February 28, 2013 at 08:30 AM EST
BreitBurn Energy Partners L.P. Reports Fourth Quarter and Record Full Year Production and EBITDA Results; Provides Full Year 2013 Guidance

BreitBurn Energy Partners L.P. (the “Partnership”) (NASDAQ:BBEP) today announced financial and operating results for its fourth quarter and full year 2012 as well as public guidance for its expected performance in 2013, excluding any future acquisitions.

Key Highlights

  • For the full year 2012, the Partnership reported record net production and Adjusted EBITDA which increased 18% and 31%, respectively, from 2011. For the fourth quarter of 2012, net production increased 7% and Adjusted EBITDA increased 21% from the fourth quarter of 2011.
  • On February 14, 2013, the Partnership increased its cash distributions for the fourth quarter of 2012 to $0.47 per unit, or $1.88 per unit on an annualized basis.
  • For the full year 2012, the Partnership paid cash distributions of $1.85 per unit, representing an increase of 7.2% over 2011 cash distributions of $1.73 per unit.
  • On December 3, 2012, the Partnership completed the acquisition of oil and gas properties in Kern County, California for approximately $38 million in cash and approximately 3 million common units.
  • On December 28, 2012, the Partnership completed acquisitions of oil and gas properties in the Permian Basin in Texas for approximately $202 million.
  • On February 7, 2013, the Partnership completed a public offering of 14.95 million common units. Net proceeds from the offering were used to reduce borrowings under the Partnership’s bank credit facility.
  • As of February 27, 2013, the Partnership had $77 million in outstanding borrowings under its credit facility, which has total lender commitments of $900 million and the ability to increase commitments to $1 billion with lender approval.

Management Commentary

Hal Washburn, CEO, said: “The Partnership had an exceptional year with record production, record Adjusted EBITDA, sequential distribution growth, and the completion of seven acquisitions in Texas, California, and Wyoming. We are very pleased to have exceeded our acquisition target of $300 million to $500 million for the year by completing over $600 million in acquisitions which were primarily oil. We also established a significant presence in the Permian Basin and greatly expanded the organic growth opportunities in our portfolio. The Partnership is very well positioned to execute on its 2013 capital program and its growth through acquisitions strategy.”

Fourth Quarter 2012 Operating and Financial Results Compared to Third Quarter 2012

  • Total production increased to a record quarterly high of 2,212 MBoe in the fourth quarter of 2012 from 2,166 MBoe in the third quarter of 2012. Average daily production was 24,044 Boe/day in the fourth quarter of 2012 compared to 23,545 Boe/day in the third quarter of 2012.
    • Oil and NGL production was 1,005 MBoe compared to 973 MBoe.
    • Natural gas production was 7,243MMcf compared to 7,161 MMcf.
  • Adjusted EBITDA, a non-GAAP financial measure, was $78.0 million in the fourth quarter of 2012 compared to $90.1 million in the third quarter of 2012 primarily due to the timing of oil shipments from our Florida operations.
  • Lease operating expenses, which include district expenses and processing fees and exclude production and property taxes and transportation costs, were $18.88 per Boe in the fourth quarter of 2012 as compared to $18.62 per Boe in the third quarter of 2012.
  • General and administrative expenses, excluding non-cash unit-based compensation were $4.44 per Boe in the fourth quarter of 2012 as compared to $3.73 per Boe in the third quarter of 2012.
  • Oil and natural gas sales revenues were $113.2 million for the fourth quarter of 2012, up from $111.7 million in the third quarter of 2012, primarily reflecting higher natural gas prices.
  • Realized gains on commodity derivative instruments were $22.5 million in the fourth quarter of 2012, consistent with realized gains in the third quarter of 2012.
  • NYMEX WTI crude oil spot prices averaged $88.01 per barrel and Brent crude oil spot prices averaged $110.15 per barrel in the fourth quarter of 2012 compared to $92.17 per barrel and $109.63 per barrel, respectively, in the third quarter of 2012. Henry Hub natural gas spot prices averaged $3.40 per Mcf in the fourth quarter of 2012 compared to $2.88 per Mcf in the third quarter of 2012.
  • Realized crude oil and NGL prices averaged $91.38 per Boe and realized natural gas prices averaged $6.14 per Mcf in the fourth quarter of 2012, compared to $89.55 per Boe and $5.89 per Mcf, respectively, in the third quarter of 2012.
  • Net loss attributable to the Partnership, including the effect of unrealized losses on commodity derivative instruments, was $10.3 million, or $0.13 per diluted common unit, in the fourth quarter of 2012 compared to net loss of $73.0 million, or $1.00 per diluted common unit, in the third quarter of 2012.
  • Total oil and gas capital expenditures totaled $60 million in the fourth quarter of 2012 compared to $49 million in the third quarter of 2012.

