Breitburn Energy Partners LP
Feb 28, 2013

BreitBurn Energy Partners L.P. Reports Fourth Quarter and Record Full Year Production and EBITDA Results; Provides Full Year 2013 Guidance

 

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 2012 as well as public guidance for its expected performance in 2013, excluding any future acquisitions.

Key Highlights

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

Full Year 2012 Results

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 Ended     Year Ended December 31,
        December 31,   September 30,   December 31,          
  Thousands of dollars, except as indicated       2012         2012         2011         2012         2011  
  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       $