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

Posted on: Monday, 17 March 2008, 09:01 CDT

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

QuarterEndedDecember 31,2007

QuarterEndedSeptember 30,2007

QuarterEndedJune 30,2007

QuarterEndedMarch 31,2007

YearEndedDecember 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

QuarterEndedDecember 31,2007

QuarterEndedSeptember 30,2007

QuarterEndedJune 30,2007

QuarterEndedMarch 31,2007

YearEndedDecember 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 MonthsEnded December 31,2007

Three MonthsEnded September 30,2007

Three MonthsEnded June 30,2007

Three MonthsEnded March 31,2007

Year EndedDecember 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 SubsidiariesConsolidated Statement of Cash Flows

Thousands of dollars

Three MonthsEnded December 31,2007

Three MonthsEnded September 30,2007

Three MonthsEnded June 30,2007

Three MonthsEnded March 31,2007

Year EndedDecember 312007

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.

Source: Business Wire

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