Full Year 2012 Results

  • Total production was 8,318 MBoe in 2012, an increase of 18% from 2011 and the highest in the Partnership’s history.
  • Adjusted EBITDA, a non-GAAP measure, was $295.8 million, an increase of 31% from 2011 and a record high for the Partnership.
  • Total oil, natural gas and NGL sales were $413.9 million in 2012, an increase of 5% from 2011.
  • Oil and gas capital expenditures were $153 million, an increase of 104% from 2011.
  • Full year lease operating expenses per Boe were $19.15, which was 1% lower than 2011.
  • Full year general and administrative expenses, excluding unit-based compensation, were $4.00 per Boe, which was 11% lower than 2011.
  • Average realized crude oil prices for 2012 were $90.82 per Boe compared to NYMEX WTI crude oil prices of $94.05 per barrel. Average realized natural gas prices were $5.99 per Mcf, compared to Henry Hub prices of $2.75 per Mcf.
  • Net loss attributable to the Partnership, including the effect of unrealized losses on commodity derivative instruments, was $40.8 million, or $0.56 per diluted common unit, in 2012 compared to net income of $110.5 million, or $1.79 per diluted common unit, in 2011.

2012 Estimated Proved Reserves

BreitBurn's total estimated proved oil and gas reserves as of December 31, 2012 were 149.4 MMBoe. The standardized measure of discounted future net cash flows related to our estimated proved reserves was approximately $1.99 billion, 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 $2.76 per MMBtu for gas and $94.71 per Bbl of oil. Of the total estimated proved reserves, 53% were oil and 47% were natural gas; 80% were classified as proved developed; and 35% were located in Michigan, 26% in Wyoming, 17% in California, 15% in Texas and 7% in Florida, with less than 1% in Indiana and Kentucky.

2013 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.

