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Press release from Business Wire

BreitBurn Energy Partners L.P. Reports Fourth Quarter and Full Year Results; Provides Full Year 2012 Guidance

Tuesday, February 28, 2012

BreitBurn Energy Partners L.P. Reports Fourth Quarter and Full Year Results; Provides Full Year 2012 Guidance08:50 EST Tuesday, February 28, 2012 LOS ANGELES (Business Wire) -- BreitBurn Energy Partners L.P. (the “Partnership”) (NASDAQ:BBEP) today announced financial and operating results for its fourth quarter and full year 2011 as well as public guidance for its expected performance in 2012, excluding any future acquisitions. Key Highlights The Partnership had strong fourth quarter operating and financial results, with net production increasing 23% and EBITDA increasing 22% from the third quarter of 2011. During 2011, the Partnership increased proved reserves by 32.2 MMBoe to 151.1 MMBoe, representing a 27% increase from 118.9 MMBoe at year-end 2010. Reserve replacement from all sources was 558% of 2011 production. On February 14, 2012, the Partnership paid cash distributions for the fourth quarter of 2011 of $0.45 per unit, or an annualized rate of $1.80 per unit, representing an increase from an annualized rate of $1.74 per unit for the third quarter of 2011. On October 6, 2011, the Partnership completed the acquisition of gas and oil properties in the Evanston and Green River Basins in southwestern Wyoming for approximately $281 million. On January 13, 2012, the Partnership completed a private offering of $250 million in aggregate principal amount of 7.875% Senior Notes due 2022. Net proceeds from the offering were used to reduce borrowings under the Partnership's bank credit facility. On February 8, 2012, the Partnership completed a public offering of 9.2 million common units. Net proceeds from the offering were used to further reduce borrowings under the Partnership's bank credit facility. As of February 27, 2012, the Partnership had $88 million in outstanding borrowings under its bank credit facility, which had a borrowing base of approximately $788 million. During the fourth quarter of 2011, Quicksilver Resources completed the sale of all of its remaining common units of the Partnership. Management Commentary Hal Washburn, CEO, said: “The Partnership delivered very strong fourth quarter and full year results that significantly exceeded our production and EBITDA targets for 2011. During the year, we completed two attractive acquisitions that greatly expanded our presence in Wyoming. With our most recent distribution, we have increased our distributions per unit by 9% since the fourth quarter of 2010. The Partnership also reduced its outstanding borrowings and increased its financial flexibility with the completion of a Senior Notes offering and equity offering earlier this year. We are well positioned to continue executing on our growth through acquisitions strategy and are excited about the opportunities we see for 2012.” Fourth Quarter 2011 Operating and Financial Results Compared to Third Quarter 2011 Total production increased to a record quarterly high of 2,065 MBoe in the fourth quarter of 2011 from 1,681 MBoe in the third quarter of 2011. Average daily production was 22,450 Boe/day in the fourth quarter of 2011 compared to 18,273 Boe/day in the third quarter of 2011. Oil and NGL production was 871 MBoe compared to 829 MBoe. Natural gas production was 7,168 MMcf compared to 5,114 MMcf. Adjusted EBITDA, a non-GAAP measure, was a record quarterly high of $64.4 million in the fourth quarter of 2011, increasing from $52.9 million in the third quarter of 2011. Lease operating expenses per Boe, which include district expenses and processing fees and exclude production and property taxes and transportation costs, decreased to $17.77 per Boe in the fourth quarter of 2011 from $21.66 per Boe in the third quarter of 2011. On a per Boe basis, general and administrative expenses, excluding non-cash unit-based compensation, decreased to $4.59 per Boe in the fourth quarter of 2011 from $5.09 per Boe in the third quarter of 2011. Oil and natural gas sales revenues, including realized gains and losses on