Breitburn Energy Partners LP
Feb 27, 2014

BreitBurn Energy Partners L.P. Reports Fourth Quarter Results and Record Full Year Production and EBITDA; Provides Full Year 2014 Guidance

LOS ANGELES--(BUSINESS WIRE)-- BreitBurn Energy Partners L.P. (the "Partnership") (NASDAQ:BBEP) today announced financial and operating results for the fourth quarter and full year of 2013 as well as public guidance for its expected performance in 2014, excluding any future acquisitions.

Key Highlights:

Management Commentary

Halbert Washburn, CEO, said: "The Partnership had a very active 2013, completing approximately $1.2 billion in acquisitions, doubling our organic development expenditures, expanding our presence into the mid-continent, and significantly increasing our liquids reserves and production. Although we had a variety of challenges during the fourth quarter, we grew the business significantly in 2013 and are pleased to report record annual production and Adjusted EBITDA. 2013 also marked BreitBurn's 25-year anniversary. We have a long history of operating effectively and successfully pursuing our growth-through-acquisitions strategy. Looking forward to 2014, our large portfolio of high quality assets, a robust capital program, and ample financial flexibility should serve as a strong foundation for continued growth. We are very optimistic about our prospects for 2014 and are targeting at least $600 million in new acquisitions during the year."

Fourth Quarter 2013 Operating and Financial Results Compared to Third Quarter 2013

Full Year 2013 Results

2013 Estimated Proved Reserves

Total estimated proved reserves as of December 31, 2013 were 214.3 MMBoe. The standardized measure of discounted future net cash flows related to our estimated proved reserves was approximately $3.2 billion. Of the total estimated proved reserves, 53% were oil, 7% were NGLs and 40% were natural gas; 81% were classified as proved developed; and 27% were located in Michigan, 20% in Oklahoma, 19% in Texas, 17% in Wyoming, 11% in California and 5% in Florida, with less than 1% in Indiana and Kentucky. As of December 31, 2012, our total estimated proved reserves were 149.4 MMBoe. The unweighted average first-day-of-the-month oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2013 were $96.94 Bbl of oil for WTI NYMEX, $108.32 per Bbl of oil for ICE Brent and $3.67 per MMBtu of natural gas for Henry Hub.

2014 Guidance (Assuming no future acquisitions)

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, NGLs and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of oil, natural gas liquids 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)       FY 2014 Guidance
Total Production (MBoe):       13,600   -   14,400
Oil Production (MBbls) 7,900 - 8,400
NGL Production (MBbls) 1,125 - 1,225
Gas Production (MMcfe) 27,500 - 28,600
December 2014 Exit Rate (Boe/d) 38,400 - 40,800
Average Price Differential %:
WTI Oil Price Differential % 88.0 % - 96.0 %
Brent Oil Price Differential %(1) 92.0 % - 96.0 %
NGL Price Differential % (of WTI) 37.5 % - 42.5 %
Gas Price Differential % 100.0 % - 103.0 %
Other Revenue(2) $ 3,500 - $ 4,500
Operating Costs / Boe(3)(4) $ 18.50 - $ 20.50
Production / Property Taxes (% of oil & natural gas revenue) 6.50 % - 7.00 %
G&A (Excl. Unit Based Compensation) $ 51,000 - $ 53,000
Cash Interest Expense(5) $ 117,000 - $ 120,000
Adjusted EBITDA(6) $ 500,000 - $ 510,000
Capital Expenditures(7):
Maintenance Capital

 

$

125,000

Growth Capital       $ 200,000       -   $ 220,000  
(1)       Approximately 24% of oil production is expected to be sold based on Brent pricing.
(2) Primarily comprised of pipeline revenues and equity earnings in affiliate.
(3) Operating Costs include lease operating costs, processing fees, district expense, and transportation expense. Expected transportation expense totals approximately $6.0 million in 2014, largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs range per Boe is approximately $18.00 - $20.00.
(4) Operating Costs are based on flat $95 per barrel WTI oil, $105 per barrel Brent oil, and $4.00 per Mcfe natural gas price levels for 2014. Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices.
(5) 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 0.25%.
(6) Assuming the high and low range of our guidance, Adjusted EBITDA is expected to range between $500 million and $510 million, and is comprised of estimated net income (before non-cash compensation) between $131 million and $144 million, plus losses on commodity derivative instruments of $22 million, less net payments for derivative contracts settled during the period of $28 million, plus DD&A of $255 million, plus interest expense between $117 million (high end of Adjusted EBITDA) and $120 million (low end of Adjusted EBITDA). Estimated 2014 net income is based on oil prices of $95 per barrel for WTI oil, $105 per barrel for Brent oil and $4.00 per Mcfe for natural gas. Consequently, differences between actual and forecast prices could result in changes to gains or losses on mark to market of commodity derivative instruments, DD&A, including potential impairments of long-lived assets, and ultimately, net income.
(7) Total Capital Expenditures for 2014 excludes capital expense for acquisitions as well as information technology spending. Maintenance capital is 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.