($ in 000s) Assuming no acquisitions FY 2013 Guidance
Total Production (Mboe): 9,500 - 10,100
Oil Production (Mbbls) 5,050 - 5,350
Gas Production (MMcfe) 26,700 - 28,500
December 2013 Exit Rate (boe/d) 27,700 - 28,850
Average Price Differential %:
WTI Oil Price Differential % 90 % - 91 %
Brent Oil Price Differential %(1) 95 % - 96 %
Gas Price Differential % 102 % - 103 %
Operating Costs / BOE(2)(3) $18.25 - $20.25
Production / Property Taxes (% of oil & gas revenue) 7.5 % - 8.0 %
G&A (Excl. Unit Based Compensation) $33,000 - $35,000
Cash Interest Expense(4) $69,000 - $71,000
Adjusted EBITDA(5) $330,000 - $340,000
Capital Expenditures(6):
Maintenance Capital $75,000
Growth Capital $178,000 - $188,000
(1) 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 $6.7 million in 2013, largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs range per Boe is approximately $17.58 - $19.58.
(3) Operating Costs are based on flat price levels for 2013 of $95 per barrel for WTI crude oil, $105 per barrel for Brent crude oil and $3.50 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 0.3%.
(5) Assuming the high and low range of our guidance, Adjusted EBITDA, a non-GAAP financial measure, is expected to range between $330 million and $340 million, and is comprised of estimated net income (before non-cash compensation) between $77 million and $65 million, plus unrealized loss on commodity derivative instruments of $27 million, plus DD&A of $167 million, plus interest expense between $69 million (high end of Adjusted EBITDA) and $71 million (low end of Adjusted EBITDA). Estimated 2013 net income is based on oil prices of $95 per barrel for WTI crude oil, $105 per barrel for Brent crude oil and $3.50 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.
(6) Total oil and gas capital expenditures for 2013 excludes acquisitions, capitalized engineering costs and 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 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 $87.6 million for the year ended December 31, 2012. Realized losses from interest rate derivative instruments were $5.5 million for the year ended December 31, 2012, which included $2.5 million in realized loss from the termination of an interest rate swap. Non-cash unrealized losses from commodity derivative instruments were $82.0 million and non-cash unrealized gains from interest rate derivative instruments were $4.4 million for the year ended December 31, 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 December 31, 2012 and 2011, the three months ended September 30, 2012 and the years ended December 31, 2012 and 2011:

Three Months EndedYear Ended December 31,
December 31,September 30,December 31,
Thousands of dollars, except as indicated20122012201120122011
Oil, natural gas and NGLs sales $ 113,179 $ 111,700 $ 109,720 $ 413,867 $ 394,393
Realized gain (loss) on commodity derivative instruments 22,455 22,496 (28,851 ) 87,605 (16,067 )
Unrealized gain (loss) on commodity derivative instruments (18,740 ) (91,914 ) (8,614 ) (82,025 ) 97,734
Other revenues, net 700 796 894 3,548 4,310
Total revenues $ 117,594 $ 43,078 $ 73,149 $ 422,995 $ 480,370
Lease operating expenses and processing fees $ 41,769 $ 40,325 $ 38,093 $ 159,289 $ 136,441
Production and property taxes 10,962 8,574 7,946 33,634 26,599
Total lease operating expenses $ 52,731 $ 48,899 $ 46,039 $ 192,923 $ 163,040
Purchases and other operating costs 267 293 210 1,577 961
Change in inventory 578 856 255 1,279 1,968
Total operating costs $ 53,576 $ 50,048 $ 46,504 $ 195,779 $ 165,969
Lease operating expenses pre taxes per Boe (a) $ 18.88 $ 18.62 $ 18.45 $ 19.15 $ 19.39
Production and property taxes per Boe 4.96 3.96 3.85 4.04 3.78
Total lease operating expenses per Boe 23.84 22.58 22.30 23.19 23.17
General and administrative expenses (excluding unit-based compensation) $ 9,815 $ 8,069 $ 9,480 $ 33,281 $ 31,311
Net income (loss) attributable to the partnership $ (10,334 ) $ (73,003 ) $ (30,392 ) $ (40,801 ) $ 110,497
Net income (loss) per diluted limited partner unit $ (0.13 ) $ (1.00 ) $ (0.51 ) $ (0.56 ) $ 1.79
Total production (MBoe) 2,212 2,166 2,065 8,318 7,037
Oil and NGLs (MBoe) (b) 1,005 973 871 3,652 3,255
Natural gas (MMcf) 7,243 7,161 7,168 27,997 22,697
Average daily production (Boe/d) 24,044 23,545 22,450 22,726 19,281
Sales volumes (MBoe) 2,203 2,219 2,080 8,334 7,106
Average realized sales price (per Boe) (c) (d) $ 61.49 $ 60.40 $ 56.48 $ 60.09 $ 58.33
Oil and NGLs (per Boe) (c) (d) 91.38 89.55 84.00 90.82 79.80
Natural gas (per Mcf) (c) 6.14 5.89 6.02 5.99 6.58
(a) Includes lease operating expenses, district expenses, transportation expenses and processing fees.
(b) NGLs account for less than 3% of total production.
(c) Includes realized gain 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. 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 2012 2012 2011 2012 2011