commodity derivative instruments and excluding a $36.8 million loss related to the early termination of crude oil derivative contracts, were $117.6 million in the fourth quarter of 2011, up from $105.4 million in the third quarter of 2011, primarily reflecting higher crude oil prices and higher sales volumes for both crude oil and natural gas. Realized losses on commodity derivative instruments were $28.9 million in the fourth quarter of 2011 compared to realized gains of $8.1 million in the third quarter of 2011, reflecting the $36.8 million loss on the early termination of crude oil derivative contracts. Excluding the loss on termination, realized gains on commodity derivative instruments would have been $7.9 million in the fourth quarter of 2011. NYMEX WTI crude oil spot prices averaged $94.01 per barrel and Henry Hub natural gas spot prices averaged $3.33 per Mcf in the fourth quarter of 2011 compared to $89.49 per barrel and $4.12 per Mcf, respectively, in the third quarter of 2011. Brent crude oil spot prices averaged $109.42 per barrel in the fourth quarter of 2011 compared to $113.24 in the third quarter of 2011. Realized crude oil and NGL prices, excluding the realized loss on termination of oil derivatives, averaged $84.00 per Boe and realized natural gas prices averaged $6.02 per Mcf in the fourth quarter of 2011, compared to $81.50 per Boe and $6.72 per Mcf, respectively, in the third quarter of 2011. Net loss attributable to the Partnership, including the effect of unrealized losses on commodity derivative instruments, was $30.4 million, or $0.51 per diluted common unit, in the fourth quarter of 2011 compared to net income of $178.2 million, or $2.87 per diluted common unit, in the third quarter of 2011. Capital expenditures totaled $17.4 million in the fourth quarter of 2011 compared to $22.3 million in the third quarter of 2011. Full Year 2011 Results Total oil, natural gas and NGL sales were $394 million in 2011, an increase of 24% from 2010. Total production was 7,037 MBoe in 2011, an increase of 5% from 2010 and the highest yearly production in the Partnership's history. Oil and gas capital expenditures were $75.4 million, an increase of 8% from 2010. Full year lease operating expenses per Boe were $18.64, which was 5% higher than 2010 primarily due to inflationary pressure on costs related to high oil prices, as well as increased production costs from new wells in Florida and higher Michigan well services, repairs and maintenance. Full year general and administrative expenses, excluding unit-based compensation, were $31.3 million, which was $6.8 million higher than 2010, primarily due to our acquisition activities. Adjusted EBITDA, a non-GAAP measure, was $225 million, which was above the high end of our guidance range of $205 million. Average realized crude oil and natural gas prices for 2011, excluding the realized loss from termination of oil derivatives, were $79.80 per Boe and $6.58 per Mcf, compared to NYMEX WTI crude oil and Henry Hub of $94.87 per barrel and $4.00 per Mcf. Net income attributable to the Partnership, including the effect of unrealized losses on commodity derivative instruments, was $110.5 million, or $1.79 per diluted common unit, in 2011 compared to net income of $34.8 million, or $0.61 per diluted common unit, in 2010. 2011 Estimated Proved Reserves Increase to 151.1 MMBoe BreitBurn's total estimated proved oil and gas reserves as of December 31, 2011, were 151.1 MMBoe, which represent a 27% increase from 118.9 MMBoe at year-end 2010. Reserve replacement from all sources was 558% of 2011 production. The Standardized Measure of future net cash flows from the production of these reserves is approximately $1,659 million using 12-month average first-day-of-the month prices that are held constant throughout the life of the properties. Estimated proved reserves were determined using $4.12 per MMBtu for gas, $95.97 per Bbl of oil for Michigan, California and Florida and $76.79 per Bbl of oil for Wyoming. Of the total estimated proved reserves, 65% were natural gas and 35% were crude oil; 87% were classified as proved developed; and 49% were located in Michigan, 29% in Wyoming, 14% in California and 7% in Florida, with the remaining 1% in Indiana and Kentucky. 