Impact of Derivative Instruments

The Partnership uses commodity derivative instruments to mitigate the risks associated with commodity price volatility 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. Because the Partnership does not use hedge accounting to account for its derivative instruments, changes in the fair value of derivative instruments are recorded in earnings each reporting period. These non-cash changes in the fair value of derivatives do not affect Adjusted EBITDA, cash flow from operations, distributable cash flow or the Partnership's ability to pay cash distributions for the reporting periods presented.

Total losses from commodity derivative instruments were approximately $17.2 million for the fourth quarter of 2013, which include $4.5 million net receipts for contracts that settled during the period.

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, 2013 and 2012, the three months ended September 30, 2013 and the full year results for 2013 and 2012:

  Three Months Ended   Year Ended December 31,
December 31,   September 30,   December 31,  
Thousands of dollars, except as indicated 2013 2013 2012 2013 2012
Oil sales $ 158,456 $ 162,709 $ 85,639 $ 530,625 $ 326,130
NGL sales 8,644 7,888 845 22,558 3,858
Natural gas sales 26,504 26,816 26,695 107,482 83,879
(Loss) gain on commodity derivative instruments (17,234 ) (54,765 ) 3,715 (29,182 ) 5,580
Other revenues, net   978     737     700     3,175     3,548  
Total revenues $ 177,348   $ 143,385   $ 117,594   $ 634,658   $ 422,995  
Lease operating expenses and processing fees (a) $ 63,439 $ 58,731 $ 41,769 $ 216,275 $ 159,289
Production and property taxes (b)   11,295     14,476     10,962     46,220     33,634  
Total lease operating expenses $ 74,734   $ 73,207   $ 52,731   $ 262,495   $ 192,923  
Purchases and other operating costs 440 226 267 1,321 1,577
Change in inventory   5,758     (4,931 )   578     (995 )   1,279  
Total operating costs $ 80,932   $ 68,502   $ 53,576   $ 262,821   $ 195,779  
Lease operating expenses, pre taxes, per Boe (a) $ 20.56 $ 18.96 $ 18.88 $ 19.69 $ 19.15
Production and property taxes per Boe (b) 3.66 4.67 4.96 4.21 4.04
Total lease operating expenses per Boe   24.22     23.63     23.84     23.90     23.19  
General and administrative expenses (excluding unit-based compensation) $ 8,742   $ 11,227   $ 9,815   $ 38,752   $ 33,281  
Net loss attributable to the partnership $ (58,792 ) $ (25,011 ) $ (10,334 ) $ (43,671 ) $ (40,801 )
 
Total production (MBoe) (c) 3,086 3,098 2,212 10,983 8,318
Oil (MBbl) 1,704 1,681 972 5,651 3,652
NGL (MBbl) 205 207 33 640 138
Natural gas (MMcf) 7,060 7,258 7,243 28,156 27,997
Average daily production (Boe/d)   33,542     33,674     24,044     30,091     22,726  
Sales volumes (MBoe) (d)   3,163     3,027     2,203     10,988     8,334  
Average realized sales price (per Boe) (e) (f) $ 61.10 $ 65.16 $ 51.29 $ 51.29 $ 49.57
Oil (per Bbl) (e) (f) 88.77 100.94 88.75 88.75 92.18
NGLs (per Bbl) (e) 42.17 38.11 25.61 35.25 27.96
Natural gas (per Mcf) (e)   3.75     3.69     3.69     3.82     3.00  
 
(a) Includes lease operating expenses, district expenses, transportation expenses and processing fees.
(b) Includes ad valorem and severance taxes.
(c) Natural gas is converted on the basis of six Mcf of gas per one Bbl of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a Bbl of oil equivalent for natural gas is significantly less than the price for a Bbl of oil.
(d) Oil sales were 1,782 (MBbl), 1,610 (MBbl), 963 (MBbl), 5,563 (MBbl) and 3,530 (MBbl) for the three months ended December 31, 2013 September 30, 2013 and December 31, 2012 and for the twelve months ended December 31, 2013 and 2012, respectively.
(e) Excludes the effect of commodity derivative settlements.
(f) Includes 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 are "Adjusted EBITDA" and "distributable cash flow." These non-GAAP financial measures should not be considered as alternatives 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. Distributable cash flow is used by management as a tool to measure the cash distributions we could pay to our unitholders. This financial measure indicates to investors whether or not we are generating cash flow at a level that can support our distribution rate to our unitholders. These non-GAAP financial measures 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 or distributable cash flow in the same manner.