Reconciliation of net income (loss) to Adjusted EBITDA:
Net income (loss) attributable to the Partnership $ (10,334 ) $ (73,003 ) $ (30,392 ) ($40,801 ) 110,497
Unrealized (gain) loss on commodity derivative instruments 18,740 91,914 8,614 82,025 (97,734 )
Depletion, depreciation and amortization expense 40,497 37,270 31,149 149,565 107,503
Interest expense and other financing costs (a) 21,171 16,174 11,492 66,675 42,422
Unrealized (gain) on interest rate derivatives (3,021 ) (570 ) (340 ) (4,368 ) (480 )
Loss on early termination of commodity derivatives (b) - - 36,779 - 36,779
Loss (gain) on sale of assets 264 68 (71 ) 486 (111 )
Income taxes 285 (647 ) (321 ) 84 1,188
Unit-based compensation expense (c) 5,329 5,652 5,707 22,184 22,002
Net operating cash flow from acquisitions, effective date through closing date 5,092 13,227 1,808 19,914 2,886
Adjusted EBITDA $ 78,023 $ 90,085 $ 64,425 $ 295,764 $ 224,952
Three Months Ended Year Ended December 31,
December 31, September 30, December 31,
Thousands of dollars 2012 2012 2011 2012 2011
Reconciliation of net cash flows from operating activities to Adjusted EBITDA:
Net cash provided by (used in) operating activities $ 25,506 $ 65,725 $ (241 ) $ 191,782 128,543
Increase (decrease) in assets net of liabilities relating to operating activities

27,655

(3,935 ) 15,503

22,492

18,942
Interest expense (a) (d) 19,885 15,133 10,394 61,807 37,702
Loss on early termination of commodity derivatives (b) - - 36,779 36,779
Income from equity affiliates, net (131 ) (47 ) (41 ) (487 ) (210 )
Incentive compensation expense (e) (82 ) - (2 ) (82 ) (41 )
Incentive compensation paid - - - - 78
Income taxes 98 (18 ) 278 400 474
Non-controlling interest - - (53 ) (62 ) (201 )
Net operating cash flow from acquisitions, effective date through closing date 5,092 13,227 1,808 19,914 2,886
Adjusted EBITDA $

78,023

$ 90,085 $ 64,425 $

295,764

$ 224,952
(a) Includes realized 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/premium.
(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 27, 2013. Please refer to the updated Commodity Price Protection Portfolio via our website for additional details related to our hedge portfolio.