2012 Guidance 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. (Assuming no acquisitions)   FY 2012 Guidance Total Production (Mboe)   7,800   -   8,300 Oil Production (Mbbls) 3,350 - 3,600 Gas Production (MMcfe) 26,700 - 28,200 Average Price Differential %: Oil Price Differential %(1) 88 % - 90 % Gas Price Differential % 102 % - 104 % Operating Costs / BOE(2)(3) $18.00 - $20.50 Production / Property Taxes (% of oil & gas revenue) 9.5 % - 10.0 % G&A (Excl. Unit Based Compensation) ($000s) $31,000 - $33,000 Cash Interest Expense ($000s)(4) $52,000 - $54,000 Capital Expenditures ($000s)(5) $66,000 - $70,000 Adjusted EBITDA ($000s)(6)   $255,000     -   $265,000   (1)   Represents the expected average price differential to both WTI crude oil and Brent crude oil pricing. Approximately 30% of the Partnership's 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 $6.2 million in 2012, largely attributable to Florida production. Excluding transportation expense, our operating costs per Boe are estimated to range between approximately $17.25 - $19.75. (3) Operating Costs are based on $95 per barrel for WTI crude oil, $105 per barrel for Brent crude oil, and $3.00 per Mcfe for natural gas. 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 $192 million of borrowings at a weighted average swap rate of 1.81%. (5) Total Capital Expenditures include maintenance and obligatory capital expenditures as well as growth capital expenditures and exclude capital expenditures for acquisitions as well as information technology spending of approximately $1.4 million. Maintenance and obligatory capital expenditures are defined as the estimated amount of investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately constant for the period. Management estimates that we would need to spend approximately $60 million in 2012 to hold production flat. (6) Assuming the high and low range of our guidance, Adjusted EBITDA, a non-GAAP financial measure, is expected to range between $255 million and $265 million, and is comprised of estimated net income (before non-cash compensation) between $49 million and $61 million, plus unrealized loss on commodity derivative instruments of $45 million, plus DD&A of $107 million, plus interest expense between $52 million (high end of Adjusted EBITDA) and $54 million (low end of Adjusted EBITDA). Estimated 2012 net income is based on oil prices of $95 per barrel for WTI crude oil, $105 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. In the fourth quarter of 2011, the Partnership terminated certain crude oil fixed price swaps at NYMEX WTI prices for a cash payment of $36.8 million and entered into new crude oil fixed price swaps at IPE Brent prices. The new crude oil swaps were entered into to mitigate future price volatility associated with our California production. Historically WTI oil prices and Brent oil prices have fluctuated together, but they have recently diverged and management believes that Brent pricing will better correlate with local California pricing. Including the effects of the $36.8 million loss on termination of crude oil derivative contracts noted above, realized losses from commodity derivative instruments were $28.9 million during the fourth quarter of 2011. Realized losses from interest rate derivative instruments were $0.1 million during the fourth quarter of 2011. Non-cash unrealized losses from commodity derivative instruments were $8.6 million and non-cash unrealized gains from interest rate derivative instruments were $0.3 million during the fourth quarter of 2011. Realized losses from commodity derivative instruments were $16.1 million for the year ended December 31, 2011. Realized losses from interest rate derivative instruments were $3.3 million for the year ended December 31, 2011. Non-cash unrealized gains from commodity derivative instruments were $97.7 million and non-cash unrealized gains from interest rate derivative instruments were $0.5 million for the year ended December 31, 2011. 