Adjusted EBITDA

The following table presents a reconciliation of net income 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 2013 2013 2012 (a) 2013 2012 (a)
Reconciliation of net loss to Adjusted EBITDA:
Net loss attributable to the Partnership $ (58,792 ) $ (25,011 ) $ (10,334 ) ($43,671 ) (40,801 )
 
Loss (gain) on commodity derivative instruments 17,234 54,765 (3,715 ) 29,182 (5,580 )
Commodity derivative instrument settlements (b) (c) 4,450 (6,323 ) 22,455 8,083 87,605
Depletion, depreciation and amortization expense 62,400 59,764 40,350 216,495 137,252
Impairments 54,012 361 147 54,373 12,313
Interest expense and other financing costs 26,680 23,548 17,975 87,067 61,206
Loss on interest rate swaps (d) - - 175 - 1,101
Loss on sale of assets (2,154 ) 77 264 (2,015 ) 486
Income tax expense (benefit) 277 24 285 905 84
Unit-based compensation expense (e)   5,270     4,889     5,329     19,955     22,184  
Adjusted EBITDA $ 109,377 $ 112,094 $ 72,931 $ 370,374 $ 275,850
 
Less:
 
Maintenance capital (f) $ 29,217 $ 25,782 $ 16,774 $ 89,267 $ 63,446
Cash interest expense (g)   24,741     21,748     17,421     80,767     59,382  
Distributable cash flow available to common unitholders $ 55,419   $ 64,564   $ 38,736   $ 200,340   $ 153,022  
 
Distributable cash flow available per common unit (h) $ 0.46 $ 0.64 $ 0.45 $ 1.88 $ 1.95
Common unit distribution coverage 0.93x 1.31x 0.95x 0.97x 1.06x
 
Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
 
Net cash provided by operating activities $ 90,224 $ 69,520 $ 25,506 $ 257,166 191,782
 
Increase in assets net of liabilities relating to operating activities (5,680 ) 20,663 27,655 32,105 22,492
Interest expense (d) (i) 24,654 21,721 19,885 80,617 61,807
Income from equity affiliates, net (67 ) 121 (131 ) (55 ) (487 )
Incentive compensation expense (f) (21 ) - (82 ) (21 ) (82 )
Income taxes 267 69 98 562 400
Non-controlling interest - - - - (62 )
           
Adjusted EBITDA $ 109,377   $ 112,094   $ 72,931   $ 370,374   $ 275,850  
 
(a) Adjusted EBITDA for the three and twelve months ended December 31, 2012 was conformed to exclude $5.1 million and $19.9 million related to "Net operating cash flow from acquisitions, effective date through closing date."
(b) Excludes premiums paid at contract inception related to those derivative contracts that settled during the periods of: $ 1,233 $ 1,233 $ 517 $ 4,893 $ 859
(c) Includes net cash settlements on derivative instruments:
- Oil settlements received (paid) of: $ (7,378 ) $ (17,905 ) $ 4,701 $ (36,183 ) $ 3,855
- Natural gas settlements received of: $ 11,828 $ 11,583 $ 17,754 $ 44,266 $ 83,750
(d) Includes settlements paid on interest rate derivatives of: $ - $ - $ 3,196 $ - $ 5,469
(e) Represents non-cash long-term unit-based incentive compensation expense.
(f) Maintenance Capital is management's estimate of the investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately constant for the period.
(g) Excludes $2.5 million loss on termination of interest rate swaps for the three and twelve months ended December 31, 2012.
(h) Reflects common units outstanding (including outstanding LTIP grants) at each distribution record date.
(i) Excludes amortization of debt issuance costs and amortization of senior note discount/premium.
 

Hedge Portfolio Summary

The table below summarizes the Partnership's commodity derivative hedge portfolio as of February 26, 2014. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.