Year

20132014201520162017
Oil Positions:
Fixed Price Swaps - NYMEX WTI
Hedged Volume (Bbls/d) 5,338 4,814 4,189 1,611 222
Average Price ($/Bbl) $ 91.32 $ 93.07 $ 96.61 $ 91.50 $ 88.12
Fixed Price Swaps - ICE Brent
Hedged Volume (Bbls/d) 4,200 4,800 3,300 2,800 1,548
Average Price ($/Bbl) $ 97.57 $ 98.88 $ 97.73 $ 95.79 $ 88.21
Collars - NYMEX WTI
Hedged Volume (Bbls/d) 500 1,000 1,000 - -
Average Floor Price ($/Bbl) $ 77.00 $ 90.00 $ 90.00 $ - $ -
Average Ceiling Price ($/Bbl) $ 103.10 $ 112.00 $ 113.50 $ - $ -
Collars - ICE Brent
Hedged Volume (Bbls/d) - - 500 500 -
Average Floor Price ($/Bbl) $ - $ - $ 90.00 $ 90.00 $ -
Average Ceiling Price ($/Bbl) $ - $ - $ 109.50 $ 101.25 $ -
Puts - NYMEX WTI
Hedged Volume (Bbls/d) 1,000 500 500 1,000 -
Average Price ($/Bbl) $ 90.00 $ 90.00 $ 90.00 $ 90.00 $ -
Total:
Hedged Volume (Bbls/d) 11,038 11,114 9,489 5,911 1,769
Average Price ($/Bbl) $ 92.93 $ 95.17 $ 95.61 $ 93.15 $ 88.20
Gas Positions:
Fixed Price Swaps - MichCon City-Gate
Hedged Volume (MMBtu/d) 37,000 7,500 7,500 7,000 -
Average Price ($/MMBtu) $ 6.50 $ 6.00 $ 6.00 $ 4.51 $ -
Fixed Price Swaps - Henry Hub
Hedged Volume (MMBtu/d) 21,100 38,600 43,200 18,200 5,571
Average Price ($/MMBtu) $ 4.76 $ 4.80 $ 4.83 $ 4.22 $ 4.51
Puts - Henry Hub
Hedged Volume (MMBtu/d) - 6,000 1,500 - -
Average Price ($/MMBtu) $ - $ 5.00 $ 5.00 $ - $ -
Total:
Hedged Volume (MMBtu/d) 58,100 52,100 52,200 25,200 5,571
Average Price ($/MMBtu) $ 5.87 $ 4.99 $ 5.00 $ 4.30 $ 4.51
Calls - Henry Hub
Hedged Volume (MMBtu/d) 30,000 15,000 - - -
Average Price ($/MMBtu) $ 8.00 $ 9.00 $ - $ - $ -
Deferred 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 800-572-7025(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 14, 2013 by dialing 877-870-5176 (international callers dial +1-858-384-5517) and entering replay PIN 8245339, 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, 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,” “expected,” “future,” “impact,” “guidance,” “assuming,” “forecast,” “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.

BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Balance Sheets
December 31,December 31,
Thousands20122011
ASSETS
Current assets
Cash $ 4,507 $ 5,328
Accounts and other receivables, net 67,862 73,018
Derivative instruments 34,018 83,452
Related party receivables 1,413 4,245
Inventory 3,086 4,724
Prepaid expenses 2,779 2,053
Total current assets 113,665 172,820
Equity investments 7,004 7,491
Property, plant and equipment
Oil and gas properties 3,363,946 2,583,993
Other assets 14,367 13,431
3,378,313 2,597,424
Accumulated depletion and depreciation (666,420 ) (524,665 )

Net property, plant and equipment

2,711,893 2,072,759
Other long-term assets
Derivative instruments 55,210 55,337
Other long-term assets 27,722 22,442
Total assets $ 2,915,494 $ 2,330,849
LIABILITIES AND EQUITY
Current liabilities
Accounts payable $ 42,497 $ 27,203
Derivative instruments 5,625 8,881
Revenue and royalties payable 22,262 19,641
Salaries and wages payable 10,857 13,655
Accrued interest payable 13,002 6,291
Accrued liabilities 20,997 14,218

Total current liabilities

115,240 89,889
Credit facility 345,000 520,000
Senior notes, net 755,696 300,613
Deferred income taxes 2,487 2,803
Asset retirement obligation 98,480 82,397
Derivative instruments 4,393 3,084
Other long-term liabilities 4,662 4,849
Total liabilities 1,325,958 1,003,635
Equity
Partners' equity 1,589,536 1,326,764
Noncontrolling interest - 450

