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Press release from Business Wire

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

Tuesday, August 07, 2012

BreitBurn Energy Partners L.P. Reports Second Quarter Results, Announces Substantial Increase in 2012 Capital Program and Updates Second Half 2012 Guidance08:15 EDT Tuesday, August 07, 2012 LOS ANGELES (Business Wire) -- BreitBurn Energy Partners L.P. (the “Partnership”) (NASDAQ:BBEP) today announced financial and operating results for its second quarter of 2012, a substantial increase in its 2012 capital program, and updated second half 2012 guidance. Key Highlights The Partnership had strong operating and financial results with net production increasing 18%, and Adjusted EBITDA increasing 28%, from the second quarter of 2011. On July 31, 2012, the Partnership announced an increased cash distribution for the second quarter of 2012 of $0.4600 per common unit, equal to an annualized rate of $1.84 per common unit, to be paid on August 14, 2012 to the record holders of common units at the close of business on August 10, 2012. This represents the Partnership's ninth consecutive quarterly distribution increase and a 9% increase over the cash distribution for the second quarter of 2011. On July 2, 2012, the Partnership completed two separate acquisitions of principally oil properties located in the Permian Basin in Texas from Element Petroleum LP and CrownRock LP for approximately $150 million and $70 million, respectively, subject to customary post-closing adjustments. On June 28, 2012, the Partnership completed the acquisition of oil properties located in Park County in the Big Horn Basin of Wyoming from NiMin Energy Corp. for approximately $93 million, subject to customary post-closing adjustments. The Partnership is substantially increasing its 2012 capital program for the second time this year. In April, the Partnership announced a $19 million increase to its original 2012 capital program of approximately $68 million. Today the Partnership is announcing an additional increase of $50 million. This latest increase expands the Partnership's total 2012 capital program to approximately $137 million and will be allocated principally to attractive oil development opportunities on newly acquired assets as well as the Partnership's legacy assets. The Partnership updated its guidance for the second half of 2012, reflecting year-to-date acquisitions and the positive impacts of its increased capital program. Management Commentary Hal Washburn, CEO, said: “The Partnership delivered a strong second quarter as we continued to execute on our growth through acquisitions strategy. We completed three very attractive acquisitions of primarily oil properties which expanded our operations to seven states and established our presence in the Permian Basin. Additionally, we are increasing our capital program for the second time this year by $50 million to develop our newly acquired assets and to pursue a series of attractive oil projects identified in our legacy assets as well. To reflect our increased capital program and recent acquisitions, we are increasing our full year production target to between approximately 8.3 MMBoe and 8.6 MMBoe and we are increasing our full year Adjusted EBITDA target to between approximately $280 million and $290 million. These increases demonstrate our focus on continually improving our operating performance and the ongoing success of our growth through acquisitions strategy.” Second Quarter 2012 Operating and Financial Results Compared to First Quarter 2012 Total production was 1,953 MBoe in the second quarter of 2012 compared to 1,987 MBoe in the first quarter of 2012. Average daily production was 21,457 Boe/day in the second quarter of 2012 compared to 21,835 Boe/day in first quarter of 2012. Oil and NGL production was 815 MBoe compared to 859 MBoe. The decline principally reflects interest reversions in two California fields which occurred during the second quarter. NGLs represented less than 6% of oil and NGL production and less than 3% of total production. Natural gas production was 6,824 MMcf compared to 6,769 MMcf. Adjusted EBITDA, a non-GAAP measure, increased approximately 8% to a record quarterly high of $66.3 million in the second quarter of 2012 from $61.4 million in the first quarter of 2012. Lease operating expenses per Boe, which include district expenses, transportation expenses and processing fees and exclude production and property taxes, increased to $20.03 per Boe in the second quarter of 2012 from $19.16 per Boe in the first quarter of 2012, primarily due to