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 December 31, 2011 and 2010, the three months ended September 30, 2011 and the years ended December 31, 2011 and 2010:   Three Months Ended     Year Ended December 31,December 31,   September 30,   December 31,Thousands of dollars, except as indicated2011201120102011   2010 Oil, natural gas and NGLs sales (a) $ 109,720 $ 97,356 $ 78,135 $ 394,393 $ 317,738 Realized gain (loss) on commodity derivative instruments (b) (28,851 ) 8,092 21,677 (16,067 ) 74,825 Unrealized gain (loss) on commodity derivative instruments (b) (8,614 ) 170,734 (82,307 ) 97,734 (39,713 ) Other revenues, net   894     1,375   660     4,310     2,498   Total revenues $ 73,149   $ 277,557 $ 18,165   $ 480,370   $ 355,348   Lease operating expenses and processing fees $ 36,699 $ 36,409 $ 29,536 $ 131,188 $ 118,454 Production and property taxes   7,946     6,689   5,626     26,599     20,510   Total lease operating expenses $ 44,645   $ 43,098 $ 35,162   $ 157,787   $ 138,964   Transportation expenses 1,394 1,426 943 5,253 4,058 Purchases and other operating costs 210 329 112 961 328 Change in inventory   255     1,593   (2,121 )   1,968     (825 ) Total operating costs $ 46,504   $ 46,446 $ 34,096   $ 165,969   $ 142,525   Lease operating expenses pre taxes per Boe (c) $ 17.77 $ 21.66 $ 17.37 $ 18.64 $ 17.68 Production and property taxes per Boe 3.85 3.98 3.31 3.78 3.06 Total lease operating expenses per Boe   21.62     25.64   20.68     22.42     20.74   General and administrative expenses excluding unit-based compensation   $ 9,480   $ 8,552 $ 5,907   $ 31,311   $ 24,478   Net income (loss) attributable to the partnership $ (30,392 ) $ 178,181 $ (70,903 ) $ 110,497 $ 34,751 Net income (loss) per diluted limited partner unit   $ (0.51 ) $ 2.87 $ (1.33 ) $ 1.79   $ 0.61     Total production (MBoe) 2,065 1,681 1,700 7,037 6,699 Oil and NGLs (MBoe) 871 829 791 3,255 3,157 Natural gas (MMcf) 7,168 5,114 5,452 22,697 21,251 Average daily production (Boe/d)   22,450     18,273   18,480     19,281     18,354   Sales volumes (MBoe)   2,080     1,723   1,664     7,106     6,663   Average realized sales price (per Boe) (d) (e) (f) $ 56.48 $ 61.08 $ 59.99 $ 58.33 $ 58.94 Oil and NGLs (per Boe) (d) (e) (f) 84.00 81.50 78.95 79.80 74.31 Natural gas (per Mcf) (d)   6.02     6.72   7.38     6.58     7.57   (a)   Q4 2010 and Full Year 2010 include $124 and $495 of amortization of an intangible asset related to crude oil sales contracts. (b) Q4 2011 and Full Year 2011 include the effect of $36,779 loss on early terminations of hedge contracts in the fourth quarter of 2011. (c) Includes lease operating expenses, district expenses and processing fees. (d) Includes realized gain (loss) on commodity derivative instruments. (e) Q4 2011 and Full Year 2011 exclude the effect of $36,779 loss on early terminations of hedge contracts in the fourth quarter of 2011. (f) Includes crude oil purchases. 2010 excludes amortization of intangible asset related to crude oil sales contracts. 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. In addition, this press release presents certain non-GAAP financial measures, which exclude the effect of a $36.8 million loss relating to the early termination of crude oil derivative contracts in the fourth quarter of 2011. 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     Year Ended December 31, December 31,   September 30,   December 31,   Thousands of dollars 2011 2011 2010 2011 2010 Reconciliation of net income (loss) to Adjusted EBITDA:   Net income (loss) attributable to the Partnership ($30,392 ) $ 178,181 ($70,903 ) $ 110,497 $ 34,751   Unrealized (gain) loss on commodity derivative instruments 8,614 (170,734 ) 82,307 (97,734 ) 39,713 Depletion, depreciation and amortization expense 31,149 26,688 33,159 107,503 102,758 Interest expense and other financing costs (a) 11,492 10,342 13,116 42,422 35,639 Unrealized (gain) loss on interest rate derivatives (340 ) 71 (3,126 ) (480 ) (6,597 ) Loss on early termination of commodity derivatives (b) 36,779 - - 36,779   - (Gain) loss on sale of assets (71 ) (94 ) (123 ) (111 ) 14 Income taxes (321 ) 1,895 (439 ) 1,188 (204 ) Amortization of intangibles - - 124 - 495 Unit-based compensation expense (c) 5,707 5,447 5,009 22,002 20,331 Net operating cash flow from