April 17, 2009

BreitBurn Energy Partners Announces Results of Borrowing Base Redetermination, Temporary Suspension of Distributions and Full Year 2009 Guidance

Management Will Host Conference Call and Web cast on Monday, April 20 at 9 a.m. Eastern Time

LOS ANGELES, Apr 17, 2009 (BUSINESS WIRE) -- BreitBurn Energy Partners L.P. (the "Partnership") (NASDAQ:BBEP) announced today: (1) its borrowing base under its credit facility has been redetermined, with no additional fees and no increase in borrowing rates, at $760 million, which exceeds current borrowings of $717 million; (2) having investigated a number of potential sources of capital, none of which were available on terms acceptable to the Partnership, it is temporarily suspending distributions to remain in compliance with certain provisions of its credit facility and to redirect cash flow to pay down debt; (3) it expects to remain in compliance with all the provisions of its credit facility for 2009; and (4) its outlook for significant cash flow and liquidity in 2009 is in line with expanded full year guidance.

Hal Washburn, Chairman and Co-CEO said, "Given the economic outlook for the balance of the year and the continued distress in the credit markets, we are placing a premium on liquidity. We expect significant cash flow in 2009 and will redirect that internally generated cash flow to debt reduction in the near term while temporarily suspending distributions to our unitholders. Debt reduction will accrue to the immediate benefit of all of our unitholders in the form of less debt, greater equity value, and more financial and operating flexibility. We reviewed a number of capital raising alternatives simultaneous with the redetermination process. Unfortunately, none were available on terms we considered acceptable. We will continue to look at all reasonable alternatives for reducing outstanding debt more rapidly and will pursue them if management and the Board deem they are in the long-term best interest of the Partnership."

Borrowing Base Redetermined at $760 Million Which Exceeds Current Borrowings

In connection with the April 2009 scheduled borrowing base redetermination under the Partnership's existing credit agreement, the Partnership's borrowing base was reset at $760 million. While this borrowing base is more than 15% below the Partnership's previous borrowing base of $900 million, it remains well in excess of the Partnership's current borrowings of $717 million and the Partnership's expected borrowing levels at April 30th of approximately $700 million. As a result, the Partnership is in compliance with all of the financial covenants under the facility and by temporarily suspending distributions expects to remain in compliance through 2009.

This redetermination was completed with no modifications to the terms of the facility, including no additional fees and no increase in borrowing rates which are currently very advantageous for the Partnership. The facility matures on November 1, 2011. The Partnership has no other debt outstanding other than borrowings under the facility.

The long-lived nature of our assets and our extensive hedge portfolio were critical to supporting our borrowing base given the unprecedented decline in oil and gas prices since our last redetermination process was completed in October of last year. We currently have approximately 85% of our expected production in 2009 and 2010 hedged at very attractive prices and the balance of our hedge portfolio extends through 2012.

Focus on Near Term Debt Reduction In 2009 Funded Through The Temporary Suspension of Distributions

Based upon the Partnership's existing borrowing levels, the Partnership intends to redirect cash flow to the payment of debt. As discussed in the Partnership's Form 10-K, the Partnership's "credit facility restricts our ability to make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90 percent of our borrowing base. In the event of a substantial reduction in our borrowing base at the time of a borrowing base redetermination, this restriction may prevent us from making distributions to unitholders." With the most recent borrowing base redetermination, the Partnership's borrowings exceed 90 percent of the Partnership's borrowing base. Therefore, we will not make distributions until outstanding debt is reduced below required thresholds.

In advance of and during the recent borrowing base redetermination process, the Partnership investigated a number of potential sources of capital to be used to pay down existing debt. These options included additional capital raising alternatives, asset sales, hedge monetization transactions and other transactions or mechanisms, including potentially revising the terms of the credit facility, to repay debt or otherwise provide relief fromcertain restrictive provisions of the credit facility. However, none of these alternatives were available on terms acceptable to the Partnership. The Partnership will continue to review capital raising alternatives on acceptable terms with the goal of re-establishing distributions when the benefits exceed the costs.