higher well service costs. General and administrative expenses on a per Boe basis, excluding non-cash unit-based compensation, decreased to $3.75 per Boe in the second quarter of 2012 from $4.07 per Boe in the first quarter of 2012. Oil and natural gas sales revenues were $95.0 million in the second quarter of 2012, up from $94.0 million in the first quarter of 2012. Realized gains on commodity derivative instruments were $25.1 million in the second quarter of 2012 compared to realized gains of $17.6 million in the first quarter of 2012. NYMEX WTI crude oil spot prices averaged $93.29 per barrel and Henry Hub natural gas spot prices averaged $2.29 per Mcf in the second quarter of 2012 compared to $102.98 per barrel and $2.44 per Mcf, respectively, in the first quarter of 2012. Brent crude oil spot prices averaged $108.04 per barrel in the second quarter of 2012 compared to $118.71 in the first quarter of 2012. Realized crude oil and NGL prices averaged $92.08 per Boe and realized natural gas prices averaged $5.74 per Mcf in the second quarter of 2012 compared to realized crude oil and NGL prices of $90.36 per Boe and realized natural gas prices of $6.18 per Mcf in the first quarter of 2012. Net income attributable to the Partnership, including the effect of unrealized losses on commodity derivative instruments, was $92.5 million, or $1.29 per diluted common unit, in the second quarter of 2012 compared to a net loss of $50.0 million, or $0.76 per diluted common unit, in the first quarter of 2012. Capital expenditures totaled $28.0 million in the second quarter of 2012 compared to $16.5 million in the first quarter of 2012. Second Half of 2012 Guidance Update The following guidance is subject to all of the cautionary statements and limitations described below and under the caption "Cautionary Statement Regarding Forward-Looking Information." In addition, estimates for the Partnership's future production volumes are based on, among other things, assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of oil and gas are extremely complex and are subject to disruption due to transportation and processing availability, mechanical failure, human error, weather and numerous other factors. The Partnership's estimates are based on certain other assumptions, such as well performance, which may actually prove to vary significantly from those assumed. Operating costs, which include major maintenance costs, vary in response to changes in prices of services and materials used in the operation of our properties and the amount of maintenance activity required. Operating costs, including taxes, utilities and service company costs, move directionally with increases and decreases in commodity prices, and we cannot fully predict such future commodity or operating costs. Similarly, interest rates and price differentials are set by the market and are not within our control. They can vary dramatically from time to time. Capital expenditures are based on our current expectations as to the level of capital expenditures that will be justified based upon the other assumptions set forth below as well as expectations about other operating and economic factors not set forth below. The guidance below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. Rather, the table simply sets forth our best estimate today for these matters based upon our current expectations about the future based upon both stated and unstated assumptions. Actual conditions and those assumptions may, and probably will, change over the course of the year.                     ($ in 000s)           Second Half 2012 Guidance Total Production (MBoe) 4,400 -   4,700 Oil Production (Mbbls) 2,050 - 2,250 Gas Production (MMcfe) 14,100 - 14,700 Average Price Differential %: Oil Price Differential %(1) 88 % - 90 % Gas Price Differential % 108 % - 110 % Operating Costs / BOE(2)(3) $ 18.00 - $ 20.00 Production / Property Taxes (% of oil & gas revenue) 8.0 % - 9.0 % G&A (Excl. Unit Based Compensation) $ 15,000 - $ 17,000 Cash Interest Expense(4) $ 32,000 - $ 34,000 Capital Expenditures(5) $ 90,000 - $ 94,000 Adjusted EBITDA(6)           $ 155,000   -   $ 165,000     (1)     Represents the expected average price differential to both WTI crude oil and Brent crude oil pricing. Approximately 30% of oil production is expected to be sold based on Brent pricing. (2) Operating Costs include lease operating costs, processing fees, district expense, and transportation expense. Expected transportation expense totals approximately $3.4 million in the second half of 2012, largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs per Boe are expected to range between approximately $17.25 - $19.25. (3) Operating Costs are based on flat $85 per barrel WTI crude oil, $100 per barrel Brent crude oil, and $3.00 per Mcfe natural gas price levels for the second half of 2012. Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices. (4) The Partnership typically borrows on a 1-month LIBOR basis, plus an applicable spread. Estimated cash interest expense assumes a 1-month LIBOR rate of 1% and includes the impact of interest rate swaps covering approximately $194 million of borrowings at a weighted average swap rate of 1.84% for the second half of 2012. (5) Total Capital Expenditures for 2012 include maintenance and obligatory capital expenditures as well as growth capital expenditures and exclude capital expense for acquisitions as well as information technology spending. Maintenance and obligatory capital expenditures are defined as the estimated amount of investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately constant for the period. Management estimates that the Partnership would need to spend approximately $35 million in the second half of 2012 to hold production flat. (6) Assuming the high and low range of our guidance, Adjusted EBITDA for the second half of 2012 is expected to range between $155 million and $165 million, and is comprised of estimated net income (before non-cash compensation) between $58 million and $70 million, less estimated unrealized gain on commodity derivative instruments of approximately $5 million, plus estimated DD&A of approximately $63 million, plus estimated interest expense between $32 million (high end of Adjusted EBITDA) and $34 million (low end of Adjusted EBITDA), and plus other adjustments of approximately $5 million. Estimated 2012 net income is based on oil prices of $85 per barrel for WTI crude oil, $100 per barrel Brent crude oil, and $3.00 per Mcfe for natural gas. Consequently, differences between actual and forecast prices could result in changes to unrealized gains or losses on commodity derivative instruments, DD&A, including potential impairments of long-lived assets, and ultimately, net income.   Impact of Derivative Instruments The Partnership uses commodity and interest rate derivative instruments to mitigate the risks associated with commodity price volatility and changing interest rates and to help maintain cash flows for operating activities, acquisitions, capital expenditures and distributions. The Partnership does not enter into derivative instruments for speculative trading purposes. Non-cash gains or losses do not affect Adjusted EBITDA, cash flow from operations or the Partnership's ability to pay cash distributions. Realized gains from commodity derivative instruments were $25.1 million during the second quarter of 2012. Realized losses from interest rate derivative instruments were $0.8 million during the second quarter of 2012. Non-cash unrealized gains from commodity derivative instruments were $82.2 million and non-cash unrealized gains from interest rate derivative instruments were $0.6 million during the second quarter of 2012. Production, Statement of Operations and Realized Price Information The following table presents production, selected income statement and realized price information for the three months ended June 30, 2012, March 31, 2012 and June 30, 2011:                   Three Months EndedJune 30,           March 31,           June 30,Thousands of dollars, except as indicated201220122011 Oil, natural gas and NGLs sales $ 94,981 $ 94,007 $ 94,742 Realized gain (loss) on commodity derivative instruments 25,063 17,591 (1,751 ) Unrealized gain (loss) on commodity derivative instruments 82,225 (53,596 ) 48,234 Other revenues, net   907   1,145     1,143   Total revenues $ 203,176 $ 59,147   $ 142,368   Lease operating expenses and processing fees $ 39,122 $ 38,073 $ 31,605 Production and property taxes   6,525   7,573     6,195   Total lease operating expenses $ 45,647 $ 45,646   $ 37,800   Purchases and other operating costs 647 370 268 Change in inventory   2,600   (2,755 )   (1,860 ) Total operating costs $ 48,894 $ 43,261   $ 36,208   Lease operating expenses pre taxes per Boe(a) $ 20.03 $ 19.16 $ 19.02 Production and property taxes per Boe 3.34 3.81 3.73 Total lease operating expenses per Boe   23.37   22.97     22.75   General and administrative expenses (excluding unit-based compensation) $ 7,314 $ 8,083   $ 6,221   Net income (loss) attributable to the partnership $ 92,506 $ (49,970 ) $ 57,523 Net income (loss) per diluted limited partner unit $ 1.29 $ (0.76 ) $ 0.92     Total production (MBoe) 1,953 1,987 1,662 Oil and NGLs (MBoe)(b) 815 859 782 Natural gas (MMcf) 6,824 6,769 5,277 Average daily production (Boe/d)   21,457   21,835     18,265   Sales volumes (MBoe)   2,013   1,899     1,621   Average realized sales price (per Boe)(c)(d) $ 59.54 $ 58.66 $ 57.29 Oil and NGLs (per Boe)(c)(d) 92.08 90.36 79.48 Natural gas (per Mcf)(c)   5.74   6.18     6.42               (a)     Includes lease operating expenses, district expenses, transportation expenses and processing fees. (b) NGLs account for less than 6% of oil and NGLs production and less than 3% of total production. (c) Includes realized gain (loss) on commodity derivative instruments. (d) Includes crude oil purchases.   