acquisitions, effective date through closing date   1,808     1,078     -     2,886     -   Adjusted EBITDA $ 64,425   $ 52,874   $ 59,124   $ 224,952   $ 226,900     Three Months Ended Year Ended December 31, December 31, September 30, December 31, Thousands of dollars 2011 2011 2010 2011 2010 Reconciliation of net cash flows from operating activities to Adjusted EBITDA:   Net cash (used in) provided by operating activities $ (241 ) $ 41,267 $ 38,722 $ 128,543 $ 182,022   Increase in assets net of liabilities relating to operating activities 15,503 1,199 9,983 18,942 15,131 Interest expense (a) (d) 10,394 9,273 10,488 37,702 30,161 Loss on early termination of commodity derivatives (b) 36,779 - - 36,779 - Income from equity affiliates, net (41 ) (10 ) (157 ) (210 ) (450 ) Incentive compensation expense (e) (2 ) (29 ) (29 ) (41 ) (93 ) Incentive compensation paid - 78 - 78 91 Income taxes 278 64 152 474 199 Non-controlling interest (53 ) (46 ) (35 ) (201 ) (162 ) Net operating cash flow from acquisitions, effective date through closing date   1,808     1,078     -     2,886     -   Adjusted EBITDA $ 64,425   $ 52,874   $ 59,124   $ 224,952   $ 226,900   (a)   Includes realized (gain) loss on interest rate derivatives. (b) Represents loss on termination of hedge contracts during the fourth quarter of 2011. (c) Represents non-cash long-term unit-based incentive compensation expense. (d) Excludes amortization of debt issuance costs and amortization of senior note discount. (e) Represents cash-based incentive compensation plan expense. Hedge Portfolio Summary The table below summarizes the Partnership's commodity derivative hedge portfolio as of February 28, 2012. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.     Year2012     2013     2014     2015Oil Positions: Fixed Price Swaps - NYMEX WTI Hedged Volume (Bbls/d) 2,402 2,580 1,500 2,500 Average Price ($/Bbl) $ 86.84 $ 87.13 $ 88.33 $ 99.50 Fixed Price Swaps - IPE Brent Hedged Volume (Bbls/d) 2,637 3,900 3,500 1,500 Average Price ($/Bbl) $ 105.46 $ 97.23 $ 96.86 $ 95.53 Collars - NYMEX WTI Hedged Volume (Bbls/d) 2,477 500 1,000 1,000 Average Floor Price ($/Bbl) $ 110.00 $ 77.00 $ 90.00 $ 90.00 Average Ceiling Price ($/Bbl) $ 145.39 $ 103.10 $ 112.00 $ 113.50 Total: Hedged Volume (Bbls/d) 7,516 6,980 6,000 5,000 Average Price ($/Bbl) $ 101.00 $ 92.05 $ 93.58 $ 96.41 Gas Positions: Fixed Price Swaps - MichCon City-Gate Hedged Volume (MMBtu/d) 19,128 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 23,000 23,000 Average Price ($/MMBtu) $ 4.88 $ 4.90 $ 5.24 $ 5.41 Collars - MichCon City-Gate Hedged Volume (MMBtu/d) 19,129 - - - Average Floor Price ($/MMBtu) $ 9.00 $ - $ - $ - Average Ceiling Price ($/MMBtu) $ 11.89 $ - $ - $ - Total: Hedged Volume (MMBtu/d) 54,257 56,000 30,500 30,500 Average Price ($/MMBtu) $ 7.12 $ 5.96 $ 5.43 $ 5.55   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 800-474-8920 (international callers dial +1-719-325-2191) 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 13, 2012 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 4015095, 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 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, 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, 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 SubsidiariesUnaudited Consolidated Balance Sheets     December 31,     December 31,Thousands20112010ASSETSCurrent assets Cash $ 5,328 $ 3,630 Accounts and other receivables, net 73,018 53,520 Derivative instruments 83,452 54,752 Related party receivables 4,245 4,345 Inventory 4,724 7,321 Prepaid expenses   2,053     1,736   Total current assets 172,820 125,304 Equity investments 7,491 7,700 Property, plant and equipment Oil and gas properties 2,583,993 2,133,099 Other assets   13,431     10,832   2,597,424 2,143,931 Accumulated depletion and depreciation   (524,665 )   (421,636 ) Net property, plant and equipment 2,072,759 1,722,295 Other long-term assets Derivative instruments 55,337 50,652 Other long-term assets   22,442     24,216     Total assets $ 2,330,849   $ 1,930,167   LIABILITIES AND EQUITYCurrent liabilities Accounts payable $ 33,494 $ 26,808 Derivative instruments 8,881 37,071 