Based on current market conditions and the outlook for commodity prices, Management expects that the future resumption of distributions may be at levels below the recent distribution rate. In addition, while the Partnership expects significant profitability and cash flow in 2009, economic and commodity price uncertainties make the expected timing for the resumption of distributions difficult to predict.

Significant Steps to Further Improve Liquidity And Deliver Strong Operating Performance

As we have previously stated, our goals for 2009 are to fund our operations, capital expenditures, interest payments and distributions to unitholders from our internally generated cash flow and to preserve financial flexibility and liquidity to maintain our assets and operations in anticipation of future improvement in the overall economic environment, commodity prices and financial markets.

Consistent with these goals, the Partnership has taken a number of significant steps to reduce costs, conserve capital and generate substantial cash flow. These include:

a) Capital Spending Reductions - In response to the rapid and substantial decline in oil and natural gas prices, the outlook for the broader economy and the ongoing turmoil in the financing markets, we elected to significantly reduce our capital spending and drilling activity in 2009. Total capital expenditures in 2009 are expected to be between $20 million and $24 million, compared to $129.5 million in 2008.

b) General and Administrative Expense Reductions - Management has recently undertaken a comprehensive review of costs and has made reductions in numerous areas. Chief among these were the consolidation of operating divisions and the elimination of a number of professional and administrative positions, as well as significant targeted reductions in other third party related expenses and incentive compensation costs. Management expects general and administrative expenses, excluding unit based compensation expense, in 2009 to be between $23 million and $25 million, or 32% to 38% below the 2008 total of $37 million. This overall reduction includes approximately $10.1 million of costs related to field/regional operations that were previously categorized by the Partnership as general and administrative expenses but will be classified as operating costs going forward. This approach is consistent with industry practice and with the treatment of these expenses by the prior operator of our largest group of assets.

c) Hedge Monetization Program - In January the Partnership elected to monetize a portion of its 2011 and 2012 hedge portfolio with the proceeds used to reduce debt and rehedged substantially similar volumes at then current pricing. This resulted in proceeds of approximately $45.6 million which were used to reduce outstanding debt.

Based on these actions, as reflected in the expanded full year guidance provided below, the Partnership expects to operate as planned and generate substantial cash flow in 2009 despite current commodity price weakness. The Partnership expects to generate Adjusted EBITDA (a non-GAAP measure) of between $178 million and $196 million in 2009. For a reconciliation of EBITDA to estimated Net Income see footnote 8 to the Guidance table below. These expectations are based on a number of operating and other assumptions, including commodity prices of $40 per barrel for WTI crude oil and $4 per Mcfe for natural gas and reflect the substantial benefits of the Partnership's existing hedge portfolio.

2009 Guidance

The following guidance is subject to all cautionary statements and limitations described below and under the caption "Cautionary Statement Relevant to 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 expectation 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) Full Year 2009 Guidance
Total Production (Mboe) 6,100 - 6,500
Production Mix:
Oil Production %

46%

Gas Production %

54%

Average Price Differential %:
Oil Price Differential % 84% - 86%
Gas Price Differential % 100% - 102%
Operating Costs per Boe(1)(2)(3) $16.75 - $19.25
Production Taxes (as % of Oil and Gas Revenue) 6.0% - 6.5%
G&A (Excl. Unit Based Compensation)(4) $23,000 - $25,000
Cash Interest Expense(5) $32,000 - $34,000
Total Capital Expenditures(6)(7) $20,000 - $24,000

Adjusted EBITDA(8)

$178,000 - $196,000

1. Operating Costs include lease operating costs, processing fees and transportation expense. Expected transportation expense totals approximately $4 million in 2009, largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs range per boe is approximately $16.25 - $18.50.