Non-GAAP Financial Measures This press release, the financial tables and other supplemental information, including the reconciliations of certain non-generally accepted accounting principles (“non-GAAP”) measures to their nearest comparable generally accepted accounting principles (“GAAP”) measures, may be used periodically by management when discussing the Partnership's financial results with investors and analysts, and they are also available on the Partnership's website under the Investor Relations tab. Among the non-GAAP financial measures used is “Adjusted EBITDA.” This non-GAAP financial measure should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. Management believes that these non-GAAP financial measures enhance comparability to prior periods. Adjusted EBITDA is presented as management believes it provides additional information relative to the performance of the Partnership's business, such as our ability to meet our debt covenant compliance tests. This non-GAAP financial measure may not be comparable to similarly titled measures of other publicly traded partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA in the same manner. Adjusted EBITDA The following table presents a reconciliation of net income (loss) and net cash flows from operating activities, our most directly comparable GAAP financial performance and liquidity measures, to Adjusted EBITDA for each of the periods indicated.                 Three Months Ended June 30,           March 31,           June 30, Thousands of dollars 2012 2012 2011 Reconciliation of net income (loss) to Adjusted EBITDA:   Net income (loss) attributable to the Partnership $ 92,506 ($49,970 ) $ 57,455   Unrealized (gain) loss on commodity derivative instruments (82,225 ) 53,596 (48,234 ) Depletion, depreciation and amortization expense 33,517 38,281 25,025 Interest expense and other financing costs(a) 14,872 14,458 10,145 Unrealized (gain) loss on interest rate derivatives (613 ) (164 ) 1,155 Loss on sale of assets 29 125 40 Income taxes 1,005 (559 ) 616 Unit-based compensation expense(b) 5,612 5,591 5,435 Net operating cash flow from acquisitions, effective date through closing date   1,595     -     -   Adjusted EBITDA $ 66,298   $ 61,358   $ 51,637       Three Months Ended June 30, March 31, June 30, Thousands of dollars 2012 2012 2011 Reconciliation of net cash flows from operating activities to Adjusted EBITDA:   Net cash provided by operating activities $ 29,252 $ 71,299 $ 33,118   Increase (decrease) in assets net of liabilities relating to operating activities 21,940 (23,168 ) 9,837 Interest expense(a)(c) 13,583 13,206 8,896 Income from equity affiliates, net (155 ) (154 ) (262 ) Incentive compensation expense(d) - - 14 Income taxes 100 220 102 Non-controlling interest (17 ) (45 ) (68 ) Net operating cash flow from acquisitions, effective date through closing date   1,595     -     -   Adjusted EBITDA $ 66,298   $ 61,358   $ 51,637               (a)     Includes realized loss on interest rate derivatives. (b) Represents non-cash long-term unit-based incentive compensation expense. (c) Excludes amortization of debt issuance costs and amortization of senior note discount. (d) Represents cash-based incentive compensation plan expense.   Hedge Portfolio Summary The table below summarizes the Partnership's commodity derivative hedge portfolio for the second half of 2012 through 2017 and includes contracts entered into through August 6, 2012. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.             