     

Year

2014   2015   2016   2017   2018
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Volume (Bbls/d) 13,814 12,689 9,211 7,971 493
Average Price ($/Bbl) $ 92.30 $ 93.01 $ 86.73 $ 84.23 $ 82.20
Fixed Price Swaps - ICE Brent
Volume (Bbls/d) 4,800 3,300 4,300 298 -
Average Price ($/Bbl) $ 98.88 $ 97.73 $ 95.17 $ 97.50 $ -
Collars - NYMEX WTI
Volume (Bbls/d) 1,000 1,000 - - -
Average Floor Price ($/Bbl) $ 90.00 $ 90.00 $ - $ - $ -
Average Ceiling Price ($/Bbl) $ 112.00 $ 113.50 $ - $ - $ -
Collars - ICE Brent
Volume (Bbls/d) - 500 500 - -
Average Floor Price ($/Bbl) $ - $ 90.00 $ 90.00 $ - $ -
Average Ceiling Price ($/Bbl) $ - $ 109.50 $ 101.25 $ - $ -
Puts - NYMEX WTI
Volume (Bbls/d) 500 500 1,000 - -
Average Price ($/Bbl) $ 90.00 $ 90.00 $ 90.00 $ - $ -
Total:
Volume (Bbls/d) 20,114 17,989 15,011 8,269 493
Average Price ($/Bbl) $ 93.70 $ 93.54 $ 89.48 $ 84.71 $ 82.20
 
Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Volume (MMBtu/d) 7,500 7,500 17,000 10,000 -
Average Price ($/MMBtu) $ 6.00 $ 6.00 $ 4.46 $ 4.48 $ -
Fixed Price Swaps - Henry Hub
Volume (MMBtu/d) 41,600 47,700 24,700 8,571 1,870
Average Price ($/MMBtu) $ 4.75 $ 4.77 $ 4.23 $ 4.39 $ 4.15
Puts - Henry Hub
Volume (MMBtu/d) 6,000 1,500 - - -
Average Price ($/MMBtu) $ 5.00 $ 5.00 $ - $ - $ -
Total:
Volume (MMBtu/d) 55,100 56,700 41,700 18,571 1,870
Average Price ($/MMBtu) $ 4.95 $ 4.94 $ 4.32 $ 4.44 $ 4.15
 
Calls - Henry Hub
Volume (MMBtu/d) 15,000 - - - -
Average Price ($/MMBtu) $ 9.00 $ - $ - $ - $ -
Deferred Premium ($/MMBtu) $ 0.12 $ - $ - $ - $ -
 

Premiums paid in 2012 related to oil and natural gas derivatives to be settled in 2014 and beyond are as follows:

 

Year

Thousands of dollars 2014 2015 2016 2017 2018
Oil $ 4,479 $ 4,683 $ 7,438 $ 734 $ -
Natural gas $ 4,015 $ 1,989 $ 952 $ - $ -
 

Other Information

The Partnership will host an investor conference call to discuss its results today at 9:00 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 888-437-9445 (international callers dial +1-719-457-2697) 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 6, 2014 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 7789996, 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 oil and natural gas reserves are located in Michigan, Oklahoma, Texas, 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," "expect," "future," "impact," "guidance," "will be," "future" 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.

 
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets
       
 
December 31, December 31,
Thousands 2013 2012
ASSETS
Current assets
Cash $ 2,458 $ 4,507
Accounts and other receivables, net 96,862 67,862
Derivative instruments 7,914 34,018
Related party receivables 2,604 1,413
Inventory 3,890 3,086
Prepaid expenses   3,334     2,779  
Total current assets 117,062 113,665
Equity investments 6,641 7,004
Property, plant and equipment
Oil and gas properties 4,818,639 3,363,946
Other assets   21,338     14,367  
4,839,977 3,378,313
Accumulated depletion and depreciation   (924,601 )   (666,420 )
Net property, plant and equipment 3,915,376 2,711,893
Other long-term assets
Intangibles, net 11,679 -
Derivative instruments 71,319 55,210
Other long-term assets 74,205 27,722
   
Total assets $ 4,196,282   $ 2,915,494  
LIABILITIES AND EQUITY
Current liabilities
Accounts payable $ 69,809 $ 42,497
Derivative instruments 24,876 5,625
Revenue and royalties payable 26,233 22,262
Wages and salaries payable 15,359 10,857
Accrued interest payable 19,690 13,002
Accrued liabilities   26,922     20,997  
Total current liabilities 182,889 115,240
 