2. Operating Costs are based on flat $40 per barrel WTI crude oil and $4 per Mcfe natural gas price levels for 2009. Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices. Based on the expectations for commodity prices above, operating costs are expected to decline throughout the year and are generally expected to be approximately 20% higher in the first quarter of 2009 as compared to the fourth quarter of 2009.

3. Going forward, the Partnership will classify as operating expenses certain costs related to field/regional operations that were previously categorized as General and Administrative expenses. This approach is consistent with industry practice and with the treatment of these expenses by the prior operator of our largest group of assets. Operating costs now include approximately $10.1 million of these expenses with a corresponding reduction to General and Administrative expense.

4. Due to the timing of certain audit, tax, legal, severance, advisory and other professional services being performed for the Partnership, the Partnership estimates that approximately 55% of the projected annual general and administrative expense should be incurred in the first half of 2009. While the Partnership anticipates that a significant portion of the expenses related to litigation against the Partnership brought by Quicksilver Resources will be covered by insurance, General and Administrative expenses shown here do not include any expense which may be incurred by the Partnership in defending itself from Quicksilver's actions not covered by insurance.

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 2% and includes the impact of interest rate swaps covering approximately $400 million of borrowings at a weighted average swap rate of 3.57%. Our resulting estimated 2009 weighted average LIBOR rate is 2.93%.

6. Total Capital Expenditures assumes actual amounts budgeted to be spent in 2009 for Development and Mandatory capital expenditures.

7. Total Capital Expenditures for 2009 are less than historical and current estimates for Maintenance and Obligatory Capital Expenditures which we define 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 we would need to spend between $55 million and $60 million in 2009 to keep production flat.

8. Assuming the high and low range of our guidance, Adjusted EBITDA is expected to range between $178 million and $196 million, and is comprised of estimated net income between $278 million and $298 million, less unrealized gain on commodity derivative instruments and proceeds from hedge monetization of $256 million, plus DD&A of $122 million, plus interest expense between $32 million (high end of Adjusted EBITDA) and $34 million (low end of Adjusted EBITDA). Estimated 2009 net income is based on oil prices of $40 per barrel for WTI crude oil and $4 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.

Litigation Update

On October 31, 2008, Quicksilver Resources filed a lawsuit against the Partnership and other persons and entities, including several Directors of the Partnership. One of Quicksilver's primary claims is that the amendment to the Limited Partnership Agreement which was adopted by the Partnership in June of 2008, was improperly adopted. This amendment provides the limited partners with the new right to vote to elect members of the Board of Directors of the Partnership's general partner. Two seats on the Board of Directors are scheduled for election in 2009. Quicksilver originally asked for a hearing to seek a temporary injunction in early April of this year seeking to stop the election. At Quicksilver's request, this hearing was taken off calendar and the parties agreed with the Court to calendar a hearing on this issue beginning in late September of 2009. The Partnership agreed to schedule the Director election on November 30, 2009 with nominations for the two Directors seats to be made during September. A trial on the remaining issues is currently scheduled for early 2010. The Partnership continues to vigorously defend the lawsuit and believes that the allegations in the lawsuit are without merit. Unfortunately, the lawsuit diverts resources and manpower in the Partnership and has negative impacts on the Partnership's unit price and restricts the Partnership's flexibility in the market.

Conference Call

A teleconference and web cast to discuss this release and to respond to questions raised by industry analysts and institutional investors will be available to all interested parties beginning at 6:00 a.m. (Pacific Time) on Monday, April 20. Those wishing to participate in the conference call should call 1-800-289-0552(international callers dial 913-312-0691) a few minutes prior to register. A replay of the call will be available through Monday, April 27, by dialing 888-203-1112 (international callers dial 719-457-0820) and entering replay PIN 3282491.

Those wishing to participate in the live or archived web cast via the Internet should go to the Investor Relations tab of the BreitBurn website at http://ir.breitburn.com/.

