cash end of period	$ 5,929	$ 4,452	$ 1,041	$ 484	$ 5,929
(a) Non-cash investing activity in 2007 was $700 million, reflecting the issuance of 21.348 million Common Units for the Quicksilver Acquisition.

CONTACT:
BreitBurn Energy Partners L.P.
James G. Jackson, 213-225-5900 ext. 273
Executive Vice President and Chief Financial Officer
or
Ruder Finn/West
Pierre Hirsch, 415-692-3060