Total equity

1,589,536 1,327,214
Total liabilities and equity $ 2,915,494 $ 2,330,849
Common units outstanding 84,668 59,864
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Operations
Three Months EndedYear Ended
December 31,December 31,
Thousands of dollars, except per unit amounts2012201120122011
Revenues and other income items
Oil, natural gas and natural gas liquid sales $ 113,179 $ 109,720 $ 413,867 $ 394,393
Gain (loss) on commodity derivative instruments, net 3,715 (37,465 ) 5,580 81,667
Other revenue, net 700 894 3,548 4,310
Total revenues and other income items 117,594 73,149 422,995 480,370
Operating costs and expenses
Operating costs 53,576 46,504 195,779 165,969
Depletion, depreciation and amortization 40,497 31,149 149,565 107,503
General and administrative expenses 15,144 15,187 55,465 53,313
Loss (gain) on sale of assets 264 (71 ) 486 (111 )
Unreimbursed litigation settlement costs - (113 ) - (113 )
Operating income (loss) 8,113 (19,507 ) 21,700 153,809
Interest expense, net of capitalized interest 17,975 11,395 61,206 39,165
Loss on interest rate swaps 175 (243 ) 1,101 2,777
Other expense (income), net 12 1 48 (19 )
Total other expense 18,162 11,153 62,355 41,923
Income (loss) before taxes (10,049 ) (30,660 ) (40,655 ) 111,886
Income tax expense (benefit) 285 (321 ) 84 1,188
Net income (loss) (10,334 ) (30,339 ) (40,739 ) 110,698
Less: Net income attributable to noncontrolling interest - (53 ) (62 ) (201 )
Net income (loss) attributable to the partnership (10,334 ) (30,392 ) (40,801 ) 110,497
Basic net income (loss) per unit $ (0.13 ) $ (0.51 ) $ (0.56 ) $ 1.80
Diluted net income (loss) per unit $ (0.13 ) $ (0.51 ) $ (0.56 ) $ 1.79
BreitBurn Energy Partners L.P. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows
Year Ended
December 31,
Thousands of dollars20122011
Cash flows from operating activities
Net income (loss) $ (40,739 ) $ 110,698
Adjustments to reconcile net income to cash flow from operating activities:
Depletion, depreciation and amortization 149,565 107,503
Unit-based compensation expense 22,266 22,043
Unrealized loss (gain) on derivative instruments 77,657 (98,214 )
Income from equity affiliates, net 487 210
Deferred income taxes (316 ) 714
Loss (gain) on sale of assets 486 (111 )
Other 4,472 (312 )
Changes in assets and liabilities:
Accounts receivable and other assets (23,284 ) (17,833 )
Inventory 1,638 2,597
Net change in related party receivables and payables 2,832 100
Accounts payable and other liabilities (3,282 ) 1,148
Net cash provided by operating activities 191,782 128,543
Cash flows from investing activities
Capital expenditures (135,932 ) (78,107 )
Proceeds from sale of assets 1,129 2,339
Property acquisitions (562,356 ) (338,805 )
Net cash used in investing activities (697,159 ) (414,573 )
Cash flows from financing activities
Issuance of common units 370,234 99,443
Distributions (132,420 ) (102,686 )
Proceeds from issuance of long-term debt, net 1,502,885 661,500
Repayments of long-term debt (1,223,000 ) (369,500 )
Change in book overdraft (3,176 ) 2,636
Debt issuance costs (9,967 ) (3,665 )
Net cash provided by financing activities 504,556 287,728
Increase (decrease) in cash (821 ) 1,698
Cash beginning of period 5,328 3,630
Cash end of period $ 4,507 $ 5,328

BBEP-IR

Contacts:

BreitBurn Energy Partners L.P.
Investor Relations Contacts:
James G. Jackson
Executive Vice President and Chief Financial Officer
213-225-5900 x273
or
Jessica Tang, Investor Relations
213-225-5900 x210
Stock Market XML and JSON Data API provided by FinancialContent Services, Inc.
Nasdaq quotes delayed at least 15 minutes, all others at least 20 minutes.
Markets are closed on certain holidays. Stock Market Holiday List
By accessing this page, you agree to the following
Privacy Policy and Terms and Conditions.
Press Release Service provided by PRConnect.
Stock quotes supplied by Six Financial
Postage Rates Bots go here