Year2012       2013       2014       2015       2016       2017Oil Positions: Fixed Price Swaps - NYMEX WTI Hedged Volume (Bbls/d) 3,586 3,371 3,145 3,546 1,484 222 Average Price ($/Bbl) $ 89.76 $ 90.02 $ 93.14 $ 97.78 $ 91.84 $ 88.12 Fixed Price Swaps - IPE Brent Hedged Volume (Bbls/d) 2,339 3,900 3,500 2,000 500 - Average Price ($/Bbl) $ 105.37 $ 97.23 $ 96.86 $ 96.46 $ 95.55 $ - Collars - NYMEX WTI Hedged Volume (Bbls/d) 2,384 500 1,000 1,000 - - Average Floor Price ($/Bbl) $ 110.00 $ 77.00 $ 90.00 $ 90.00 $ - $ - Average Ceiling Price ($/Bbl) $ 145.37 $ 103.10 $ 112.00 $ 113.50 $ - $ - Collars - IPE Brent Hedged Volume (Bbls/d) - - - 500 500 - Average Floor Price ($/Bbl) $ - $ - $ - $ 90.00 $ 90.00 $ - Average Ceiling Price ($/Bbl) $ - $ - $ - $ 109.50 $ 101.25 $ - Total: Hedged Volume (Bbls/d) 8,309 7,771 7,645 7,046 2,484 222 Average Price ($/Bbl) $ 99.96 $ 92.80 $ 94.43 $ 95.75 $ 92.21 $ 88.12   Gas Positions: Fixed Price Swaps - MichCon City-Gate Hedged Volume (MMBtu/d) 18,730 37,000 7,500 7,500 - - Average Price ($/MMBtu) $ 7.10 $ 6.50 $ 6.00 $ 6.00 $ - $ - Fixed Price Swaps - Henry Hub Hedged Volume (MMBtu/d) 16,000 19,000 36,000 40,500 13,000 - Average Price ($/MMBtu) $ 4.88 $ 4.90 $ 4.86 $ 4.88 $ 4.18 $ - Collars - MichCon City-Gate Hedged Volume (MMBtu/d) 18,732 - - - - - Average Floor Price ($/MMBtu) $ 9.00 $ - $ - $ - $ - $ - Average Ceiling Price ($/MMBtu) $ 11.60 $ - $ - $ - $ - $ - Puts - Henry Hub Hedged Volume (MMBtu/d) - - 6,000 1,500 - - Average Price ($/MMBtu) $ - $ - $ 5.00 $ 5.00 $ - $ - Total: Hedged Volume (MMBtu/d) 53,462 56,000 49,500 49,500 13,000 - Average Price ($/MMBtu) $ 7.10 $ 5.96 $ 5.05 $ 5.05 $ 4.18 $ -   Calls - Henry Hub Hedged Volume (MMBtu/d) - 30,000 15,000 - - - Average Price ($/MMBtu) $ - $ 8.00 $ 9.00 $ - $ - $ - Premium ($/MMBtu) $ - $ 0.08 $ 0.12 $ - $ - $ -   Other Information The Partnership will host an investor conference call to discuss its results today at 10:00 a.m. (Pacific Time). Investors may access the conference call over the Internet via the Investor Relations tab of the Partnership's website (www.breitburn.com), or via telephone by dialing 888-300-2323 (international callers dial +1-719-325-2492) a few minutes prior to register. Those listening via the Internet should go to the site 15 minutes early to register, download and install any necessary audio software. In addition, a replay of the call will be available through August 21, 2012 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 1671747, or by going to the Investor Relations tab of the Partnership's website (www.breitburn.com). The Partnership will take live questions from securities analysts and institutional portfolio managers; the complete call is open to all other interested parties on a listen-only basis. About BreitBurn Energy Partners L.P. BreitBurn Energy Partners L.P. is a publicly traded independent oil and gas master limited partnership focused on the acquisition, exploitation, development and production of oil and gas properties. The Partnership's producing and non-producing crude oil and natural gas reserves are located in Michigan, Wyoming, California, Texas, Florida, Indiana and Kentucky. See www.BreitBurn.com for more information. Cautionary Statement Regarding Forward-Looking Information This press release contains forward-looking statements relating to the Partnership's operations that are based on management's current expectations, estimates and projections about its operations. Words and phrases such as “believes,” “expects,” “future,” “impact,” “guidance,” “will be” and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. These include risks relating to the Partnership's financial performance and results, availability of sufficient cash flow and other sources of liquidity to execute our business plan, prices and demand for natural gas and oil, increases in operating costs, uncertainties inherent in estimating our reserves and production, our ability to replace reserves and efficiently develop our current reserves, political and regulatory developments relating to taxes, derivatives and our oil and gas operations, risks relating to our acquisitions, and the factors set forth under the heading “Risk Factors” incorporated by reference from our Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 29, 2012, and if applicable, our Quarterly Reports on Form 10-Q and our Current Reports on Form 8-K. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this press release. Unless legally required, the Partnership undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements. BBEP-IR                       BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Balance Sheets   June 30,December 31,Thousands20122011ASSETSCurrent assets Cash $ 4,066 $ 5,328 Accounts and other receivables, net 55,575 73,018 Derivative instruments 79,616 83,452 Related party receivables 2,075 4,245 Inventory 5,267 4,724 Prepaid expenses   2,404     2,053   Total current assets 149,003 172,820 Equity investments 7,182 7,491 Property, plant and equipment Oil and gas properties 2,719,580 2,583,993 Other assets   13,695     13,431   2,733,275 2,597,424 Accumulated depletion and depreciation   (592,825 )   (524,665 ) Net property, plant and equipment 2,140,450 2,072,759 Other long-term assets Derivative instruments 87,161 55,337 Other long-term assets   47,694     22,442   Total assets $ 2,431,490   $ 2,330,849     LIABILITIES AND EQUITYCurrent liabilities Accounts payable $ 36,949 $ 33,494 Derivative instruments 2,487 8,881 Revenue and royalties payable 16,059 19,641 Salaries and wages payable 7,998 13,655 Accrued liabilities   14,732     14,218   Total current liabilities 78,225 89,889   Credit facility 225,000 520,000 Senior notes, net 548,841 300,613 Deferred income taxes 2,929 2,803 Asset retirement obligation 84,802 82,397 Derivative instruments 1,104 3,084 Other long-term liabilities   4,823     4,849   Total liabilities 945,724 1,003,635 Equity Partners' equity 1,485,766 1,326,764 Noncontrolling interest   -     450   Total equity   1,485,766     1,327,214   Total liabilities and equity $ 2,431,490   $ 2,330,849     Common units outstanding 69,144 59,864                                 BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Statements of Operations   Three Months EndedSix Months EndedJune 30,June 30,Thousands of dollars, except per unit amounts2012201120122011Revenues and other income items Oil, natural gas and natural gas liquid sales $ 94,981 $ 94,742 $ 188,988 $ 187,317 Gain (loss) on commodity derivative instruments, net 107,288 46,483 71,283 (59,694 ) Other revenue, net   907     1,143     2,052     2,041   Total revenues and other income items 203,176 142,368 262,323 129,664 Operating costs and expenses Operating costs 48,894 36,208 92,155 73,019 Depletion, depreciation and amortization 33,517 25,025 71,798 49,666 General and administrative expenses 12,926 11,656 26,600 24,127 Loss on sale of assets   29     40     154     54   Total operating costs and expenses   95,366     72,929     190,707     146,866     Operating income (loss) 107,810 69,439 71,616 (17,202 )   Interest expense, net of capitalized interest 14,069 9,080 27,869 18,500 Loss on interest rate swaps 190 2,220 684 1,877 Other expense (income), net   23     -     19     (3 )   Income (loss) before taxes 93,528 58,139 43,044 (37,576 )   Income tax expense (benefit)   1,005     616     446     (386 )   Net income (loss) 92,523 57,523 42,598 (37,190 )   Less: Net income attributable to noncontrolling interest   (17 )   (68 )   (62 )   (102 ) Net income (loss) attributable to the partnership   92,506     57,455     42,536     (37,292 )   Basic net income (loss) per unit $ 1.29   $ 0.93   $ 0.61   $ (0.64 ) Diluted net income (loss) per unit $ 1.29   $ 0.92   $ 0.61   $ (0.64 )                           BreitBurn Energy Partners L.P. and SubsidiariesUnaudited Consolidated Statements of Cash Flows   Six Months EndedJune 30,Thousands of dollars20122011Cash flows from operating activities Net income (loss) $ 42,598 $ (37,190 ) Adjustments to reconcile net income to cash flow from operating activities: Depletion, depreciation and amortization 71,798 49,666 Unit-based compensation expense 11,203 10,858 Unrealized loss (gain) on derivative instruments (29,406 ) 64,175 Income from equity affiliates, net 309 159 Deferred income taxes 126 (518 ) Loss on sale of assets 154 54 Other 2,367 (244 ) Changes in assets and liabilities: Accounts receivable and other assets 9,970 4,171 Inventory (543 ) (21 ) Net change in related party receivables and payables 2,170 1,713 Accounts payable and other liabilities   (10,195 )   (5,306 ) Net cash provided by operating activities   100,551     87,517   Cash flows from investing activities Capital expenditures (37,382 ) (35,136 ) Proceeds from sale of assets 674 110 Deposit for oil and gas properties (21,954 ) - Property acquisitions   (92,837 )   -   Net cash used in investing activities   (151,499 )   (35,026 ) Cash flows from financing activities Issuance of common units 166,044 100,204 Distributions (60,750 ) (49,470 ) Proceeds from issuance of long-term debt, net 538,885 133,500 Repayments of long-term debt (586,000 ) (234,500 ) Change in book overdraft (2,785 ) 5 Debt issuance costs   (5,708 )   (3,113 ) Net cash provided by (used in) financing activities   49,686     (53,374 ) Decrease in cash (1,262 ) (883 ) Cash beginning of period   5,328     3,630   Cash end of period $ 4,066   $ 2,747   Investor Relations Contacts:BreitBurn Energy Partners L.P.James G. JacksonExecutive Vice President and Chief Financial Officer213-225-5900 x273orJessica TangInvestor Relations213-225-5900 x210