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") (NAS: 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.
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.
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.
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):
Oil Production (Mbbls)
Gas Production (MMcfe)
December 2013 Exit Rate (boe/d)
Average Price Differential %:
WTI Oil Price Differential %
Brent Oil Price Differential %(1)
Gas Price Differential %
Operating Costs / BOE(2)(3)
Production / Property Taxes (% of oil & gas revenue)
G&A (Excl. Unit Based Compensation)
Cash Interest Expense(4)
Approximately 30% of oil production is expected to be sold based on Brent pricing.
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.
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.
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%.
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.
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,
Thousands of dollars, except as indicated
Oil, natural gas and NGLs sales
Realized gain (loss) on commodity derivative instruments
Unrealized gain (loss) on commodity derivative instruments
Other revenues, net
Lease operating expenses and processing fees
Production and property taxes
Total lease operating expenses
Purchases and other operating costs
Change in inventory
Total operating costs
Lease operating expenses pre taxes per Boe (a)
Production and property taxes per Boe
Total lease operating expenses per Boe
General and administrative expenses (excluding unit-based compensation)
Net income (loss) attributable to the partnership
Net income (loss) per diluted limited partner unit
Total production (MBoe)
Oil and NGLs (MBoe) (b)
Natural gas (MMcf)
Average daily production (Boe/d)
Sales volumes (MBoe)
Average realized sales price (per Boe) (c) (d)
Oil and NGLs (per Boe) (c) (d)
Natural gas (per Mcf) (c)
(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.
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.