Revenue and royalties payable 19,641 16,427 Salaries and wages payable 13,655 12,594 Accrued liabilities   14,218     8,417   Total current liabilities 89,889 101,317   Credit facility 520,000 228,000 Senior notes, net 300,613 300,116 Deferred income taxes 2,803 2,089 Asset retirement obligation 82,397 47,429 Derivative instruments 3,084 39,722 Other long-term liabilities   4,849     2,237   Total liabilities 1,003,635 720,910 Equity Partners' equity 1,326,764 1,208,803 Noncontrolling interest   450     454   Total equity   1,327,214     1,209,257     Total liabilities and equity $ 2,330,849   $ 1,930,167     Common units outstanding 59,864 53,957   BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Statements of Operations     Three Months Ended     Year EndedDecember 31,December 31,Thousands of dollars, except per unit amounts2011   20102011   2010   Revenues and other income items Oil, natural gas and natural gas liquid sales $ 109,720 $ 78,135 $ 394,393 $ 317,738 Gain (loss) on commodity derivative instruments, net (37,465 ) (60,630 ) 81,667 35,112 Other revenue, net   894     660     4,310     2,498   Total revenues and other income items 73,149 18,165 480,370 355,348 Operating costs and expenses Operating costs 46,504 34,096 165,969 142,525 Depletion, depreciation and amortization 31,149 33,159 107,503 102,758 General and administrative expenses 15,187 10,950 53,313 44,907 (Gain) loss on sale of assets (71 ) (123 ) (111 ) 14 Unreimbursed litigation costs   (113 )   1,401     (113 )   1,401   Total operating costs and expenses   92,656     79,483     326,561     291,605     Operating income (loss) (19,507 ) (61,318 ) 153,809 63,743   Interest expense, net of capitalized interest 11,395 10,790 39,165 24,552 (Gain) loss on interest rate swaps (243 ) (800 ) 2,777 4,490 Other (income) expense, net   1     (1 )   (19 )   (8 )   Income (loss) before taxes (30,660 ) (71,307 ) 111,886 34,709   Income tax expense (benefit)   (321 )   (439 )   1,188     (204 )   Net income (loss) (30,339 ) (70,868 ) 110,698 34,913   Less: Net income attributable to noncontrolling interest   (53 )   (35 )   (201 )   (162 ) Net income (loss) attributable to the partnership   (30,392 )   (70,903 )   110,497     34,751     Basic net income (loss) per unit $ (0.51 ) $ (1.33 ) $ 1.80   $ 0.61   Diluted net income (loss) per unit $ (0.51 ) $ (1.33 ) $ 1.79   $ 0.61     BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Statements of Cash Flows     Year EndedDecember 31,Thousands of dollars2011   2010   Cash flows from operating activities Net income $ 110,698 $ 34,913 Adjustments to reconcile net income to cash flow from operating activities: Depletion, depreciation and amortization 107,503 102,758 Unit-based compensation expense 22,043 20,422 Unrealized (gain) loss on derivative instruments (98,214 ) 33,116 Income from equity affiliates, net 210 450 Deferred income taxes 714 (403 ) Amortization of intangibles - 495 (Gain) loss on sale of assets (111 ) 14 Other (312 ) 3,528 Changes in assets and liabilities: Accounts receivable and other assets (17,833 ) 11,552 Inventory 2,597 (1,498 ) Net change in related party receivables and payables 100 (15,218 ) Accounts payable and other liabilities   1,148     (8,107 ) Net cash provided by operating activities   128,543     182,022   Cash flows from investing activities Capital expenditures (78,107 ) (66,947 ) Proceeds from sale of assets 2,339 337 Property acquisitions   (338,805 )   (1,676 ) Net cash used in investing activities   (414,573 )   (68,286 ) Cash flows from financing activities Issuance of common units 99,443 - Distributions (102,686 ) (65,197 ) Proceeds from issuance of long-term debt, net 661,500 1,047,992 Repayments of long-term debt (369,500 ) (1,079,000 ) Change in book overdraft 2,636 1,025 Debt issuance costs   (3,665 )   (20,692 ) Net cash provided by (used in) financing activities   287,728     (115,872 ) Increase (decrease) in cash 1,698 (2,136 ) Cash beginning of period   3,630     5,766   Cash end of period $ 5,328   $ 3,630   Investor Relations Contacts:James G. JacksonExecutive Vice President and Chief Financial Officer213-225-5900 x273orJessica TangInvestor Relations213-225-5900 x210