Credit facility 733,000 345,000
Senior notes, net 1,156,675 755,696
Deferred income taxes 2,749 2,487
Asset retirement obligation 123,769 98,480
Derivative instruments 2,560 4,393
Other long-term liabilities   4,820     4,662  
Total liabilities 2,206,462 1,325,958
 
Partners' equity   1,989,820     1,589,536  
 
Total liabilities and equity $ 4,196,282   $ 2,915,494  
 
Common units outstanding 119,170 84,668
 
- -
 
 
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Operations
       
Three Months Ended Twelve Months Ended
December 31, December 31,
Thousands of dollars, except per unit amounts 2013   2012 2013   2012
 
Revenues and other income items
Oil, NGL and natural gas sales $ 193,604 $ 113,179 $ 660,665 $ 413,867
Gain (loss) on commodity derivative instruments, net (17,234 ) 3,715 (29,182 ) 5,580
Other revenue, net   978     700     3,175     3,548  
Total revenues and other income items 177,348 117,594 634,658 422,995
Operating costs and expenses
Operating costs 80,933 53,576 262,822 195,779
Depletion, depreciation and amortization 62,400 40,350 216,495 137,252
Impairments 54,012 147 54,373 12,313
General and administrative expenses 14,012 15,144 58,707 55,465
(Gain) Loss on sale of assets   (2,154 )   264     (2,015 )   486  
 
Operating (loss) income (31,855 ) 8,113 44,276 21,700
 
Interest expense, net of capitalized interest 26,680 17,975 87,067 61,206
Loss on interest rate swaps - 175 - 1,101
Other expense (income), net   (20 )   12     (25 )   48  
Total other expense   26,660     18,162     87,042     62,355  
 
Loss before taxes (58,515 ) (10,049 ) (42,766 ) (40,655 )
 
Income tax expense   277     285     905     84  
 
Net loss (58,792 ) (10,334 ) (43,671 ) (40,739 )
 
Less: Net income attributable to noncontrolling interest - - - (62 )
       
Net loss attributable to the partnership   (58,792 )   (10,334 )   (43,671 )   (40,801 )
 
Basic net loss per unit $ (0.52 ) $ (0.13 ) $ (0.43 ) $ (0.56 )
Diluted net loss income per unit $ (0.52 ) $ (0.13 ) $ (0.43 ) $ (0.56 )
 
 
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows
 
 
      Twelve Months Ended
December 31,
Thousands of dollars 2013   2012
 
Cash flows from operating activities
Net loss $ (43,671 ) $ (40,739 )
Adjustments to reconcile net loss to cash flow from operating activities:
Depletion, depreciation and amortization 216,495 137,252
Impairments 54,373 12,313
Unit-based compensation expense 19,955 22,266
(Gain) loss on derivative instruments 29,182 (4,479 )
Derivative instrument settlements 8,083 84,615
Prepaid premiums on derivative instruments - (30,043 )
Settlement payments on terminated derivative instruments - (2,479 )
Income from equity affiliates, net (55 ) 487
Deferred income taxes 262 (316 )
(Gain) loss on sale of assets (2,015 ) 486
Other 5,163 4,472
Changes in assets and liabilities:
Accounts receivable and other assets (29,322 ) 6,759
Inventory (804 ) 1,638
Net change in related party receivables and payables (1,191 ) 2,832
Accounts payable and other liabilities   711     (3,282 )
Net cash provided by operating activities   257,166     191,782  
Cash flows from investing activities
Property acquisitions (1,175,817 ) (562,356 )
Capital expenditures (266,308 ) (135,932 )
Other (26,661 ) -
Proceeds from sale of assets   2,981     1,129  
Net cash used in investing activities   (1,465,805 )   (697,159 )
Cash flows from financing activities
Issuance of common units 618,013 370,234
Distributions (186,868 ) (132,420 )
Proceeds from issuance of long-term debt, net 2,276,000 1,502,885
Repayments of long-term debt (1,487,000 ) (1,223,000 )
Change in book overdraft 2,013 (3,176 )
Debt issuance costs   (15,568 )   (9,967 )
Net cash provided by financing activities   1,206,590     504,556  
Decrease in cash (2,049 ) (821 )
Cash beginning of period   4,507     5,328  
Cash end of period $ 2,458   $ 4,507  

BBEP-IR

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

Source: BreitBurn Energy Partners L.P.

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