Management to Present at 2009 IPAA OGIS Investor Conference in New York on April 21

The Partnership's management will present at the 2009 IPAA Oil & Gas Investment Symposium (OGIS) investor conference in New York at 4:10 p.m. Eastern Time on Tuesday, April 21, in the Empire East Room of the Sheraton New York Hotel & Towers. Those wishing to participate in the live or archived web cast via the Internet should visit BreitBurn's Investor Relations website at http://ir.breitburn.com/.

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. These producing and non-producing crude oil and natural gas reserves are located in the Antrim Shale in Michigan, the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming, the Sunniland Trend in Florida, the Permian Basin in West Texas, and the New Albany Shale in Indiana and Kentucky. See www.BreitBurn.com for more information.

Cautionary Statement Relevant to Forward-Looking Information

This press release contains forward-looking statements relating to BreitBurn's operations that are based on management's current expectations, estimates and projections about its operations. Words and phrases such as "anticipates," "expects," "believes," "estimates," "review," "future," "goals," "temporarily," "in the event," "impact," "guidance," 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. 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, BreitBurn undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: inaccuracies in the estimated timing and amount of future production of oil and natural gas due to numerous factors including permit delays or restrictions, weather, equipment failures, delays or lack of availability, unexpected subsurface or geologic conditions, lack of capital, increases in the costs of rented or contracted equipment, increases in labor costs, volumes of oil or gas greater or lesser than anticipated, and changes in applicable regulations and laws; unexpected problems with wells or other equipment, particularly in our Florida properties where production is concentrated in relatively few wells; the uncertainty related to the litigation instituted by Quicksilver against us; unexpected changes in operating costs and other expenses, including utilities, labor, transportation, well and oil field services, taxes, permit fees, regulatory compliance and other costs of operation; further decreases in oil and natural gas prices, including price discounts and basis differentials; difficulties in accurately estimating the discovery, volumes, development potential and replacement of oil and natural gas reserves; the impact of the current financial crisis on our business operations, financial condition and ability to raise capital; variances in cash flow, liquidity and financial position; a further significant reduction in our credit facility's borrowing base; availability of funds from the capital markets and under our credit facility; our level of indebtedness; the ability of financial counterparties to perform or fulfill their obligations under existing agreements; a further write down of our asset carrying values and field impairment; the discovery of previously unknown environmental issues; changes in business and financial strategy; inaccuracies in estimating the amount, nature and timing of capital expenditures, including future development costs; the inability to predict the availability and terms of capital; issues with marketing of oil and natural gas including lack of access to markets, changes in pipeline and transportation tariffs and costs, increases in minimum sales quality standards for oil or natural gas, changes in the supply-demand status of oil or gas in a given market area, and the introduction of increased quantities of oil or natural gas into a given area due to new discoveries or new delivery systems; the impact of weather limiting or damaging operations and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters; the competitiveness of alternate energy sources or product substitutes; technological developments; changes in governmental regulation of the oil and natural gas industry potentially leading to increased costs and limited development opportunities; developments in oil-producing and natural gas-producing countries potentially having significant effects on the price of oil and gas; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; inability to execute strategic plans, expectations and objectives for future operations; and the factors set forth under the heading "Risk Factors" incorporated by reference from our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements.

Non-GAAP Financial Measures

This press release, and other supplement 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 "cash flow". These non-GAAP financial measures 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.

Adjusted EBITDA and cash flow are presented as management believes they provide additional information and metrics relative to the performance of the Partnership's business as well as our ability to meet our debt covenant compliance tests. Adjusted EBITDA and cash flow 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 and cash flow in the same manner.

BBEP-IR

SOURCE: BreitBurn Energy Partners L.P.

BreitBurn Energy Partners L.P.
James G. Jackson, 213-225-5900 ext. 273
Executive Vice President and Chief Financial Officer
or
Ruder Finn/West
Pierre Hirsch, 415-692-3060

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